Portland General Electric Company (NYSE:POR) Q1 2026 Earnings Call Transcript

Portland General Electric Company (NYSE:POR) Q1 2026 Earnings Call Transcript May 1, 2026

Portland General Electric Company misses on earnings expectations. Reported EPS is $0.58 EPS, expectations were $0.767.

Operator: Good morning, everyone, and welcome to today’s conference call with Portland General Electric Company. Today is Friday, 05/01/2026. This call is being recorded, and all lines have been placed on mute to prevent background noise. After the speakers’ remarks, there will be a question-and-answer period. If you would like to ask a question during this period, press star then the numbers 11 on your telephone keypad. 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 Company’s Senior Manager of Investor Relations. Investor Relations Executive, you may begin.

Investor Relations Executive: Thank you, Towanda. Good morning, everyone, and thank you for joining us today. Before we begin, I would like to remind you that we issued a press release this morning and have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The press release and slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause actual results to differ materially, please refer to our press release and our most recent periodic reports on Forms 10-K and 10-Q, which are available on our website.

Turning to Slide 3, leading our discussion today are Maria MacGregor Pope, President and CEO, and Joseph R. Trpik, Senior Vice President of Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now I will turn things over to Maria.

Maria MacGregor Pope: Good morning. Thank you, Erin. Thank you all for joining us today. The first quarter delivered another stretch of warm winter weather, 10% year-over-year industrial customer demand growth, and continued maturity of our cost management initiatives. Beginning with Slide 4, I will speak to our financial results and key drivers. For the first quarter, we reported GAAP net income of $45 million, or $0.38 per diluted share, and non-GAAP net income of $68 million, or $0.58 per diluted share. Our non-GAAP results exclude the previously disclosed deferral adjustments related to the January 2024 storm restoration and reliability contingency event, and business transformation, optimization, and acquisition expenses.

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

On recent calls, you have heard us highlight the company-wide work to optimize our cost structure. We are using our operational strength, which we have built over multiple years, to mitigate the impact of recent weather challenges by accelerating our cost management work. Our teams are squarely undertaking the challenge, and we are committed to delivering strong results. As such, we are reiterating our full-year earnings guidance of $3.33 to $3.53 per diluted share and our long-term earnings and dividend growth guidance of 5% to 7%. Turning to Slide 5 for updates on our five key strategic priorities. First, our teams made progress on the Washington acquisition and other key regulatory filings. In late March and early April, we filed applications with the Washington Utilities and Transportation Commission and the Oregon Public Utility Commission for approval of the Washington transaction.

We anticipate the regulatory approval process to take about a year and continue to target a mid-2027 close. Portland General Electric Company’s holding company proposal continues to advance. The docket’s procedural schedule has been modestly extended. To prioritize timely resolution of the holding company, we have paused the transmission company. That said, formation of a transmission company remains part of our long-term strategy. We appreciate the ongoing collaboration and expect to engage with parties in the near future. Having just received reply testimony late yesterday, many issues have been resolved with a few key items remaining. The process is on course, with a target final order date probably in August. Second, building upon our 2025 O&M cost management work, we continued driving efficiencies and improving productivity.

We are accelerating this work given the very warm winter weather and first quarter results. Importantly, our large load tariff proposal, UM 2377, is in the final stages of review with the OPUC, and we expect an order in the next several weeks. A transparent, predictable tariff for new and existing data centers strengthens protections for existing customers while supporting economic development in our region. Our proposed rate structure under consideration, enabled by Oregon’s recent legislation, includes a 26% increase in data center prices, which will help reduce the costs borne by residential and small business customers. Third, as I noted, industrial demand growth is accelerating in our service area. We foresee robust energy usage from data centers and high-tech customers, with large customer capacity growing by about 10% compounded annually through 2030.

This growth forecast is driven by existing customers and contracts already executed with new customers—companies that own property and have civil work underway. Compared to Q1 last year, our data center customer load grew by 10%. Fourth, progress continues toward additional clean energy resource procurement. We filed our 2025 RFP shortlist with the OPUC in February, as we aim to procure approximately 2,500 megawatts. The shortlist is composed of a diverse mix of projects and technologies to support our existing portfolio and growing customer demand. We look forward to working collaboratively with stakeholders to achieve commission acknowledgment in the coming months. And fifth, our year-round, risk-based wildfire mitigation work remains on track as we prepare for the summer months.

In parallel, regulators and policymakers are engaged in this critical topic. The OPUC, in coordination with the Oregon Department of Energy, has hired experts on wildfire liability policy options that balance customer needs for essential services, support for wildfire victims, and financial health of utility companies. We expect the study’s findings will help inform policymakers in advance of the 2027 legislative session. In December, we filed our 2026 through 2028 wildfire mitigation plan, which represents a significant evolution, moving from an annual update to a forward-looking, three-year strategic framework. As we progress through 2026, our focus continues to be on executing on our core priorities: solid operational performance, meeting growing energy demands, expanding into Washington State, and advancing customer-driven clean energy investments.

With the first quarter behind us, opportunities are significant. We are focused on achieving solid financial results and delivering value for customers, communities, and shareholders. With that, I will turn it over to Joseph R. Trpik.

Joseph R. Trpik: Thank you, Maria, and good morning, everyone. Turning to Slide 6, our Q1 results reflect strong energy demand from our industrial customers and ongoing system investments. Total Q1 2026 loads were flat as compared to Q1 2025, and changes in demand between our customer classes were largely offsetting. Industrial demand increased 10% on a nominal and weather-adjusted basis. The industrial customer class is expected to continue growing at a strong pace, highlighting the strength of our large customer pipeline and the attractiveness of our service area to data centers and high-tech customers. Commercial load decreased 2.9%, or 2.3% weather-adjusted, and residential load decreased 6.2%, or 4.6% weather-adjusted. Portland General Electric Company has seen seasonal shifts in residential and small commercial average usage in recent years with rooftop solar adoption and energy efficiency growth.

While not considered in our 2026 plan, deviations of this magnitude are not unprecedented, and we are adapting to manage through this. Historically, demand has been winter peaking, but our region has been transitioning to a dual peaking profile with customers increasing their cooling demand as air conditioning becomes more widespread in our region. After considering the recent trends in customer usage, we now anticipate weather-adjusted load growth of 1.5% to 2.5% this year. In the last twelve months, our organization has evolved tremendously in the ability to adapt through cost management. We have a well-defined plan in place for the balance of the year to solve for the load impacts experienced this quarter, which I will discuss shortly. Now I will cover our quarter-over-quarter earnings drivers.

We experienced a $0.07 increase in retail revenues, including a $0.09 increase from additional cost recovery, largely from the inclusion of our Seaside battery asset in customer rates beginning in November 2025; a $0.09 increase driven by higher industrial demand, offset by $0.11 due to lower residential demand; a decrease from power costs of $0.15 driven by $0.09 from power cost performance in 2025 that reverses for this comparison, and $0.06 from current-year power cost performance driven by less favorable wholesale and environmental credit market conditions; a $0.16 decrease from capital and financing costs in support of our ongoing rate base investments, made up of $0.10 of higher depreciation and amortization, $0.05 of dilution, and $0.01 of additional interest cost; a $0.09 decrease from other items, primarily the timing of tax credits and O&M costs; $0.10 from deferral reductions related to the January 2024 storm and reliability contingency event reflecting the outcome of the final OPUC order received in March; and a $0.10 decrease from business transformation, optimization expenses, and acquisition costs.

This brings us to our GAAP EPS of $0.38 per diluted share. After adjusting for the 2024 regulatory disallowance and our business transformation expense, we reach our Q1 2026 non-GAAP EPS of $0.58 per diluted share. On to Slide 7 for our five-year capital forecast, which includes 2026 and 2027 spend for the incoming 2023 RFP projects. I will note this view does not contemplate CapEx from the ongoing 2025 RFP. For the Washington utility business, given our ongoing investment in critical systems and assets serving our customers and other policy priorities, we remain engaged with stakeholders as we consider our next regulatory steps. We will keep you informed as this progresses in line with our usual practice. On to Slide 8 for liquidity and financing summary.

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

Lastly, in April, the board of directors declared a quarterly common stock dividend of $0.55125 per share, representing an increase of 5% on an annualized basis. We remain committed to paying a competitive dividend in line with our 60% to 70% payout target while balancing overall financing needs. Our plan focuses on maintaining strong operating cash flows while supporting continued investments in customer-focused capital projects, all while advancing us towards our authorized capital structure. As Maria and I have mentioned, our teams remain focused on advancing key priorities for the balance of the year. Most notable is our deployment of incremental cost management measures to offset load impacts on 2026 earnings to date. Relative to our plan, Q1 was $0.25 below our expectations.

While $0.09 is driven by timing, we will address the remainder through refining our capital and maintenance work streams, optimizing our team, equipment, and facilities management, and positioning our power portfolio and generation fleet to deliver optimal value. We are confident that these cost savings measures are achievable, especially when considering the $25 million we saved last year, our existing momentum built into our 2026 plan, and the opportunity to accelerate what was planned for 2027 into this year. As such, we are reaffirming our long-term earnings and dividend growth guidance of 5% to 7% and our full-year adjusted earnings guidance of $3.33 to $3.53 per diluted share. We remain focused on safe, reliable, and efficient operations, advancing our strategic priorities, and achieving our commitments to deliver value to our customers, communities, and shareholders.

And now, Operator, we are ready for questions.

Q&A Session

Operator: We will now open the call for questions. As a reminder, to ask a question, press star then 11, then wait for your name to be announced. To withdraw your question, please press 11 again. Our first question comes from the line of Julien Dumoulin-Smith with Jefferies. Good morning, Julien.

Julien Dumoulin-Smith: Hey, good morning, Maria. Thanks, Operator. Thanks, everyone. It is nice to chat. If we can start off here a little bit more on the negotiations and conversations on the holdco side. What are the key areas of contention that prevented a settlement here? And particularly now that you have removed the transco from the filing, how do you think about prospects from here given how perhaps the two became at times a little overly intertwined?

Maria MacGregor Pope: Sure. Well, first of all, thanks, Julien. With regards to the holding company, we are really encouraged that parties have been meeting together to align thinking to further the process. We just received testimony yesterday, and we have agreed upon some funds and general provisions around ring-fencing, including commission oversight and access to books and records, and other things. Obviously, we still remain pretty far apart with regards to credit, the use of leverage, and other such things, and we look forward to engaging with stakeholders as well as commission staff. This is all part of the process, and as you can see, there are a lot of different concepts and history brought up in the filing that was just published yesterday.

Julien Dumoulin-Smith: And then if I can follow up real quickly here just around the year itself. Obviously there have been some gyrations here, especially with starting the year. Can you talk about the levers a little bit more—in the context of the remainder of the year and the offsets, if you will, against the full-year number? I know the load number was moving to start the year with Q1. You reaffirmed 2026, but can you speak a little bit to the levers going into that?

Joseph R. Trpik: Sure. Good morning as well. Our cost management program has always been designed as a multiyear plan. We achieved and slightly exceeded our goals last year, which gave us a foundation to build off to have levers, tools, and items in place to react to situations like this. Part of the plan overall was to mature the organization to give us flexibility when situations like this occur. One of the things we are doing is taking advantage of the fact this is a multiyear plan. This plan was intended to extend beyond 2026, so we had already been working and identifying levers and benefits for this year, but also items for next year. We have had the ability to look into our toolkit of actions. In addition, we are realigning based on what we are now seeing as the pattern of performance to set the portfolio up to really optimize itself.

We have the ability on both sides—how we plan and adapt our energy portfolio, and how we plan and adapt our costs, working throughout the whole management team and organization. This process has already been in place. We have already been working this because the goal has always been transformation. We feel confident that, as we look to our toolkit and identify the gap, we have the ability to execute things well within our control since this work had already been underway; it is really just steering it a little differently and giving it a little more momentum.

Julien Dumoulin-Smith: And, Maria, just to clarify the earlier comment you made—at this point, do you expect any further settlement conversations on either the holdco or transco? I heard your comment about remaining pretty far apart on some of these key issues.

Maria MacGregor Pope: No, the process still allows for settlement conversations, and we are engaging with parties and working through the issues.

Operator: Thank you. Our next question comes from the line of Shahriar Pourreza with Wells Fargo Securities.

Analyst: Hi, Shah. Good morning, team. This is Whitney Motilema on for Shah. Thinking broadly on recovery tools, with the RCE mechanism no longer available, how are you thinking about the path to future reliability-related costs in a way that remains timely and investable? Should we assume the fallback is simply broader GRC treatment, or are there other tools you think Oregon could still support for event-driven cost recovery?

Maria MacGregor Pope: First of all, an excellent question. Over time, you are absolutely right—we are engaging with regulators to work on removing the volatility and generating more predictability both on the impact to energy usage from weather, as well as other issues. Obviously, the RCE was around significant events, and of course we have more volatility to power costs and exposure. Clearly something that is going to take some time, and it is really important.

Analyst: Thank you. And then just as a follow-up, as it relates to multiyear rate planning, obviously Portland General Electric Company is supportive of Oregon’s transition. But staff has been arguing for just the transition framework, and the company finds it restrictive. As Oregon moves into multiyear rate plans, what is the main principle Portland General Electric Company is trying to protect—is it the ability to retain the existing statutory tools during this transition, or the ability to continue using narrower mechanisms for high-priority capital without needing a full rate case?

Maria MacGregor Pope: It is a good question. There is no question that we need to work on a common understanding of what is needed for all stakeholders, particularly investors, and tools that will provide for adequate capital recovery and other interim items as we move to the multiyear framework. I think, as we saw from the testimony that was just issued yesterday, we have a lot of work to do around common understanding of how we will attract and retain capital and continue to grow the utility to invest for customers in clean energy, reliability, and customer growth.

Joseph R. Trpik: And just to add, there is a collection of new tools that are needed both in the transition and also in the multiyear plan. We have already been adapting to those. You saw those new tools, in all honesty, with the Seaside tracker as well as the DSP that have taken some time to work through. We are all working to evolve from what was a very traditional process to both a multiyear process and how to find your way to that multiyear process. The dialogue with the Commission is really about what type of tools we need, understanding that they are new, which is why this takes a bit of time—to make sure they work well for all parties involved.

Operator: Our next question comes from the line of Christopher Ronald Ellinghaus with Siebert Williams Shank. Your line is open.

Christopher Ronald Ellinghaus: Good morning, everybody. Maria, can you talk about what you are seeing in the Oregon economy? It has been struggling a little bit—are you seeing some recovery? And as an adjunct to that, customer growth year over year was a little lighter than the first quarter of last year. Is that part of that issue, or are there some other factors at play?

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

Joseph R. Trpik: If I could add on load patterns, we saw a combination of warm months and some unusual flows of weather even within the month. We asked ourselves—similar to you—whether other economic conditions were at play, but what we are really seeing are items reacting to an unusual set of weather patterns. We had one of the warmest winters and it was a little sunnier, so you got a little more solar penetration than you normally would have seen in the winter months. To Maria’s comment, the broad economic factors that guide our view of longer-term load continue to hold and be consistent.

Christopher Ronald Ellinghaus: In the reduction to the 2026 load expectations, is that merely a Q1 adjustment, or are there other factors incorporated?

Joseph R. Trpik: On an overall basis, we believe we largely realized the main heating-driven part of the load reduction in Q1. We have reshaped the remainder of the year, but the reshaping is movements between the other quarters. From a loads experience, we think we have worked through the unusual part of the year on a cumulative basis and then expect some slightly different flows as we see differing customer reactions to heat and cold. But overall, net should be relatively close to zero rest-of-year.

Christopher Ronald Ellinghaus: Maria, you were talking about pursuing a mechanism for volatility. The region is supposed to be on the warmer side for spring and into the summer. Do you think that effect on consumers will inspire intervenors to pursue that mechanism discussion a little more?

Maria MacGregor Pope: It is a good question. Last year, we began to see the impacts of significantly higher AC penetration, and we saw higher load growth without as much high temperature as one would have historically needed. So there is definitely more correlation to high temperatures in terms of energy usage, which is a positive going forward for us. We have not factored that into our forecast—we are relying on those things that are actionable. Regarding the Commission and how they might think of this, affordability is a priority and predictability for customers is important. I have had conversations with the Chair regarding these unique patterns we are seeing, and those conversations with the commissioners and staff will be ongoing.

Christopher Ronald Ellinghaus: A couple of related questions on the holdco. One, can we infer from the transco retreat that while you did not come up with an official settlement, you have resolved some issues unofficially through that process? And second, references to historical events are not surprising—they were very sensitive about ring-fencing and credit back in the day. The holdco is a different animal than some of those events—does the Commission staff appreciate the significant differences despite bringing them up again?

Maria MacGregor Pope: First, with regard to the transmission company, our goal was to prioritize at the request of staff and commissioners. We are trying to be mindful of their workload and make sure we are focused on the highest-priority items. The transmission company remains a topic that we will continue to discuss in the future, but not at this time. The testimony shows we have common ground on a number of items. I would agree with you that some of the written words in the testimony show we have more work to do—collaborate and establish common understanding and the “why” and drivers, as well as utility practices across the country that are pretty standard. The next step is to engage directly and continue the conversation.

Operator: Our next question comes from the line of Analyst with JPMorgan. Good morning.

Analyst: Good morning. Thanks for the time today. With the applications in Oregon and Washington now underway, could you speak to the initial feedback from stakeholders on the pending acquisition, the upcoming milestones we should watch for, and any sense of what customer benefits you are highlighting for the commissions at this time?

Maria MacGregor Pope: We have engaged with a wide variety of stakeholders. We have spoken with all of the commissioners and staff in Oregon and multiple times with the commissioners in Washington, as well as staff and the respective governor’s offices. Importantly, we have spent time in the service territory and are encouraged by the receptivity, the focus on economic development, and the interest in our ability to serve current and new businesses in the Walla Walla, Wallula, and Yakima regions. In terms of discussions on benefits, we are at the very early stages, but I would say, in particular for Washington, it is a constructive, business-focused environment. We look forward to engaging with all stakeholders as we move forward.

Analyst: Thanks. On the regulatory front, could you speak to the timing of your next GRC as we get closer to your stay-out expiring this summer? What are the factors that would cause you to file earlier or later?

Maria MacGregor Pope: We are spending a lot of time talking about that issue and focusing on our timing. We know that energy bills are incredibly important to all businesses and families, and we are working to keep customer bills as low as possible by delivering reliable services that customers can count on. We have not decided on the next timing of our rate case, but it will probably be sometime in the second half of the year. We are still evaluating the major components.

Operator: Our next question comes from the line of Gregg Gillander Orrill with UBS. Your line is open.

Gregg Gillander Orrill: When would you be in a position to include the 2025 RFP into the CapEx plan?

Joseph R. Trpik: Morning, Greg. As a reminder, we include RFPs in the plan once we have them under contract. We think the earliest we will start to see contracts is the beginning of 2027 if things proceed in the normal course as we work through these projects. We would like to have it aligned with our fourth-quarter update, but as you know, we are working with a collection of counterparties and a series of negotiations that can vary.

Operator: Thank you. Please stand by for our next question. Our next question comes from the line of Paul Fremont with Ladenburg Thalmann & Company. Your line is open. Morning, Paul.

Paul Fremont: Good morning. Thank you very much. First, should we think about the prospects for settlement being best between now and when hearings are scheduled in early June?

Maria MacGregor Pope: I hope so—the sooner we can settle, the better. But I want to make sure we give all parties adequate time to establish good understanding and be able to move forward constructively.

Paul Fremont: In most states, if it is going to settle, it usually settles before hearings. Is that the case in Oregon, or would you expect prospects to be just as good after hearings?

Maria MacGregor Pope: I would not hedge either side. We are going to continue the process just as we have in the past. Hopefully we can come to settlements, and if not, we will go to the hearings and then work towards settlements afterwards. We have plenty of runway to engage ahead of hearings, and we are always hopeful of settling sooner rather than later.

Paul Fremont: In the past, you have expressed a high level of confidence in your ability to settle this particular case. Is that unchanged, given your comments earlier that the parties still remain pretty far apart?

Maria MacGregor Pope: We still have good expectations of being able to settle, and I would reiterate that we have put a number of issues behind us as we work through the process.

Paul Fremont: Have you received the counterproposal referenced in your regulatory filing from intervener parties? It sounds like even if you did receive one, there are still major issues to be resolved.

Maria MacGregor Pope: We have not. The parties are working on that, and we are continuing the discussions.

Paul Fremont: It looks as if the Washington utility subsidiary of Berkshire may not be earning at levels close to their authorized return levels. Is there something you plan on doing to narrow the gap between what they are earning and what they are authorized to earn?

Maria MacGregor Pope: As we move into Washington and look at the opportunities in the state, first, it is a strong operational fit with operations that we know well. We have noted that we expect the transaction to be accretive in the first year and to enhance our long-term EPS growth and dividend growth. Much of that is driven by new investment, particularly clean energy investments supporting CETA compliance obligations. The commissioners have continued to reiterate that. We would expect to drive to a similar return profile in Washington as we have in Oregon—or better.

Joseph R. Trpik: The historical gap we have seen has been mainly related to power costs. One attribute of this transaction is much more specific and transparent direction of costs for Washington customers. Having a clearer Washington utility with a more specific, instead of allocated, set of assets and costs will drive to more effective recovery over time.

Paul Fremont: So it is not through merger synergies that you would expect improvement?

Joseph R. Trpik: Today, when we speak to the accretive nature of this transaction on the front end and getting better recovery, this is about execution of the plan, execution of costs, and operation of the utility. We have not layered in any type of cost synergy. We have layered in effective operations and financing and other benefits. Synergies we will work to, but we are not counting on those to make this accretive.

Maria MacGregor Pope: There absolutely will be synergies on the O&M side and on the procurement side.

Operator: Our next question comes from the line of Travis Miller with Morningstar. Your line is open.

Travis Miller: Good morning. Thank you. Two quick ones and then a follow-up. First, the 26% increase in the data center prices you talked about through the tariff—are those for all existing and prospective customers, or just for prospective data centers?

Maria MacGregor Pope: Those are for existing and new customers—all data center customers. We worked very collaboratively with each of those customers, and there are no surprises.

Travis Miller: Second quick one, the generation mix—Q1 last year to Q1 this year—some changes there in terms of your own generation versus purchased. Was this weather-driven, or is there something fundamental going on?

Joseph R. Trpik: There is no strategic change. It is a combination of events: weather, energy pricing related to running assets, and certain contracts that roll on and off. You will see a contract rolled on under the contracted section. Overall, our strategy on how we manage the portfolio and the mix of owned versus contracted stays the same—these are normal ebbs and flows.

Travis Miller: Higher-level question: the E3 report that came out in the last couple of days talked about a 9 gigawatt shortfall by 2030 and a 14 to 18 gigawatt shortfall by 2035, particularly along the Western edge of the region. Were you involved in the report, and are these numbers consistent with what you are seeing and reporting to regulators?

Maria MacGregor Pope: The report was commissioned on behalf of industry groups that we participate in and know well across the Pacific Northwest. As you can see through our 2025 RFP and our IRP, we are working to procure more energy than we have in the past, and others in the region are doing the same. The report focused on resource adequacy and how we better manage it as a region. It includes additional focus on transmission. Entering the day-ahead market and building upon our energy imbalance market will improve outcomes for Portland General Electric Company, as well as PacifiCorp, which just went live with the day-ahead market today. We appreciate the information—it has created constructive regional discussions.

Operator: Our next question comes from the line of Analyst with Mizuho. Your line is open.

Analyst: Hi. Good morning. This is Rugia from Mizuho for Anthony Christopher Crowdell. You have talked about the Washington acquisition as an opportunity to bring a growth-oriented philosophy to a service territory that has historically been more maintenance-focused. Can you walk us through what that looks like in the first 12 to 18 months after you take over? Specifically, what areas would you bring this growth initiative to, and what would be early signs that the shift is taking hold?

Joseph R. Trpik: Good morning, Rugia. In the shorter term, this is about supporting and giving the right investment mainly on the distribution side, and a little bit on transmission, to continue building infrastructure at the rate needed to support growth. The longer-term growth will come from RFPs we will be involved in and supporting economic growth and development in a region we believe is primed for it. That is why, if you look to the charts we show related to inclusion of the Washington utility, you will see the growth is a little more back-end focused as we support some industrial growth and RFP needs in the area.

Maria MacGregor Pope: We are really encouraged by regional leaders’ interest in accelerating growth in Eastern Washington, and I have had terrific conversations with our existing customers as well as new potential customers.

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

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

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