Portland General Electric Company (NYSE:POR) Q4 2024 Earnings Call Transcript

Portland General Electric Company (NYSE:POR) Q4 2024 Earnings Call Transcript February 14, 2025

Portland General Electric Company beats earnings expectations. Reported EPS is $0.34, expectations were $0.33.

Nick White – Manager, IR:

Maria Pope – President and CEO:

Joe Trpik – SVP, Finance and CFO:

Julien Dumoulin-Smith – Jefferies:

Richard Sunderland – JPMorgan Securities:

Shar Pourreza – Guggenheim Partners:

Michael Lonegan – Evercore ISI:

Nicholas Campanella – Barclays:

Anthony Crowdell – Mizuho:

Paul Fremont – Ladenburg Thalmann & Co. :

Travis Miller – Morningstar:

Operator: Good morning, everyone, and welcome to Portland General Electric Company’s Fourth Quarter and Full Year 2024 Earnings Results Conference Call. Today is Friday, February 14th, 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. [Operator Instructions] For opening remarks, I will turn the conference call over to Portland General Electric Manager of Investor Relations, Nick White. Please go ahead, sir.

Nick White: Thank you, Martin. Good morning, everyone. We’re happy you could 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 will be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause actual results to differ materially, please refer to our earnings press release and our most recent periodic reports on Forms 10-K and 10-Q, which are available on our website.

Turning to Slide 3, leading our discussion today are Maria Pope, President and CEO, and Joe Tripik, Senior Vice President of Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now it is my pleasure to turn the call over to Maria.

Maria Pope: Good morning, and thank you all for joining us today. In 2024, we experienced solid growth from new and returning customers, enhanced our operational reliability and resilience, achieved strong safety performance, and made significant investments in clean energy resources and battery storage. We delivered four quarters of strong financial results, and overall a solid 2024. I’ll start by summarizing our results, which you can find on Slide 4. For the full year, we reported GAAP net income of $313 million or $3.01 per diluted share and non-GAAP net income of $327 million or $3.14 per share. This compares with 2023 GAAP net income of $228 million or $2.33 per share. Non-GAAP net income of — excuse me, $233 million or $2.38 per share.

For the fourth quarter, we reported GAAP net income of $39 million or $0.36 per share compared to the fourth quarter of 2023 of $68 million or $0.67 per share. These results reflect our sustained growth on — and focus on operational excellence and top quartile customer demand. 2024 weather-adjusted energy usage increased 3% compared with 2023, again, led by semiconductor manufacturing and data center customers, driving industrial growth of 11% year-over-year. With high tech and digital customers continuing to invest and grow, we are increasing our long-term customer usage growth expectations from 2% up to 3%, weather-adjusted through 2029. Given these solid fundamentals and our focus on operating cost reductions, we’re issuing 2025 earnings guidance of $3.13 to $3.33 per diluted share and reiterating our long-term dividend and EPS growth guidance of 5% to 7%, using a base of $3.08 per share, the midpoint of our original 2024 guidance.

Turning to Slide 5. Execution was our imperative as we began 2024. While January last year started with historic winter ice storms that brought nearly 0.5 million customer outages and extreme power market volatility, the extraordinary response of our line crews generating plants and operating teams highlighted our ability to respond and our focus on customer outage restoration. We had many significant accomplishments in 2024, including investing in our system deploying over $1.2 billion in capital projects, targeting customer growth, grid resiliency and decarbonization, advancing the 2023 RFP, receiving acknowledgment of the final shortlist from the Oregon Public Utility Commission and starting negotiations with bidders. Returning customers to cost of service.

In 2024, we earned back two prominent customers and their 27 megawatts of demand among others and delivering solid results, achieving earnings in the upper quartile of our original guidance range. To build on our progress, we remain committed to five key priorities: first, enabling tech — high-tech growth, strong industrial growth and in-migration made PGE an important part of our region’s economic development. Second, customer values, sustainability and clean energy continue to be important customer values and in the region. Third, customer affordability. We’re looking at every cost and every program to keep them as low as possible and to align the economics of our most recent rate case. And fourth, risk reduction. We are prioritizing the safety of our teams and the compliance of our work while investing in stronger more resilient grid to better withstand extreme weather and mitigate against wildfire risk.

At the Oregon legislature, we are advocating for wildfire legislation. And fifth, creating an investable energy future for Oregon. We’re deepening our relationships with customers and stakeholders to ensure that our returns are competitive, that we can effectively attract investments to achieve these priorities. I’ll touch on each of these before returning it to Joe. Enabling growth. We are fortunate to be one of the top growth markets in the country for data centers and semiconductor manufacturers. Proximity to the transpacific subsea fiber network, which terminates that our service territory remains a key differentiator. In addition to the growth of data centers, Oregon continues to be strongly supportive of our region’s semiconductor manufacturing, the state is providing $500 million in funding on top of billions of dollars already contracted federal funding to accelerate onshoring and reshoring of tech manufacturing.

Second, our customers and the communities we serve remain solidly focused on renewable energy. Clean energy represented 45% of our energy mix in 2024, a 7% compounded growth rate in non-emitting resources since 2020. As we made continued progress towards PGE’s and Oregon’s clean energy goals. Our region’s focus on clean energy has always balanced affordability. Many of our largest industrial customers have aggressive sustainability goals and our municipal customers representing the majority of our service area also a very public clean energy targets. Our residential customers continue to lead in the energy transition with PGE’s voluntary renewable program again ranked number 1 by NREL and this year, Oregon ranked as the number 6 electric vehicle market in the country.

Integrating the Clearwater Wind Energy Center led to record wind integration in 2024. We also added significant battery storage, including the incoming 200-megawatt seaside battery, PGE will soon have over 500 megawatts of battery capacity, providing a vital tool for renewable integration, system reliability and energy price stability. These resources were meaningfully lowering cost for customers, thanks to over 30% battery investment tax credit as well as wind production tax credits. In prior quarters, I’ve highlighted our success with several grants and as of December 2024, over $300 million of direct PGE grants were under contract. Combined with our grant partners, our total exceeds $2 billion. Customer affordability. We’re taking significant company-wide actions to reduce costs, align our cost structure to the economics of our latest rate review and enhance the effectiveness of our work.

In 2024, we leveraged innovation and technology to provide lapping efficiencies and benefits. For example, driving productivity with new AI-powered tools to streamline operations, improve load forecasting and predictive maintenance as well as employee support. In deploying satellite imaging for vegetation management and utilizing weather station data for wildfire monitoring to enhance Dynamic Line ratings help deployment across our transmission system. In 2025, we are realizing and evaluating programs that will maximize the capabilities of these and other technologies and diligently reducing our costs. We’re focused on changes that will drive durable long-term outcomes. Risk reduction. We made continued progress on our work to reduce risk across our business.

Our ongoing work to strengthen our safety culture is yielding results. On a compounded annual basis since 2020, our OSHA recordable incident rate has fallen by 16% and our lost time incident rate has decreased 27%. PGE’s energy portfolio optimization and improving Western market conditions led to a reduction in power cost volatility. We significantly increased routine vegetation management, addressing trees and other vegetation impacted by multiple years of record-setting high heat and drought. As we continue to drive operational improvements, we’re also advocating at the state and federal levels for solutions that address the financial risk from extreme weather events, including wildfires. At the state level, we’re focused on three areas: First, standards of care based on approved wildfire plants.

Second, creating a wildfire back step fund on to support timely resolution and recovery for wildfire victims. And third, limitations on liabilities. At the federal level, alongside peer utilities and EEI are advocating for policy solutions that enhance the energy security of the U.S. and address shared risk of catastrophic events. This work is focused on four areas: First, addressing strict liability and expediting permits and authorizations for work on federal lands. Second, enabling electric utility customers access to FEMA assistance. Third, federal liability reforms, and fourth, creating a voluntary federal backstop fund. Creating an investable energy future for Oregon. We’re deepening our relationships with customers and stakeholders to work towards competitive returns to attract capital and support the region’s need for growth-driven infrastructure development and reliable and resilient clean energy.

In December, we received a decision from the OPUC and our 2025 rate review. While the outcome was not unexpected, it is less than what we had strive for, but it does not distract us from our priorities or change the focus on managing our business. We remain laser-focused on affordability and committed to powering the region’s growth, safely and reliably serving the changing needs of customers. This has been our commitment for nearly 140 years and remain so. With that, let me turn it over to Joe. Thank you.

Joe Trpik: Thank you, Maria, and good morning, everyone. Turning to Slide 6. Our solid result reflects continued demand growth, improved power cost conditions and strong operational performance throughout the year. Overall, our region experienced milder weather compared to 2023 with heating degree days and cooling degree days declining 5% and 16%, respectively. 2024 loads increased by 1.3% overall and 3.1% weather adjusted compared to 2023, exceeding our 2% to 3% expectations. Residential load decreased 2.8% year-over-year but increased 0.5% weather-adjusted. Residential customer count increased by 1.7%, partially offset by energy efficiency and distribution energy resources, driving lower usage per customer. Commercial load decreased 2.2% year-over-year or 0.9% weather adjusted, driven largely by continued energy efficiency and the industrial class continued to experience significant growth in 2024, notably from our data center and semiconductor customers, industrial load growth increased 10.3% or 10.7% weather-adjusted from 2023.

I’ll now cover our financial performance year-over-year. We observed a $0.14 increase in revenues, primarily driven by the 1.3% increase in demand year-over-year, an increase in power cost to $0.68, driven by $0.04 increase due to power cost performance in 2023 that reverses per comparison and a 64% increase from favorable power cost conditions in our region and derisking actions taken by our team, which drove lower power costs than anticipated in our annual update tariff. Increased renewable and battery integration and hydro availability drove market stability and lower market prices through Q3. This was partially offset by less favorable market conditions than anticipated in the fourth quarter. A $0.04 decrease from higher O&M, depreciation and interest expenses, net of improved recovery and deferral related items, driven primarily by increased maintenance costs and wages and higher asset and debt balances to support the ongoing capital investment, a $0.02 decrease from other items, including higher property taxes, partially offset by returns on non-qualified benefit trust assets.

And then lastly, a $0.13 decrease to GAAP EPS resulting from the 20% portion of the non-recoverable January RCE costs, bringing us to a GAAP EPS of $3.01 per diluted share. After adjusting for the $0.13, we reach our 2024 non-GAAP EPS of $3.14 per diluted share. As a reminder, our results are subject to an earnings test due to the January storm damage cost deferral. This test was unique to 2024 and became applicable once we had a major storm deferral combined with third quarter performance that exceeded our original outlook. Last quarter, we highlighted a $0.11 decrease from the deferral release from the earnings test. After evaluating fourth quarter results, we ultimately reversed the deferral release and the deferred balance stands at $46 million at the — at year-end 2024.

Turning to Slide 7. For our updated five-year capital forecast through 2029. Our transmission investment strategy continues to evolve, focused on improving our network in alleviating congestion. 2027 through 2029 transmission projects include larger improvements within and adjacent to our service area as well as PGE’s estimated contributions to the Bethel Roundview line upgrade. The Constable battery project was placed in service in December, and the Seaside battery project remains on schedule to come online in the middle of 2025. In the 2025 rate review decision, PGE was invited to make a new filing to recover the investment inside battery project outside of a rate case with an expedited review. We are actively weighing our options available, and we will keep you informed of our regulatory strategy as we finalize our evaluation.

We received formal acknowledgment of the 2023 RFP short list in November. This is an evolving and competitive environment, and we were notified in December that Project 1 from Group A, the 250-megawatt PPA has withdrawn from commercial negotiations. Negotiations with the remaining projects in Group A are ongoing, and we expect build transfer agreements to be finalized in the second half of 2025. All projects have an estimated in-service date by the end of 2027. The OPUC encouraged PGE to promptly launch its next RFP to address remaining resource and capacity needs and preliminary filings for the 2025 RFP were made in November. We anticipate submitting an integrated resource plan update in the first half of 2025 as we move toward issuing the next RFP to market.

This filing will provide refined low growth expectations and the estimated resources needed from future RFPs to meet robust customer demand and advanced decarbonization. On to Slide 8 for a summary of liquidity and financing. Total available liquidity at year-end was $997 million. Our investment-grade credit rating, strong balance sheet and our outlook remains unchanged from our last disclosure. In the fourth quarter, we drew $119 million previously priced under our legacy ATM settling the full facility in support of our base capital plan. We also priced an additional $67 million under the new ATM, drawing $50 million during the quarter to derisk our longer-term financing plans and manage credit metrics. The residual amount priced under the facility was unissued at the end of December.

Our equity needs to support our base investment and strengthen our balance sheet remain unchanged at approximately $300 million per year in 2025 and 2026, tapering thereafter in 2027 and beyond. We also expect debt issuances throughout 2025 of up to $550 million focused on funding our capital expenditures. Our ongoing evaluation of facilities and structures that maximize our financing options will continue through the year, we remain focused on maintaining flexibility, managing our capital structure and credit ratings and providing strong customer value and accretion from rate base investments. Turning to Slide 9. 2024 was a strong year. Our teams executed in all four quarters, enabling us to deliver at the high end of both our near- and long-term earnings expectations.

With 2024 setting the foundation, we are initiating full year 2025 adjusted earnings guidance of $3.13 to $3.33 per diluted share. This guidance is supported by solid expectations of our service territory, including 2025 weather-adjusted load growth of 2.5% to 3.5%, highlighted by meaningful growth from our industrial customers. In prior quarters, I’ve highlighted our work to set the stage for consistent long-term performance, positioning leadership and building effective teams, thoughtful, focused planning that clarifies our objectives and a constant focus on executing our plan. We’re entering 2025 with a renewed emphasis on operating as efficiently and effectively as possible. Over the last eight weeks, we finalized alignment to the outcome of the 2025 rate review, making careful strategic choices to manage our business while still delivering on our expectations.

We expect 2025 O&M expenses of $795 million to $815 million, which includes $135 million of earnings neutral regulatory deferral amortizations, wildfire mitigation and vegetation management costs and other offsetting items. Our guidance reflects the initiation of sustained multiyear strategy to examine all activities into support serving our customers safely, reliably and efficiently, while still delivering on our financial commitments. This work will be intentional and deliberate and our entire team will play a critical role. We are calibrating our cost structure, configuring our teams and harnessing our tools and technology to enhance productivity and provide exceptional customer service. Our execution capabilities as well as the potential of our service territory also underpin our long-term optimism.

As Maria highlighted, we have updated our long-term demand growth guidance to 3% through 2029, and we’re also reaffirming our long-term dividend and earnings growth of 5% to 7%, now using the midpoint of our original 2024 adjusted earnings guidance of $3.08 per share. We remain confident in our fundamentals and focus on the milestones ahead in 2025, and we continue to improve and grow our business while staying centered on our core priorities, safely serving clean, reliable and affordable energy, while providing value to our communities, our customers and our shareholders. And now operator, we are ready for questions.

Q&A Session

Operator: [Operator Instructions] And our first question comes from the line of Julien Dumoulin-Smith of Jefferies. Your line is now open.

Julien Dumoulin-Smith : Good morning, team. Thank you guys very much for the time. I appreciate it. Nice to chat with you guys. Nicely done here. Top of the morning to you guys. Maybe just focusing first on the bigger priorities here. Obviously, you’ve got this wildfire effort here in front of you this coming year. And obviously, you’ve been building into this for some time. Can you speak maybe one, how the nature of what’s happening in California has maybe shifted or evolved any of the dialogues in the state? And then secondly, if you could frame how you envision this coming together and kind of a belt and suspenders approach, you obviously talk about creating sort of a wildfire backstop to our fund. How would that work as far as you’re concerned in an effort to try to draw analogs from California in a similar scope of what you would imagine coming out of this year looks like?

Just what are the conversations looking like at this time? Obviously, you’ve been spending your — spending quite some time building this together. What is that starting to look like in a more tangible set if you can?

Maria Pope: Great. So thank you, Julien. First of all, I want to just remind us that the wildfire work that we’re doing in the legislature at both the state and the federal level, really builds upon the work that we’ve been doing, as you noted, over multiple years at Portland General. We have a very advanced wildfire mitigation program. We filed our plans with the Oregon Public Utility Commission, our 2025 plan was filed at the end of December this year and really focuses on the hardening of our system, the prevention, the detection and the overall risk mitigation through power safety shutoffs as well as other programs. We are also working with the state legislation in three main areas. The first one is a standard of care based on the plans that I just talked about and the approval of those plans.

We work extensively with first responders and folks across the state as well as across the entire West who are experts in wildfire prevention in developing those. Second, the creation of a backstop fund to support the timely resolution and recovery for wildfire victims. But to do this, Julien, as we’ve learned in California, we have to have limitations on liabilities. That’s a really important aspect of any fund. And you can see that in the legislation that has already been passed in Utah and is being discussed in many other states. At the federal level, what’s happening in California has also catalyzed and focused on the need for further work. And there, we’re working to address and expedite permit authorizations to do work on federal lands.

And just to remind you, more than half of the state of Oregon is owned and managed by either the U.S. Forest Service or the Bureau of Land Management. Second, we’re enabling invest around utility electric customers to have access to FEMA assistance in any time of disaster. Third, that federal liability reforms and then for the creating a voluntary federal backstop, so there’s a lot of work going on, increased momentum and focus as we see some of the tragedies not only in Southern California, but in other parts of the country.

Julien Dumoulin-Smith: Got it. Excellent. And then maybe just to pivot more to the more tangible here on cost structure. Obviously, you’ve laid out some degree of detail here on your initiatives. And in some response, I imagine recognizing some of the feedback in the last quarter here. Can you elaborate a little bit on what you’re seeing out there in terms of relative rate lag? I mean how would you frame that this year in light of fee side and then more prospectively, given the higher sales growth in O&M, can you speak a little bit to kind of maybe more structural lag, if there’s any shifts in that as well as if there’s anything else that we should know about given some of the commentary around the case in O&M specifically in last quarter?

Maria Pope: So first of all, we are very fortunate to be in a part of the world that has tremendous growth. We’ve just increased, as Joe and I noted in our prepared comments, our long-term growth rate from 2% to 3%. This is really driven by semiconductor manufacturers’ data centers and the reshoring of regular manufacturing into our service area. We just had growth year-on-year of 11% of that sector, and that remains a key driver as we move forward. But equally as important is realigning our cost structure. Looking at all of the cost of how we do our work, ensuring that we are meeting our customers’ needs as efficiently and effectively as we can and also ensuring that our programs are all aligned with those outcomes. Let me let Joe talk with you a little bit about the extensive work that we’re going to be doing in 2025 around our cost structure.

Joe Trpik: Good morning, Julien. To your comment, part of what we’re doing in 2025 is to try to reduce that structural lag. As we realign to the rate case outcome, we’ve taken a really hard look honestly starting in 2020 — mid-2024 forward at how we work within our distribution ops, our IT functions, our digital tools, our support and really looking at realigning our cost structure here to continue to put what we’ll call downward pressure on that structural lag. I mean there are certain items when you deal with the short term within the rate case that create structural — some structural lag, but we’re really focused on this long-term compression of our performance against the regulatory recovery. So I mean that’s why you’ll see if you look to 2025, our earnings guidance range, you’ll see is lower than — the midpoint of that range is lower than our actual performance last year.

When adjusting for regulatory and other type of items, you see a pretty small relative increase that we’re expecting from our cost structure as we manage forward.

Maria Pope: So we made are committed to making up for the 16 basis points that we’ve seen in reduction and ensuring that we continue to deliver on our growth prospects.

Julien Dumoulin-Smith: Excellent. And that’s a lot. Kudos on the cost and good luck the session, speak soon.

Operator: Our next question comes from the line of Richard Sunderland of JPMorgan Securities. Your line is open.

Richard Sunderland : Good morning. Thank you for the time today. Picking up on the O&M dialogue from the last question. Just thinking about the durable long-term outcomes you referenced in the script, is there any way to sensitize this potential on a, say, three to five-year basis?

Joe Trpik: Sure. I mean, I think, Richard, to that, I mean, the way to sensitize understanding for us, you have to peel out some — there’s some regulatory spend like wildfire in that. I mean I would sensitize it that using our cost structure going forward, some relatively low single-digit growth rates off of what is the adjusted our 2025 range. I mean that is — our goal is to challenge our cost against inflation. But it’s important is what you laid out, this is about being methodical, it’s about durable. This isn’t about chasing any individual thing. It is about structurally changing how we do our work while continuing to safely effectively, reliably serve our customers and continue to improve on that. So I mean this is a — is a programmatic move as opposed to what I’ll call it, reactionary what we’re trying to do.

Richard Sunderland: Got it. That’s very clear. And then touching on overall regulatory strategy after the last rate case. How are you weighing the timing of another rate case, the Seaside options? And then I guess, against these O&M efforts as well. I know you said you were evaluating what to do with Seaside, but could you speak a little bit more to how you’re balancing those different considerations and when you might have an update across all of that?

Maria Pope: Sure. And Richard, we’re working through these issues of whether we focus on sea side is a single regulatory item or whether we take a more comprehensive approach to recover the battery storage project as well as other capital.

Richard Sunderland: Got it. Thank you.

Operator: Our next question comes from the line of Shar Pourreza of Guggenheim Partners. Your line is now open.

Shar Pourreza : Good morning. Just a real quick follow-up on Julien’s question. If there was some sort of a fund established would you be open at this point to structures that require equity contributions from the company? I couldn’t give a strong sense there?

Joe Trpik: Good morning, Shar. Joe Trpik. So I think the answer is yes. I think what’s critical to your openness comment is addressing standards of conduct framing the liability side of the equation. But I mean, we’ve taken in a bundle there, that — there’s value to that risk reduction, both for the customers and for others, and we think that would be a worthwhile investment. I think also it’s important you would expect something like that as an overtime kind of item.

Shar Pourreza: Got it. And then I just want to piece some of the data points that you guys were kind of touching on, but I’d like to just — I guess as you guys talk a little more on the plan, the different facets. I guess, where do you see yourself, I guess, trending within that 5% to 7% through the planning period? And any kind of considerations we should be thinking about from a year-over-year variability, what does the guidance that from a rate case timing? And then Joe, just specifically, I want to make sure I’m crystal clear. On the ’25 guide, do you assume you get the tracker for Seaside after the June completion? Thanks.

Joe Trpik: Yes. So overall, to your kind, where we sit in the range in that 5% to 7% range, and I think I’ve mentioned this before that in a year where we do not have meaningful investment in RFP. So take for example, right now, 2025 would really would spell that out. We would expect to be on the lower end of that range. To the extent that we have a period where we are modestly performing within the RFP, we would expect that we would push ourselves towards the higher end of that band. I think you can see that a little bit in the last couple of year cycles that we have. To your — specifically to your Seaside question, because the offer from the commission is somewhat unique at this expedited process for this battery, we had even though we have not decided what we’re going to do, we have designed a plan that does not include a recovery of Seaside because of its uncertainty.

So our cost management program, the structure that we are working through our guidance here assumes that we — a 0 for right now on Seaside, not because we’re not — to seek recovery, but just the uncertainty of it. And by the time you would have clarity on it, certainty would be relatively late. So planning with it in would might be probably too optimistic of what we’re doing. So we want to make sure that we have numbers we can execute on with or without it.

Shar Pourreza: Perfect. And then just real quick, lastly. With wildfire that process working itself through, any sense on timing, Joe, as far as the holding company structure, is it still — let’s get through the wildfire process and then we can look at the hold co. Is that this year kind of catalyst? Is it a next year catalyst, where are we in that process? Thanks.

Joe Trpik: So we continue to evaluate here, and we’re reading as the legislation starts to evolve, I mean, I think we’re taking a serious hard look on the time when we’ll address the whole call here. We think the having that action out there is important to drive financing flexibility for us to manage our costs for our customers. But I fully, we’re going to take some form of action this year. I think we’re down to just measuring months here. And we’d like to have a few more facts in front of us before we’re tight, but we think it is an important item to take a run at this year.

Shar Pourreza: Okay, perfect. Lot of good moving pieces. I appreciated guys. Thanks.

Operator: Our next question comes from the line of Mike Lonegan of Evercore ISI. Your line is open.

Michael Lonegan : Hi, good morning. Thanks for taking my question. So going back to the Seaside tractor, you said you’re still evaluating a potential filing. In the written order in the GRC, the commission mentioned that in order to grant you a tracker, they may want a commitment from you not to file a GRC for a certain period of time. I was just wondering your thoughts on committing to this and what kind of timeline you would commit to before the next rate case, if you were to make this tracker filing?

Maria Pope: So we have — that’s obviously out there as is the request by PUC staff to engage in discussions on multiyear regulatory solutions. And so we’re taking all of these things into consideration to hopefully end up with a more durable place for the company as well as for staff in PUC.

Michael Lonegan: Got it. Thank you. And then on the equity issuance plan, you reiterated $300 million in ’25 and ’26 and continue to mention tapering off in ’27 and beyond, consistent with your prior outlook. I know you’ve talked about monetization of renewable tax credits to mitigate needs. Just wondering, what are your latest thoughts on equity needs beyond ’26 and the FFO to debt metric you are targeting?

Joe Trpik: Yes. So as it relates to beyond ’26 exclusive of the RFP or some of the other equity items that we discussed here. We continue to have a focus to maintain our cap structure at about 50-50. If you take this capital plan for a few years after ’26, you get to — you have an equity plan that is relatively low to mid-hundreds understanding it rounds by year. But your initial focus here is to continue to maintain the strength of the balance sheet and then allow that strengthen the balance sheet to drive our credit ratings going forward. I mean we have commitments on budget size between just how one we want to operate the business, how we are involved in our rate structure and then just how the strength on the credit metric side.

So we’ll focus on just constantly, re-upping that to just really maintain it within that range. So I mean really, we’ve had no change here just because I mean we’re trying to be clear and consistent over time on what our equity needs are. And that — I’ll stop there.

Michael Lonegan: Great. Thanks for taking my questions.

Operator: Our next question comes from the line of Nicholas Campanella of Barclays. Your line is now open.

Nicholas Campanella : Good morning. Thanks for taking the time. I just wanted to clarify on the comments around being at the high end of the 5% to 7%. I think you kind of said that if you have like a meaningful RFP addition kind of put you there and in the prior update, you kind of gave like base rate base growth of 8%. And then I think for the upside opportunities, it was roughly 10% CAGR. What’s kind of like the new refreshed RAB metrics with this new outlook you’re presenting today that kind of ties you to that high end. Thanks.

Joe Trpik: Sure, sure. So our — back in the materials that got published this morning, we did update that rate base growth slide. The rate base slide will now show that range of 7% to 9%. It showed 8% to 10% last time, but that isn’t — there isn’t really a change in the trajectory of what we’re doing. It’s just regulatory. First of all, when we rebased the earnings, we rebased that chart and honestly just cutting ’22 and ’23 off slightly changed the trajectory because there was a fair amount of movement between using that ’22 pillar. And then secondarily, some small items regarding the treatment in this last case regarding the ITCs, being against rate base has shrunk those numbers a little bit. The fundamentals are there, right? The earnings trajectory holds. It’s just a slightly smaller rate base growth due to those mechanics.

Maria Pope: I think it’s important to recognize that the additions to our rate base projections are almost exclusively in the transmission area. We’ve utilized all of the excess transmission across the region, and it’s really important that we invest not only in our existing rights of way and in our service territory, but in adjacent areas to our service territory with regards to transmission as well as broader across the Pacific Northwest. We should recognize that on the rate base growth laws and the capital forecast, the RFPs, the competitive bidding processes as we go out further years are not reflected in those numbers.

Joe Trpik: That’s reflected in the base numbers. Obviously in the base numbers.

Maria Pope: In the base numbers.

Nicholas Campanella: Sorry if we missed that. I appreciate that. And then just common equity ratio. I think in the K is 45.6%. And I know you’re working to get back to the plan, but just how are you framing the cadence of improvement through the plan at this point? Is it 50 to 100 basis points a year? Or just how should we think about that?

Joe Trpik: I mean, I think we should — by ’27, so between ’25, ’26 to ’27, we expect that move upwards to be in the range. Understanding there’s a couple of different calculations the way you see it there on the financials and the way the OPUC does it. But it should be relatively methodical to our brings trajectory in our equity needs here. But I mean it should be a consistent move chunk wise between now and ’27.

Nicholas Campanella: Okay. Thank you so much.

Operator: Our next question comes from the line of Anthony Crowdell of Mizuho. Your line is now open.

Anthony Crowdell : Good morning, Maria, good morning, Joe. Just a cleanup from Julien’s question. I was wondering on the structural lag, and I may have missed the number, so apologies. Are you able to tell us what structural lag the amount and maybe basis points that you experienced in 2024? And then where do you think that lag could potentially be at the end of your plan?

Joe Trpik: So I believe if we take 2024’s performance from an accounting basis, we had about a 70 basis point structural issue between earned and allowed and what we plan to do, and we haven’t assigned Anthony, to that, a dollar amount, but we plan to throughout cost management and just our structure to squeeze that 70 basis points lower as we work forward. And we’ll — honestly, it’s going to take us a bit of time, but that is — we’re hoping to use that as we’re a high watermark for where we are on that lag and readjust from there.

Anthony Crowdell: Got it. But you didn’t — you haven’t quantified where you think you could end with that of the plan. Is that correct?

Joe Trpik: Not at this point, what we’ve quantified so far is really that earnings guidance on where we’ll get O&M range-wise, and then we’ll build from that.

Anthony Crowdell: Great. And then just if I could follow up on some of the wildfire question. I think one of the issues or long term. I mentioned about the limitation on liabilities. Do you think this could be achieved in this legislative session in 2025? And if you wouldn’t mind, I don’t know the Oregon legislative session. What’s the time — like when did it start, when it ends?

Maria Pope: Sure. Well, we have three areas of focus, as I mentioned, in the Oregon legislature and we are very optimistic and working diligently with parties. Bill will be submitted probably in the next two weeks, so you’ll be able to see them publicly in this session ends in June. But we remain optimistic we’re going to work hard, but I would not underappreciate. This is tough and it may take two sessions.

Anthony Crowdell: Great. Session starts in two weeks — or the bills may be submitted in two weeks and this session ends in June.

Maria Pope: Session has already started. Bills will be submitted within the next two weeks by representatives who we are working diligently with on wildfire and session ends in June.

Anthony Crowdell: And last, just does the session happen every year? Or it’s one of those where every other year they meet? Every year?

Maria Pope: Every year, they meet. This is a long session. Next year would be a short session.

Anthony Crowdell: Great. Thanks so much for taking my questions. I appreciated.

Operator: Our next question comes from the line of Paul Fremont of Ladenburg Thalmann and Co. Your line is now open.

Paul Fremont : Thank you. Congratulations on a good quarter. My question, I guess, following up on Anthony’s question in terms of wildfire legislation. Are you looking to essentially replicate what’s in AB 1054 or are you looking for something that’s different than that?

Maria Pope: So we’re looking for a combination of what you can see in Utah and in California as well as talking with other states about the active work that they’re doing, many — almost every state in the West currently has wildfire legislation discussions ongoing. And so we’re looking at what is best practices and what is doable within this data of Oregon and will reflect the continued investments that are needed by the utility into the system and the risk reduction of something catastrophic.

Paul Fremont: And then as has the state or have the parties sort of come up with a number potentially for the backstop fund that you’re talking about?

Maria Pope: No, we have not. And there’s a lot — we clearly need to have an established set of prudent utility practices based on the wildfire plans that we have been submitting and most recently submitted for 2025 to Oregon Public Utility Commission. We’ll also need to make sure that we have some balance around limitations on liabilities. We already have some precedent of that Oregon state law. So we’ll need to make sure that we are able to have a fund that is actually investable and durable.

Paul Fremont: Okay. And then the limits of liability would they apply to just regular negligence, gross negligence. How — would they just be absolute limits on liability? How should we think about sort of?

Maria Pope: Give do have a negligence standard within state law, and we’re working through all of those details right now.

Paul Fremont: Okay, great. Thank you.

Operator: [Operator Instructions] Our next question comes from the line of Travis Miller of Morningstar. Your line is now open.

Travis Miller : Thank you. Good morning. I’m interested in a little more on the federal initiatives. With the new administration, what are you either hearing or anticipate hearing in terms of changes in tone relative to any kind of wildfire mitigation. It seemed like the last administration wasn’t too interested in doing a whole lot to help at the federal level. Wondering if that’s changing at all that you hear or anticipate hearing?

Maria Pope: Sure. Well, first of all, there’s a lot of discussion on the Hill with regards to concern over wildfire, and we’re working with a variety of parties, many of whom have extensive personal experience either in the forest products industry or its firefighters themselves. So we’re really encouraged. With regards to the administration, it is just too early to tell. We’re clearly all hearing a lot of things out of the administration, and we look forward to working with them. I do believe that there is recognition that we need to proactively manage our federal for us to reduce the risk of wildfire across all states, but particularly in the West.

Travis Miller: Okay. And is there — would you anticipate any kind of conflict, either legislative or political conflict between what you’re doing at the state or what might develop say within in Utah or within California and what you’re trying to initiate at the federal level?

Maria Pope: So we see these efforts and as do other utilities doing similar work within their states as very complementary to what would take place at the federal government. I also want to make sure that we recognize that energy security and the integrity of the electric system is also national security. So I think we’re highly aligned at the federal level and the actions that we are taking in Oregon as well as other utilities are taking in other states are aligned with all of these objectives.

Travis Miller: Okay. That makes sense. We’re good. And then one other real quick one. How do you think about power costs with your now updated demand forecast and then thinking about wrapping in the projects in the RFPs which have very low variable costs in there? How do you think about total power cost development over the last next few years?

Maria Pope: So, Joe mentioned this, and you can see in our forecast that we’re actually seeing a near-term moderation in power costs. I think the battery storage that we’ve seen implemented by ourselves as well as other utilities across the West, particularly in California and Arizona is having an impact. We’re seeing continued growth in renewable energy projects and being able to leverage the hydro system to balance all of these things that’s been long been a part of the Pacific Northwest and a unique characteristic of our renewable energy that we’re building upon. But we have also seen with the continuation of production tax credits and investment tax credits that renewable energy is some of the lowest cost energy that we can bring on to the system. And clearly, that remains the preference of our customers in the regions.

Travis Miller: Sure. Okay. Well, I really appreciate all the thoughts.

Operator: Thank you. I’m showing no further questions at this time. I would now like to turn it back to Maria Pope for closing remarks.

Maria Pope: Thank you for joining us today. We appreciate your interest in Portland General Electric. We look forward to connecting with you soon. And thank you very much for your time this morning.

Operator: Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.