Portland General Electric Co (POR) 2026 Q3 法說會逐字稿

Good morning, everyone, and welcome to today's conference call with Portland General Electric. Today is Thursday, October 29, 2026. This call is being recorded, and all lines have been placed on mute to prevent background noise. (Operator Instructions)

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

Thank you, Steven. 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 Forms 10-K and 10-Q, which are available on our website.

Turning to slide 3, leading our discussion today are Maria Pope, President and CEO; and Joe Trpik, Senior Vice President of Finance and CFO. Following their prepared remarks, we will open the line for your questions.

Now I will turn things over to Maria.

Thank you, Erin, and good morning, everyone. We appreciate you joining us today. The third quarter was impacted by the coolest summer in a decade. Against that backdrop, we continue to execute with discipline, actively managing power costs, driving efficiencies in O&M, and identifying additional opportunities to operate more effectively across our business. Importantly, our fundamentals remain strong, with industrial demand growing 9% year over year, driven by continued demand from high-tech and data center customers. In fact, we concluded a significant agreement with Verrus for a facility of up to 420 megawatts, which is expected to be energized in 2028 and ramped to full capacity by 2033.

Now, regarding the proposed holding company. The Commission issued its holding company order on September 25. While the order approved certain aspects of the proposal, several conditions were not workable. We filed for clarification and changes to two areas. We support the proposed rate credit and customer benefits totaling $83 million. If implemented, the holding company would provide additional financial flexibility while maintaining strong customer protections and utility financial strength. That said, while very important, our growth strategy, capital plan, and current guidance do not depend on the holding company implementation.

Next, I'll speak to our financial results and key drivers. This morning, we reported third-quarter GAAP net income of $119 million, or $1.00 per diluted share, and non-GAAP net income of $125 million, or $1.06 per diluted share. Our non-GAAP results excluded business transformation, optimization, and acquisition-related expenses, which are not reflective of ongoing operational performance. The third quarter, like the year, was marked by historically mild weather, lower cooling demand, and, in the quarter, significantly reduced residential and small commercial energy usage.

Turning to slide 4 for our strategic priorities. Customer Growth: We continue to see strong demand from technology, semiconductor, and data center customers. Our New Large Load Tariff, effective in July, increased rates for data centers and other large customers while lowering rates for residential and small commercial customers, putting us ahead of many utilities across the country. The tariff contributed approximately $4 million of incremental margin in the third quarter and includes provisions designed to reduce risk and costs associated with serving new large loads.

Essentially, at PGE, growth pays for growth. We now expect approximately 12% annual capacity growth from our large load customers through 2030, up from our prior outlook of 10%. This growth is supported by customers under contract who run already energized facilities or who are actively advancing construction and facility development. As I mentioned earlier in my remarks, we have an agreement with Verrus for a facility of up to 420 megawatts. It is backed by customer and shareholder protections in our New Large Load Tariff, including minimum payment obligations, direct cost allocation for infrastructure that will strengthen reliability across the region.

The facility also includes integrated battery storage, giving us added flexibility to manage peak demand while maintaining reliability, integrating clean energy, and helping keep residential and commercial prices as low as possible. Verrus is working through the permitting processes, and applications were submitted ahead of any moratoriums. Energization is expected to begin in 2028.

Turning to the Washington acquisition, we continue to move forward and advance the regulatory review process. We anticipate a 2027 close, or mid-2027 close. The third quarter marked an important milestone with the successful launch of our participation in the Extended Day-Ahead Market, or EDAM, a market PGE helped design and develop. EDAM further advances Western energy markets, lowers costs, reduces volatility, and improves reliability. We expect EDAM to create meaningful customer value, contributing to reliability and affordability.

Reflected in our 2027 AUT is $14 million of customer savings. I'm proud of the outstanding work our teams delivered to achieve this milestone. Another step forward in delivering efficient and affordable energy for our customers.

Clean Energy: We have executed two contracts for non-emitting projects. First, we signed a build-transfer agreement for a combined 200-megawatt solar and 250-megawatt battery storage facility at Biglow with an anticipated investment of $900 million.

Second, we've also signed a build-transfer agreement for the Salmonfly project, a combined 199-megawatt solar and 199-megawatt battery storage facility with an anticipated investment of $850 million. Salmonfly is being developed with the Confederated Tribes of the Warm Springs. The project supports coordinated operations of solar and storage along with our existing and jointly owned hydroelectric facilities. Additionally, we continue to make progress on commercial negotiations for other projects from the 2025 RFP. And finally, this month, we filed our 2026 Clean Energy Plan and Integrated Resource Plan with the Commission.

Turning to risk management and wildfires. Against a challenging regional wildfire season, our teams executed our risk management plans, maintained enhanced readiness, and responded proactively. We declared the end of fire season in our service territory on October 26. We continue to execute our year-round wildfire mitigation program, including system hardening, enhanced situational awareness, and technology investments designed to improve reliability and reduce risk. Wildfire risk is a society-wide issue, and we remain committed to working collaboratively with stakeholders on solutions that strengthen public safety, community resilience, and an investable energy future for the Pacific Northwest.

To summarize, we're seeing continued strength in customer growth, success executing initiatives such as EDAM, and advancing clean energy resource opportunities. This work positions us to serve our customers, support Oregon's growth, and deliver long-term value for shareholders.

With that, I'll turn to slide 5 and our 2026 earnings guidance. As a result of weather-related headwinds, we are revising our full-year adjusted earnings guidance from $3.33 to $3.53 to $3.18 to $3.28 per diluted share. We would have been solidly within our original guidance range if not for weather-related headwinds in the second half of the year. We continue to reaffirm our long-term earnings and dividend growth guidance of 5% to 7%.

I'll now turn the call over to Joe to walk through our financial results in more detail. Thank you.

Thank you, Maria. Good morning, everyone. Turning to slide 6, our third-quarter results reflect continued execution on cost management, regulatory recovery, and industrial growth despite the mildest summer since 2016. Beginning with our load trends year over year, total retail energy deliveries decreased 3% compared to the third quarter of 2025 on a nominal basis and increased 1% on a weather-adjusted basis.

We continue to see strong demand from our technology, semiconductor, and data center customers, with 12% annual large customer capacity growth expected through 2030. Industrial demand remained a key driver in the third quarter, increasing 5% quarter over quarter and 9% year over year. This reflects continued demand from our high-tech and data center customers. In the third quarter, we experienced one of the mildest summers in recent history. Residential deliveries decreased 8.9% on a nominal basis and were down 0.6% weather-adjusted, while commercial deliveries decreased 5.5% nominally and were down 2.8% weather-adjusted.

We are updating our 2026 weather-adjusted load growth guidance from 1.5% to 2.5% to 1% to 2%, primarily reflecting changes in the timing of industrial load ramp-ups. Given contractual minimums, we do not expect the revised load forecast to result in meaningful changes to our 2026 revenue.

Turning to our third--quarter financial results. As a reminder, we provided adjusted EPS guidance of $1.20 to $1.32 per share with a midpoint of $1.26. Actual third-quarter adjusted EPS was $1.06. The majority of this variance is a result of the historically mild weather.

Now we'll cover the primary year-over-year earnings drivers for the quarter. A $0.07 decrease from industrial demand, driven by continued growth from high-tech and data center customers, a $0.21 decrease from residential and commercial load largely driven by the mild weather, a $0.04 benefit from power costs. This variance is comprised of a $0.14 detriment from favorable power costs in 2025 that reversed for this comparison and an $0.18 benefit in the current period, primarily driven by the expected intra-year timing of revenue collection and power cost recognition.

Quarter over quarter, there is a $0.15 weather-related EPS impact that contemplates both the decreased revenue impact and the offsetting decrease to power costs. This is embedded within the residential and commercial load and net variable power cost variances. There was a $0.14 increase from additional cost recovery, reflecting the Seaside battery asset included in customer rates beginning in November 2025 and the Distribution System Planning recovery that began in April of 2026. A $0.09 decrease from other capital and financing costs in support of our ongoing rate-based investments, made up of $0.01 of higher depreciation and amortization, $0.07 of dilution, and $0.01 of additional interest expense. And then there was a $0.11 benefit from O&M, reflecting continued strong cost management and productivity improvements across the organization.

On to slide 7 for our five-year capital forecast, which includes 2026 and 2027 spend from our 2023 RFP projects. I will note that this view does not contemplate CapEx from the recently signed Biglow Optimization Phase 2 and Salmonfly projects or any other ongoing resource procurement negotiations and the Washington acquisition, which are progressing as expected. Focusing on 2027 spend, when including both the recently signed projects, we have a total forecasted capital expenditures of $2.5 billion.

On to slide 8 for financing, we remain well positioned. We have completed the majority of our 2026 financing activity, providing clear visibility to our funding need for this year. This includes $550 million of equity issued under the forward sale, with $152 million drawn as of September 30. We are moving $398 million of the planned equity draw to 2027 from 2026 while the decision on the holding company structure is pending. We have a $500 million ATM facility to further support equity needs. We also have a $350 million 24-month term loan satisfying our 2026 financing.

And finally, our investment-grade credit ratings remain unchanged. Looking ahead to our 2027 financing plans, we anticipate $350 million to $400 million of tax credit monetization and $150 million to $200 million of equity issuance. In October, 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. Our plan focuses on maintaining strong operating cash flows while supporting continued investment in customer-focused capital projects, all while advancing us towards our authorized capital structure.

As we look back at our progress over the past three quarters and turn to Q4, we're proud of our disciplined execution. We are advancing cost management. We are advancing management actions across operating and power costs. We remain focused on safe, reliable, and efficient operations, advancing our strategic priorities, and delivering value for our customers, communities, and shareholders.

We successfully addressed the year-to-date significant weather and other load impacts in the first half of the year through management of power costs and driving efficiencies across the organization. However, given the impact of historically mild weather in the second half of the year, we are revising our adjusted earnings guidance to $3.18 to $3.28 per diluted share. We are reaffirming our long-term EPS and dividend growth guidance of 5% to 7% and our long-term load growth guidance of 3% through 2030.

And now, operator, we are ready for questions.

(Operator Instructions)

Julien Dumoulin-Smith, Jefferies.

So just real quickly, I saw this in the 10-Q, this added risk disclosure. I just wanted to dig in a little bit about it, right, specifically setting some of these delay risks potentially. Can you clarify a little bit of what's going on with the 2025 RFP, if that impacts both company-owned generation assets or PPAs, or just a little bit more context, right? Obviously, we've seen various delayed processes in the past, so it's not entirely novel to see this as a new -- novel risk disclosure. But again, we would love to understand a little bit about what specifically is transpiring today.

Yeah, Maria, I'll kick us off on this. Julien, good morning. Really, what you're seeing there is we're just talking that we have -- there are multiple paths to procuring assets, including BTA, not just the RFP. And you see in this case that we're just exploring some alternative paths based on what are the most attractive investments. So that's the only difference here, understanding our last path was straight in RFP.

And Julien, let me add, first of all, I'm impressed that you're looking at our risk disclosures in the 10-Q. But one of the things that I think gives us a lot of confidence in our pipeline is the Biglow 2 project that we announced today as well as Salmonfly. And the overall cost per kilowatt is pretty close to what we saw out of the 2023 and even -- as well as what we see from statistics across the country over the last 12 months. So while we are nervous about inflation and supply chain, the execution of our team has been very strong.

Yeah, excellent. And if I can just follow up a little bit on some of the HoldCo dynamics. Again, this gets a little bit in the weeds as well. Look, I know that Staff has -- OPUC Staff has filed here in support of some of the clarifications on the retained earnings cap. Can you talk a little bit about some of those alternative cap calculations, and do you see that as an acceptable provision?

Again, I go back to some of the caveats you guys put in the Q here about moving forward and what this might look like for reconsideration. I'll leave it open ended.

Yeah, I'll start us here. I mean, we continue to appreciate the dialogue from the Staff here, and our focus is making sure that the HoldCo is able to function on a normal basis, meaning pay dividends and be able to finance itself. We appreciate that we don't have opposition from parties like AWEC, and I'll just leave it as we work through the math of some of these. We are open to any proposals here that, again, just allow it to operate effectively. The reason we are where we are right now is we would not have been prudent to move forward with the design as was because it did not allow us to effectively have a HoldCo and protect our shareholders and dividends.

Got it. Excellent. Just lastly here on the credit rating side. And obviously, this ends up being fairly binary in terms of what exactly happens in terms of notch thresholds. But given the financing benefit, is the one-notch threshold like a red line that if the Commission doesn't amend it, you guys wouldn't proceed with the HoldCo? Again, I'm just curious on the relationship between the rating side and your decision to move forward, again, if I can have this too.

As it relates to the proposal, the order out there on the HoldCo, both the one-notch provision within the HoldCo agreement and the dividend restrictions are both red lines. I mean, that is why we responded to where we are. As it relates specifically to the rating agencies, we continue to be in dialogue with them. We keep them apprised, and we are working through different scenarios with them as it relates to us adapting to whatever the next proposed HoldCo order is.

Got it. All right, awesome. And anything on wildfires here that you could offer up, in as much as we saw a lot happen in California? I don't know if there's anything that you'd flag for your upcoming session, or maybe not. Again, maybe a catch-all, but some (multiple speakers)

First of all, I think it's against the backdrop of a tough season overall in the state of Oregon, as well as across the country, with regards to wildfires. And as I noted in my prepared remarks, our team did really well. And we did turn the power off a number of times and actively monitored for one of the longest IMT runs that we've had in the history of our company. Clearly, wildfire smoke is an issue for Oregon, the damage and destruction mostly which is in the US Forest Service lands or BLM lands, but also for the overall health of the economy of the state. So you can see the Oregon Business Plan and the Governor's Prosperity reports and council work, a lot of focus on how to address this issue.

We're looking forward to seeing the report that the PUC has commissioned. It's not out yet. I would expect it to be out in the next couple of weeks, and that should create a foundation for some of the legislative work we can do this session. We're closely monitoring what's going on in California, and particularly the findings from wildfire that's in the California earthquake report done earlier this year.

Excellent, guys. Speak soon.

Shahriar Pourreza, Wells Fargo Securities.

Just real quick on the HoldCo, just on the petition. I mean, AWEC came in not opposing your changes to Conditions '25 and '26. Are you seeing similar alignment from Staff and CUB? And is a resolution before the December 7 acceptance date the base case, or should we think of this sliding into '27 with the shareholder vote?

That's a good question. We're continuing to work through the process. The Commission should come out pretty soon with their decision, and we are monitoring and working through all of the different aspects.

Okay, got it. And then just on Biglow and the Salmonfly build-transfers, that's $1.75 billion that sits outside of the plan, mostly '27, '28. How should we think about the equity content there? Is it roughly 50-50 with the $500 million ATM covering it, or does the HoldCo outcome change how you finance it?

So I'll start with our guidance. When we talk to both our 5% to 7%, when we talk directly planning here, we are always viewing this without the HoldCo in the first place. So our growth rates and the affirmation we made previously were exclusive to HoldCo. But we do think, too, when we think to the financing of these two projects specifically, we start with the tax credit that we'll receive from the 2023 RFP disclosure earlier on the call, somewhere between $350 million or $400 million of tax credits that will come from the '23 RFPs, then we'll look to the debt to finance, our draw from the '25 forward, which we had almost $400 million left, and then we have -- and minimal new equity.

I think when you look to our equity guidance here, our equity for 2027, even inclusive of these projects, has increased by about $50 million from our prior disclosure.

Got it. Perfect. Appreciate it, guys. I'll leave it there.

Steve Fleishman, Wolfe Research. Your line is now open.

Just clarity on, you said you'll hear from the Commission in the near future. Any more specifics on likely timing and which of these different options, clarification, and which direction, if anything?

So the outside date is December 7, when we would expect to hear from them. So I would assume that we'll go all the way to December 7. Given that we had a year-and-a-half-long process and a negotiated settlement, so there's a lot of testimony on the record, a lot of expert statements. My hope is that they are looking at the record and working through the process, and they'll come out with a decision on December 7. So we'll know more then.

Okay. One other question on that. So in this scenario where they do fix those two conditions appropriately, how are you thinking about the fact that they left double leverage open in the order for a future rate case? And just, is that an acceptable risk as part of this?

I think, Steve, we've looked at that from sort of the norm across the country, and it's not something that is always excluded from other holding companies. And so it's a risk that is typical of some other utilities, and we would expect to work through it. We're also moving towards five-year rate cases, and so I think that the five-year rate case system in the future will create more certainty for investors as we move forward.

Got it. That's helpful.

Chris Ellinghaus, Siebert Williams Shank.

Hey, good morning, everybody. So, vis-à-vis the HoldCo decision, have you had any ways to get a sense of whether the two key elements sort of in dispute were errors on the part of the Commission in haste of trying to make adjustments to the settlement or those were intentional?

I don't think we have a comment on that. We can't have any ex parte communications during this period of time with the decision outstanding. And so we submitted what we thought were clear and pretty minimal recommendations in our clarification filing a number of weeks ago and tried to make that as workable as possible given all of the discussions over the prior months and the settlement that we had previously had with Staff.

So obviously the settlement was very detailed and really gave the Commission a pretty good roadmap for this, but they decided to deviate. Do you think that they understand the impact that that has on investors and how that affects cost of capital when they do things like that?

I'll chime in. I mean, that's the point of the clarification and, honestly, the point of our communications. Clearly, the material included within the Staff addressed that. However, we will work through the record here to hope that they have that clarity. Obviously for us, as you know, that's what's critical to us.

That's the value of this HoldCo that allows for the benefits that would go to customers to be paid. And so, we need to make sure they appreciate that it's a critical structure for it all to come together.

Okay. Joe, some of the numbers that you quoted were kind of interesting in the absolutes versus the weather-adjusted load numbers. It seems like maybe there might be some other factor because, like, the residential weather-adjusted was still lower. And total retail sales weren't up that much on a weather-adjusted basis either.

So is there another factor at play that you can identify that might be dampening load for the quarter beyond the weather?

And for the quarter, just for the quarter, when we think of residential, we were at 0.6% on a weather-adjusted. But I would agree with you on a year-to-date basis, Chris, as you may recall, in the first quarter we had some unusual load trends that we addressed through our plans, and we do agree that there were some unusual load patterns. So when you look to year-to-date results, those patterns obviously still hold. However, as we revised and looked through the third quarter, which is obviously one of our largest load quarters, after adjusting out weather on the residential side, it was pretty darn close.

First, let me add one other comment. One of the great things about the 2377 large load tariff is that there's essentially a take-or-pay. So we have pretty significant capacity payments which positively impacted the bottom line, but we had some lower energy usage from a couple of the data center customers. The data center customer energy uses can be kind of choppy at times.

That reminds me, Maria, I meant to ask, have you got any rule of thumb or any thoughts in terms of, when you do have some extremes on the weather side, how that will affect the data centers or large load customers in general that ambient temperatures really might have an impact on their cooling needs, and did you see any of that in this quarter at all?

So I'll respond to it. Clearly, the data centers have less of a weather sensitivity. You did see a small weather, to your question. To date, we haven't shown that. I believe we have seen that their weather differences in a couple percentage points, obviously where you see the residential side acting much more extreme. I agree, and maybe what we can reflect to as we work through our guidance going forward is potentially, as this class becomes more significant, try to give the differing sensitivities because it is, you're right, as we go through this, the residential classes and the small commercial class react much more significantly to weather than these classes that are much more insulated.

They're already insulated, right? They already have, they're trying to be as efficient as possible, even without the external factors.

And lastly, have you got any updates on your expected timing of 2025 resources?

So if we're talking to the 2025 RFP, we have the two projects obviously we just announced here. The timing for these projects, as we're trying to work through tax credits, have in-service dates, and they have a couple of -- a bit of different in-service dates in 2029. We do continue to work other items on the RFP shortlist that we published at the beginning of the year as we continue to work to fill what we believe is the bucket to serve the system reliably.

Okay. Appreciate it.

Aidan Kelly, JPMorgan.

I guess just picking up on the HoldCo, or the hypothetical lack thereof scenario, could you just walk through how you would finance the Washington acquisition under the existing structure? I guess the question is, like, do you see this changing the calculus of your CapEx, or would you more look to kind of backfill with more equity in that scenario?

Yeah, I think, to your comment, without a HoldCo, I'll start with, we had said that with the HoldCo, Washington would be accretive in the first full year. Our goal without a HoldCo would be that it'd be at least a breakeven to a slight accretion in its first full year. We would expect that we would not be impacting the capital at our PGE side, but we would be financing this at a balanced cap structure as it relates to that structure, assuming again no HoldCo.

Great. That's super helpful. And then maybe just picking up on the Washington utility acquisition, could you just characterize where Staff stakeholders' concerns are most substantive today and maybe what incremental commitments you believe might be necessary to reach a settlement in Washington at this time?

Sure. So first of all, the process is going really well, and we're moving through a lot of important conversations. There's three main areas that have been raised. The first one is CETA compliance, which is their clean energy compliance in the state of Washington. The second is the hydro facility that is not included in the transaction. That's facilities that are on the Lewis River off of Mount St. Helens. And then third is the rate credit for customers.

Great. Thanks for the time today. I'll leave it there.

Anthony Crowdell, Mizuho.

Good morning, team. I just wanted to follow up on Chris's question maybe two people ago, just on the capital plan and I think the higher cost of equity, just without the holding company or if it's still not determined yet, just are there any changes to your capital program, just as given the higher cost of equity that maybe you guys would have to readdress the capital plan that's out there? And I have a follow-up.

At this time, there really isn't a change to the capital plan. As I mentioned, the additional financing costs for the RFP projects as they were added, thanks to the ability to monetize the tax credits from 2023, have a negligible or slight impact on our equity plan. And we believe we continue to be able to support our 5% to 7% growth with our current financings and with and without a HoldCo. So right now, I don't think now is the time really to debate any changes to the capital.

But we agree that with our current stock price and not having a holding company creates challenges, especially given Oregon's specific clean energy goals. Still noted near term, we have levers from the tax credits, our solid balance sheet, being able to draw on equity forward, as well as other mechanisms. So we're really focused on working through the process to hopefully come to a solid resolution that works for everyone on the holding company.

Okay. And then just more of a modeling question. Most of the calls here this cycle, we've been talking about maybe a spread between rate base growth and maybe earnings growth or earnings per share CAGR. I'm just curious, what do you think the ranges are? What's a good modeling assumption to use to go from rate base growth to earnings growth for Portland?

I don't have an update yet. I mean, we will look to that as we work through the 2027 guidance. I think this spread will hold for the moment until we formalize and layer in everything as it relates to 2027.

Great. Catch you guys at EEI.

Gregg Orrill, UBS.

Maybe just some housekeeping around the CapEx plan and the Biglow and Salmonfly projects were signed on in October. Was that the reason why you didn't include them in the $7.4 billion CapEx plan?

Yeah, that's right, Gregg. Not to do the sort of accounting or disclosures, we've always had our CapEx table that we use in the investor materials align with the Liquidity and Capital Resources footnote in the 10-Q as an as-of date. And so we've tried to hopefully put some pretty adequate disclosures both in the investor deck as well as in the 10-Q to layer that through. And that is the only reason, is because both agreements have effective dates within the last couple days here.

And are you providing any guidance around how those projects would impact the EPS growth rate guidance?

For right now, we've obviously given guidance on the equity financing plan, and we've affirmed our 5% to 7% for right now. So at the moment, what we've historically said here, which aligns, is that in years of meaningful RFPs, we expect to achieve a growth rate at our midpoint, generally our midpoint or better year. And these RFP projects don't change that.

Appreciate it.

David of Bank of America. Your line is now open.

Just looking at the 4Q implied guide, wondering if you could help us bridge a little better how you get there just to a little more granularity. In other words, if we took your slide 6 and rolled it forward a quarter, comparing last year to last year or even to 2024, what are the puts and takes you would flag that kind of ground your confidence in the Q4 number for this year, just given it's such a meaningful step-up from recent quarters?

Okay, sorry, I didn't mean to talk to you too soon. I always love the roll-forward questions where I get to just put the numbers in the air here. But so, yeah, there's a meaningful change from last fourth quarter to this fourth quarter. Just as a reminder, last year had a pretty material weather effect in the fourth quarter, mainly in December. So when you think of the biggest -- the biggest puts and takes are weather-normal assumption. So that in and of itself is $0.17.

The timing of the DS -- So the Distribution System Planning recovery, and Seaside was only a partial quarter last time. So the DSP and Seaside will drive that. We have a change, or a more favorable move, on net variable power costs. We have additional cost management. And then the last one is just the mechanical timing of the way the costs roll through the AUT.

But when you take this, the supermajority of the variance between when you look fourth quarter last year to what we anticipate fourth quarter to be this year is in margin. There's a little bit in the O&M management side, but the majority is these margin items that I laid out here, plus some O&M favorability.

Okay, great.

JC Vidales, Ladenburg Thalmann & Co.

Hi. Good morning. Just a quick clarification. If the Commission were to take action consistent with Staff's recommendations that they put out on the 22nd, would that be enough to accept the Commission's order if they kind of go ahead and approve Staff's recommendations, or would you consider that an unacceptable recommendation?

If we took the recommendation with the one-notch credit downgrade before dividends stopped, we would not be able to accept that. That's not -- A one-notch, as you all know, occurs sometimes for the sector as a whole and through ordinary course of business. And you have an ordinary course of business item, risk dividends is not something that we're willing to accept.

Okay, great. And then just on the Washington portion, I believe the utility is somewhat earning around the mid-single digits. I mean, do you think that's enough to make it either breakeven or be slightly accretive if there is no HoldCo?

So I think I mentioned a little earlier here, obviously our plan here, we said it would be accretive in the first full year with a HoldCo. Our comment was that, you know, the transaction does not need a HoldCo, which we fully support. We said it would take a little while longer to be accretive without a HoldCo. However, as we continue to work forward, our goal is in the first full year of the Washington acquisition to at least be breakeven. That is what we are shooting for.

We believe if we hit our operational goals here that that is an achievable result.

Okay. And then just along those lines, I mean, if it closes mid-2027, when would you suspect you would be going in for your first rate case in Washington?

We're still evaluating when that would be. I think when we would go in for a rate case would potentially be part of this agreement. So I don't have an exact date at this point in time.

Okay, great. See you all at EEI.

(Operator Instructions) Travis Miller, Morningstar, Inc.

Quick modeling question here. The New Large Load Tariff, what is or will be the impact either from a net revenue and/or earnings for either the rest of the year, next year?

Good morning. So I'll start. Maria may add on this one. So for the third quarter, the first quarter that the New Large Load Tariff has been in effect, I believe we disclosed it's around $4 million. We think for the second half of the year potentially that same, if not a little bit more.

And then next year, as we work through, obviously we haven't given guidance, there's no reason to think that those types of numbers wouldn't occur for the first part of the year. But just as a reminder, all of this gets rolled into a rate case. One of the more important factors of the large load, as much as we talk about, you know, the additional charging and the balancing to the data centers, is the residential customers also did experience a little bit of a rate reduction, around 1% here, that came through starting at that same period of time.

Okay, perfect. And then higher-level question for your system. As you look at it today in terms of energy coming from renewables and then the need for capacity, and particularly clean capacity, should we expect most of the incremental projects to come with some type of battery solution? Again, just given the balance between energy and capacity that's on your system now?

So that's a great question. We have been very fortunate to be out front in implementing battery storage, and it's a really important part of our reliability mix today. Being able to add batteries to existing renewable facilities, as well as with additional renewables, enables us to better leverage existing transmission through the system and really create positive synergies. We would expect to continue to add batteries. The more you add, you get to a little bit of diminishing returns.

One of the things that we, as part of EO 2377 and all of our large load work, is the capacity that many of those customers bring. So as I noted, Vantage is bringing battery storage to their project, and we have other data centers that do the same thing. So we also are watching very closely the run-up in battery storage prices and are fortunate to have as much underway in construction and moving forward at the prior pricing.

I do think, just as a numbers part, it's just interesting. When we work through this 2025 RFP and PPAs that are out there, we will have batteries on the system well in excess of 1,000 megawatts on a system with a peak load of somewhere around 4,500 megawatts right now. So it's a pretty -- right, even now, realize we have some standaralone batteries. It's a pretty impressive battery population relative to the overall system.

Yeah, that's great. Those are big numbers relative. So, okay, that's all I need. Thanks

Paul Fremont, Ladenburg Thalmann.

Hey, thanks. Just curious what your plans are for your ownership interest in Colstrip. Are you still planning to exit ownership of the plant in 2028?

Yeah. So good morning, Paul. How are you? So Colstrip, we continue to own Colstrip, and our interest. We do not currently have a disposition plan for Colstrip. We do know that under current Oregon law that the electrons related to Colstrip, or the power coming from coal generation, will not be served for retail load, at least as currently written.

We just continue to work with all the constituents on what is the best alternative as it relates to the future status at that point for us.

So would you consider continued ownership of the plant if you couldn't sell to retail customers?

We honestly will have to work with the regulators. I think it'll be just an interesting dialogue to have considering the status of the law and the ownership interest. But we're open to work with them. Obviously, it is inexpensive energy, but by view of Oregon, it is not clean energy. But we are open to work through many different scenarios on how to resolve our structure with Colstrip.

Great.

Thank you. This concludes the question-and-answer session. I would now like to turn it back to Maria for closing remarks.

Great. Thank you very much. Clearly, as we've discussed this morning, a lot of work to continue to be doing on the holding company structure. But as we've also noted, we've taken up our growth rate from our data centers from 10% to 12%, underpinned by really positive results from our Large Load Tariff. We have two exciting RFP projects that are moving forward, offsetting some of the other reductions in capital for this year.

And then as we look at O&M, we've exceeded our goals, solid operating performance, as well as through the day-ahead market. We're seeing great results on the power cost side. We appreciate your time this morning, and we look forward to seeing you all at EEI in a couple of weeks. Thank you.

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