Portland General Electric Company (NYSE:POR) Q4 2023 Earnings Call Transcript

Portland General Electric Company (NYSE:POR) Q4 2023 Earnings Call Transcript February 16, 2024

Portland General Electric Company isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning, everyone, and welcome to Portland General Electric Company’s Fourth Quarter 2023 Earnings Results Conference Call. Today is Friday, February 16, 2024. This call is being recorded, and as such, all lines have been placed on mute to prevent any background noise. [Operator Instructions] For opening remarks, I will turn the call over to Portland General Electric’s Manager of Investor Relations, Nick White. Please go ahead, sir.

Nick White: Thank you, Daniel. Good morning, everyone. I’m happy you can join us today. Before we begin this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we’ll be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2, some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause our 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.

Leading our discussion today are Maria Pope, President and CEO; and Joe Trpik, Senior Vice President Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now it’s my pleasure to turn the call over to Maria.

Maria Pope: Thank you, Nick, and good morning. Thank you all for joining us today. Beginning with Slide 4, I’ll discuss our 2023 full year and fourth quarter results and then turn to our outlook for 2024 and beyond. For the full year, we reported GAAP net income of $228 million or $2.33 per diluted share and non-GAAP adjusted net income of $233 million or $2.38 per share. This compares with GAAP net income of $233 million or $2.60 per share and non-GAAP adjusted net income of $245 million or $2.74 per share in 2022. For the fourth quarter, we reported net income of $68 million or $0.67 per share, up from the fourth quarter of 2022 of $50 million or $0.56 per share. While these are lower-than-expected results, we remain confident in our long-term growth trajectory of 5% to 7% and 2024 guidance of $2.98 to $3.18 per diluted share.

To start, challenging weather impacted the quarter with mild conditions across the period in the second warmest December on record. This resulted in very low energy usage and historically low wind and hydro production. As a result, this combination, both to our revenue and purchase power and fuel expense, performance fell short. The power cost challenges we faced in 2023 underscore the importance of risk reductions achieved as part of the 2024 general rate case. This includes 500 megawatts of hydro agreements, improving our capacity portfolio and the introduction of the reliability contingency event provision as part of the PCAM. These are solid steps in reflecting actual power costs and extreme events. We also have more work to do and look forward to working with the commission, other utilities and regional stakeholders towards a holistic energy framework and solution.

Finally, our results also reflect higher costs associated with continued capital investment to support grid resiliency, customer growth and decarbonization. Turning to Slide 5. We consistently said that 2023 would be an investment year. Notwithstanding the challenges we faced, we achieved important milestones that have set the stage for 2024, including a constructive outcome in our general rate case. 2024 will be a year of growth supported by three key drivers: first, continued load growth led by high-tech and digital customers; second, capital investment to enable this growth, advance our clean energy goals and strengthen reliability and resilience; and third, ongoing operational discipline across our organization. I will touch on each of these in turn.

First, we expect continued strong industrial load growth supported by state and federal policies. Microchip was recently awarded $72 million under the federal CHIPS Act for $800 million expansion at their facility in Gresham. This is an addition to the multibillion dollar investments by analog devices and others. This builds on the state of Oregon’s appropriation of $240 million for semiconductor projects, 85% of which are in our service territory. Our capital plan now includes additional strategic transmission investments to enable this high tech and other customer growth as well as renewable development. Joe will walk you through the updates to our plan in more detail. But at a high-level, our transmission projects are largely within our service territory or adjacent.

Many of these lower risk projects are re-conducting existing lines. Related to renewable development, we are currently accepting and evaluating bids for the 2023 RFP throughout the first quarter of 2024, and we’ll present the short list later in the year. Coming out of our last RFP, Clearwater Wind project came online in January with an impressive 45% capacity factor. And we look forward to our battery storage projects coming online later this year and into 2025. Now on to Slide 6. Utilities across the country are dealing with increasing impacts of extreme weather. This January, a severe storm brought a powerful combination of high winds, ice and snow that led to widespread damage and high power costs. In the face of these extraordinary conditions, we deployed an extraordinary response.

This included more than 1,800 personnel, crews and support staff, working hard to restore power and repair critical equipment. I want to take a moment to acknowledge and thank our teams and partners for all of their hard work in very challenging conditions. The storm came in multiple phases of severe weather and single-digit temperatures. In the course of about a week, crews restored power to over 0.5 million customers. This is a great example of how our teams are working together efficiently to deliver for customers when they need us most. Our response was informed by lessons learned from the severe storms we experienced in 2021, and we are continuing to improve in what used to be one in a decade events. This operational focus is showing up in other ways as well.

Our results in 2023 reflect our strong execution on cost management, thanks to the extraordinary efforts of our team to streamline processes, leverage technology and improve productivity. As we look to 2024, we continue to build on this progress. To reiterate, we are focused on three main areas to achieve growth in the coming year and beyond: first, exceptional customer growth; second, execution of our capital plan; and third, ongoing operational discipline. As such, we are well-positioned to achieve 5% to 7% long-term earnings growth. With that, I’ll turn it over to Joe, who will walk you through our financial results. Thank you.

Joe Trpik: Thank you, Maria, and good morning, everyone. Before I walk through the results and outlook, I want to acknowledge that we did not file our 10-K this morning in line with our typical practice. We are just finalizing the required documentation for the 10-K and completing associated compliance procedures. As you may know, we finished a new ERP software implementation in the fourth quarter. With the holiday on Monday, you will see our filings posted with the SEC on Tuesday morning. Now turning to Slide 7. Our 2023 results reflect continued industrial load growth, dynamic weather and power cost conditions, execution of our capital plan and strengthening our growth foundation. Weather had a meaningful impact on 2023 results, particularly in the second half of the year.

We saw 11% fewer cooling degree days and 13% fewer heating degree days compared to 2022. Q4 had historically moderate stretches with our regions seeing the second warmest December on record. Overall, we experienced 15% fewer heating degree days than the 15-year average. Customer uses was affected by these conditions, but power costs were also challenged as renewables production was significantly impacted during these mild periods. PGE’s wind farms generated 23% less energy in Q4 2023 than Q4 2022, requiring generation — PGE’s thermal fleet to make up much of the shortfall. Ultimately, these dynamics were a significant headwind in achieving the level of power cost favorability expected for the year. 2023 loads increased by 0.9% or 1.4% weather-adjusted compared to 2022.

2022 residential load decreased 1.7% year-over-year or 0.5% weather-adjusted, driven by mild weather and energy efficiency, residential customer count increased 0.8% for the year. Commercial load decreased slightly down 0.3% or 0.2% weather-adjusted versus 2022, largely driven by energy efficiency. Healthy industrial load growth continued in 2023, increasing 5.9%. Over. the last 5 years, we’ve observed a 7.5% compound annual growth rate in industrial load as high tech investments and AI expansion have driven semiconductor and data center demand growth. While total loads in 2023 were below our expectations, our service territory fundamentals and our load outlook remains strong. Unemployment in our region of 3.4% trails a national average of 3.7% and we continue to see other positive indicators, public and private sector investment points to broader economic development and continued load growth in 2024 and beyond.

I’ll now cover our financial performance year-over-year. We experienced a $0.14 decrease in revenues, excluding power costs and regulatory program collections, driven by a $0.13 increase due to the 0.9% increase in deliveries and $0.27 decrease due to changes in the average prices of deliveries from higher industrial load and lower residential and commercial loan. Power costs drove a $0.25 increase in EPS, driven by a $0.29 EPS increase due to power cost headwinds in 2022 that reversed for this comparison and a $0.04 EPS decrease from higher power costs than anticipated in the annual update tariff. Serving load during the August heat event and the impact of mild weather on Q4 renewable generations were the key factors. Operating expenses, net of deferral-related items, drove a $0.01 decrease.

Our efficiency and cost management efforts, particularly in Q4 allowed us to keep base O&M nearly flat year-over-year. Next, a handful of impacts driven by the execution of our long-term capital strategy, including $0.19 decrease from higher depreciation and amortization, a $0.16 decrease due to higher interest expenses, a $0.10 increase from higher AFUDC driven by ongoing investment, including the recently completed Clearwater Wind development and a $0.22 decrease due to the dilutive impacts of draws on the equity forward sale in 2023. We had a $0.01 increase from other items, including higher returns on benefit plan assets and regulatory interest, partially offset by benefit planned buyout in 2022 that did not recur. Lastly, a $0.05 decrease to GAAP EPS resulting from the Boardman settlement refund, bringing us to our GAAP EPS of $2.33 per diluted share.

After adjusting for this $0.05 impact, we reach our 2023 non-GAAP EPS of $2.38 per diluted share. Turning to Slide 8, which shows our latest 5-year capital forecast, 2024 through 2027 estimates are now upsized by $1.2 billion as we look to maximize customer value with system-wide improvements and emerging transmission investments. These transmission projects will focus on network improvements meant to alleviate congestion, improve adequacy and reliability, enable decarbonization and address customer growth. 2028 transmission projections also include PGE’s estimated contribution to the Bethel Round view transmission line upgrade, which will be undertaken with our long-time partner, the Confederated Tribes of the Warm Springs. This project will be assisted by the previously disclosed $250 million U.S. DOE grants awarded to the tribes.

As planning and scoping are finalized for this and other grant-related projects, we will update our estimates and reflect in future forecast. We have also refined our expectations for base capital spend to support grid modernization, system hardening and technology investments. As a reminder, this chart does not reflect CapEx related to the possible ownership from the recently launched 2023 RFP, which went to the market on February 2. The competitive bidding process schedule, which is included on our RFP website, anticipates bid submission, final shortlist selection and shortlist submission to the OPUC by mid-2024. Project selection is expected in Q3 or Q4. This time line is dependent on the volume and complexity of the bids, and we will update you as the competitive process continues.

While we are continuing to evaluate timing, increased base CapEx to deliver customer benefits and the incoming battery projects to improve group flexibility put weight on the scale for a near-term rate case filing. In line with our standard process, we will keep you informed of any actions regarding a rate case filing. On to Slide 9, for our liquidity and financing summary. Total available liquidity at December 31 is $969 million. Our strong balance sheet, investment-grade credit ratings and stable credit outlook remain unchanged from our previous disclosures. Through December 2023, we’ve entered into [indiscernible] sale agreements for $78 million of the $300 million available under the ATM. There have not been any draws in these forward agreements thus far.

As we look to the remainder of 2024, we anticipate debt issuances of up to $730 million for the year, and we plan to continue our practice of issuing under our green financing framework where possible. On the equity front, capacity under the ATM remains sufficient for our base capital financing needs, including the battery projects currently underway. The ATM provides a helpful mix of capital access and dilution management that supports our ongoing base capital plan. Continued management of our capital structure and trending towards our authorized 50-50 ratio over time remains a key priority. We maintain flexibility in financing options and remain confident in competitively accessing both debt and equity markets when necessary. As additional capital investment opportunities mature, including from the RFP, we will continue to evaluate our strategy and update you on our financing plans.

Turning to Slide 10. We are initiating full year 2024 adjusted earnings guidance of $2.98 to $3.18 per diluted share. As Maria noted earlier, the January storm system had a meaningful impact on our service territory, and we are continuing to work through the implications of the multi-day event. Currently, we estimate storm restoration operating expenses of $35 million to $45 million and approximately $15 million of capital cost to repair impacted assets. Earlier this month, we filed a deferral of these costs under a standing emergency restoration deferral. The conditions to trigger the first reliability contingency event treatment under the updated power cost recovery framework for [indiscernible], as the region saw market price spikes, balancing authority alerts and resource adequacy constraints on PGE system.

Under the RCE mechanism, PGE is allowed to pursue recovery of 80% of the cost for the RCE above the amounts forecasted in the AUT, with the remaining 20% flowing through the existing PCAM. We are currently estimating the RCE cost between $85 million and $100 million. These impacts are still being finalized, but we will be able to provide more detail when we report Q1 2024 results. Given the extraordinary and irregular nature of the storm last month, the effects are excluded from our 2024 guidance and will be excluded from our 2024 adjusted non-GAAP results to improve the comparability of earnings and to better reflect our ongoing financial performance. We expect this to involve the exclusion of the non-recoverable 20% portion of the RCE cost and any operating costs, which have been determined non-recoverable under existing mechanisms.

I will now touch on other drivers of 2024 guidance. As I said earlier, confidence in our service territory remains strong, highlighted by continued load growth from industrial customers and modest increases in the residential and commercial classes. Combined, we assume a 2% to 3% weather-adjusted retail load growth for 2024. These load dynamics as well as continued regional investment in a pipeline growth guidance of incoming projects give us continued confidence in our long-run load assumptions — expectations. As such, we are reiterating our long-term load growth guidance of 2% through 2027. We anticipate O&M expense ranging from $815 million to $840 million, which includes $165 million of earnings neutral regulatory deferral amortizations, wildfire mitigation and vegetation management costs and other offsetting items.

Net of these items, the midpoint of our O&M range represents a 3% compound annual growth rate compared to 2022 base O&M net of similar offsets. We remain committed to deploying the right tools to optimize productivity and provide the highest quality customer service while also managing operating costs. This philosophy, coupled with derisking accomplishments and critical investments made in 2023 give us continued confidence in our growth plan. As such, we are reiterating our long-term earnings growth and dividend growth guidance of 5% to 7%. As our attention shifts to the year ahead, our core focus remains unchanged: 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.

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Q&A Session

Operator: [Operator Instructions] And our first question comes from Nicholas Campanella with Barclays. Your line is now open.

Nicholas Campanella: Hey, thanks so much for taking my question, happy Friday.

Maria Pope: Good morning.

Nicholas Campanella: So I guess just pretty material increase in the base CapEx plan here. So can you just help us understand, are there additional equity requirements beyond kind of the $300 million ATM that you’ve highlighted in the slides, and then — maybe I’ll just leave it there for now. And then where do you kind of stand in that 5% to 7% EPS CAGR with this new CapEx plan? Thank you.

Maria Pope: Sure. Well, thank you very much ₤ eventually (Executives) Sure. Well, thank you very much. So first, one of the additions that you’re seeing, pulled it out and separated it from what we had shown you in the past is our transmission investment plan. And that will continue to probably increase as we move forward as well. And then in regards to your questions on our equity offerings or where we’re looking for the ATM. The ATM will cover what we need for the foreseeable future, including the batteries. We are waiting to see where we end up with the RFP projects that could be coming in, and that could potentially require additional capital. We remain confident in our 5% to 7% growth rate. And you’ll see that moving forward with confidence as we look to 2024, which is a really solid year for us given the outcome of our rate case, customer growth and the capital plan that we just discussed.

Nicholas Campanella: Okay. So on the base plan today, it’s just the current equity funding needed to do the base plan today. Obviously, that can change as this RFP comes through, and we’ll see how much you can own versus not. Is that the right message?

Maria Pope: Yes. That’s correct, Nick. Thanks.

Nicholas Campanella;: Okay. Thank you. And then just — I guess just on the storm expenses. Just understanding that you’re Deferring a portion of it. You kind of talked about this $35 million to $40 million bucket and then this $85 million to $100 million for the RCE costs. Just simplistically, like how much is actually being deferred versus excluded from the non-GAAP number in ’24?

Maria Pope: Sure. Let me let Joe take that on. And one of the things I want to recognize is this was truly an extraordinary event not only for the restoration efforts with regards to customer outages, but region wise, the energy markets were really in significant disarray. Joe?

Joe Trpik: And so, Nick, I will of answer this a bit in reverse. So as it relates to the cost, the amount that we would expect not to be deferred that would be the operating — the exclusion would be between $0.10 and $0.15. Maybe everything else that we talked to would be deferred within 1 of the 2 mechanisms that we’ve mentioned previously.

Nicholas Campanella: That’s helpful. Thank you so much.

Operator: Thank you. One moment for our next question. And our next question comes from Shar Pourreza with Guggenheim Partners. Your line is now open.

Unidentified Analyst: It’s actually James for Shar. So if I could start on the load side, just part of the backdrop is your service territory has seen a lot of companies involved in semiconductor manufacturing and AI-specific data centers. Can you just give us some color on how AI is providing growth across the customer classes as you see it? And also any detail on what kind of incremental generation or transition opportunities are being created in the longer term, specifically by those customers?

Maria Pope: Sure. That’s a great question. So on the longer term side, certainly, we have been semiconductor manufacturing center for decades. And about 15% of semiconductors are manufactured in our service territory, and we expect to see a lot of longer-term growth. The construction of those facilities is very extensive. Easier to construct and near-term growth is the AI-driven data centers, both in terms of some of the mega facilities as well as some of the grid edge computing. So we’re seeing no small shortage of demand from just about every hyperscaler and cloud computer company out there. And it’s a really terrific amount of opportunity for us. Most of these companies want 100% clean energy. They frequently bring their own reliability back up and are interested in additional transmission substation infrastructure as well as others.

So it allows for significant growth as we move forward. For our communities and the other customers we serve, this creates an overall strengthening of our reliability and resiliency as we invest in new infrastructure, and it provides important jobs for the region, property taxes and other significant benefits.

Unidentified Analyst: Got you. Thank you. And then shifting over to the regulatory side, Joe, you hinted this at the end of your prepared. I assume the time line for new rates, Jan 1, ’25, would the new GRC filing in the next week or 2. I guess can you just get a little more color on your thoughts on timing?

Joe Trpik: Sure. Well, so we haven’t finalized our thoughts on timing, but you’re correct. Under the regulatory framework in Oregon, it is a 10-month window. So if we want rates to go effect immediately on January 1, a filing would need to occur by the end of this month. We continue to sort of finalize our thinking and approach and we’ll obviously communicate that as we have it. As I mentioned previously, there are certain items putting weight on the scale, of the batteries coming online and some other items that we would expect, needing more time to recover.

Unidentified Analyst: Okay. Thanks, guys.

Operator: Thank you. One moment for our next question. Our next question comes from Julien Dumoulin-Smith with Bank of America. Your line is now open.

Julien Dumoulin-Smith: Hey, good morning team. Thank you guys very much for the time. Hey, Maria, thank you. And just a follow-up — just following up on the latest from the Oregon PC, just on the rejection of the clean energy plan. I just want to understand a little bit, right? Because obviously, this is sort of partial short-term versus long-term. What message are they trying to send here about the 100% target, especially relative to affordability. And I’d love to get in your words, a sense of breaking out of the different pieces that are ongoing? And then I got a follow-up quickly.

Maria Pope: Sure. No, it’s a great question. And first of all, this is our first clean energy plan. And I want to acknowledge and recognize that our integrated resource plan was acknowledged and we are moving forward under that IRP. There are questions really had to do around more granular admissions modeling. We have been doing day-by-day admissions modeling and they like to see hour-by-hour emissions modeling. Overall, as you’ll also remember, our original IRP had — was upsized in July quite significantly for additional energy needs as well as additional capacity needs. And I think there’s more discussion among stakeholders and key constituents around how we’re going to meet the additional needs with additional renewable energy and other infrastructure. So it’s a good time to have healthy discussion around what is a really dynamic and rapidly growing environment here.

Julien Dumoulin-Smith: Yes, it’s certainly. And just to make sure I’m understanding the key takeaway here. I mean it seems like there’s a broader question about like how you meet the 100% in terms of maybe there’s a need for more, again, because I know that at times, there’s been an acute focus on affordability here and perhaps enabling and ensuring that there’s a pathway for affordability. I just want to make sure I’m hearing clearly what direction this rejection on the long-term came from.

Maria Pope: It came from a need most clearly for additional emissions modeling, Julien. But the back story here is that we’re seeing pretty significant changes to the upside of energy usage and wanting to really understand the sources of the economics of all of those procurements. As we bring on renewable resources and Clearwater would be a good example, we’re actually not seeing customer prices, react we’re displacing higher purchase energy in the market. And so the additional renewables procurement is actually not driving customer prices as much as one would think as we model it forward. It’s the overall need for investment and aging infrastructure and supporting significant customer growth that is driving customer prices as we move forward, more than clean energy development.

Joe Trpik: Right. And actually to that point, I mean, you have a dramatic increase here in transmission, and that’s not necessarily surprising given what you’ve been telegraphing in recent periods about the need for transmission. But can you maybe frame out — I mean, how do you think about sort of upside generation given the new level of spend tied to especially transmission here? I mean should we continue to think about this as being incremental? Do you have a shift in how you think about allocating capital to generation here? I mean I know that you’re reaffirming 5% to 7%, but at times, perhaps there’s been sort of a ceiling on how much you want to push your core rate base considering all the various needs. Is there a push out potentially here in terms of some of the investments? Or really, do we — should we consider this as truly incremental upon incremental opportunities?

Maria Pope: Sure. I mean we have to always keep customer prices first and foremost. There’s no question that we have seen customer price pressures, and we are very attuned to the interest of our customers and keep making sure that affordability stays first and foremost. One of the reasons that we have competitive RFPs for renewable generation capacity and energy is to get the very best prices for customers in competitive processes. We have done well in those processes in the past, and we hope to continue to be able to deliver the lowest cost, least risk clean energy resources to customers that is marketdly available. With regards to transmission, there is some flexibility. Some of these transmission spend was in our historic run rate.

Some is new and incremental. We think of this sort of as concentric circles. The first circle being within our service territory really directly being impacted by customer growth. The second is to bring clean energy from our area or just adjacent to our areas to our customers. And then the third is broader investments across the Northwest. One of the big increases as you look further out on the chart in 2028 is the Confederated Tribes of the Warm Springs project on our existing [indiscernible] line where we received a $250 million Department of Energy grant to significantly upsize that existing line, most of which will continue over existing rights of way. So if we look at transmission, we’re focused on relatively easy to execute and my colleagues would probably question that transmission is ever easy to execute, but relatively lower risk projects within our service territory focused on repowering and increasing existing rights of lines.

Julien Dumoulin-Smith: Wonderful. Excellent. And just quick housekeeping on the ITC here, if you don’t mind. Just for the battery, is that going to be reflected like in a single year here or over 5 years? Or how do you think about the accounting for the ITCs here real quickly, again sort of a novel subject in storage and regulated land?

Joe Trpik: So, good morning, Julien. So from a standpoint of recognition, as the battery comes online, we’ll recognize those ITCs, and we would expect since we have 2 batteries that will be coming in over ’24 and ’25, that will recognize those ITCs, what I’ll call it to the balance sheet, the customer is receiving the benefits of those ITCs that we’ll lay out in our next regulatory filing that will be amortized to them. Julien, I think when you get to the real question is once we put them on the balance sheet, the expectation is that we will monetize them somewhat shortly thereafter. So as we recognize them and they have the certainty of the ability to transfer, we will be looking to monetize it.

Julien Dumoulin-Smith: Got it. Pretty concurrently. Got it. Excellent. Thank you. that will flow through the income statement?

Joe Trpik: The monetization will flow through as a cash flow, right, from the purchase and sale of the ITCs income will be income statement neutral to us.

Julien Dumoulin-Smith: Okay. Thanks for that color. I appreciate it.

Operator: Thank you. One moment for our next question. Our next question comes from Gregg Orrill with UBS. Your line is now open.

Gregg Orrill: Yes, thank you.

Maria Pope: Good morning, Gregg.

Maria Pope: Thank you. Good morning. With regard to the rate case coming up, do you have any sort of early thoughts on level of rate increase or sort of thoughts on affordability heading into that?

Joe Trpik: Hey, Greg. Good morning. Obviously, we start our case here always thinking about affordability to the customer, also considering we’ve had a previous case here. We — I would expect, in this case, truly the focus is going to be on the batteries, the assets that have been put in service to continue to advance both reliability, expand capacity on the system as well as small amounts of cost. I mean I think this will mainly be truly just an infrastructure update to the plan focused on affordability.

Gregg Orrill: Got it. Thank you.

Operator: Thank you. Our next question comes from Paul Fremont with Ladenburg Thalmann. Your line is now open.

Paul Fremont: Thank you very much and thank you for taking my questions. I guess my first is given the storm deferrals for January, is that something that you would be looking to recover in the rate case that you’re filing currently? Or would that fall outside the purview because of — it’s too recent?

Joe Trpik: Good morning, Paul. So the storm recovery actually will fall through two separate processes than the general rate case. They’ll both be existing mechanisms. So the — as it relates to the operating costs, sort of and the reconstruction costs, those will come through a deferral rider that will be filed and will have its own proceeding, which is — and then the — as it relates to the cost of the energy and the RCE event, that will go through the PCAM process. Each will have a bit of a different time frame. For example, the PCAM process would not be filed until 2025 with the recovery of that, that would work itself into 2026.

Paul Fremont: And then the timing on the OpEx recovery, does that — would that normally occur within a year’s time or shorter than that?

Maria Pope: That recovery will be up to discretion with the commission. Normally, these storms are recovered over due to their magnitude and the significance over an extended period. The last time we had a storm recovery of this nature was recovered over 7 years. And what we will also — to just — I would say, we’ll also look through the eligibility for either of these for securitization, which will obviously can change the recovery stream as well.

Paul Fremont: Okay. And then looking at the higher base CapEx, how should we think about that relative to your bidding into the renewable RFP? Would you be looking to win less in the RFPs given sort of the magnitude of the CapEx increase? Or would there be sort of no change in terms of your business strategy?

Maria Pope: So our bidding strategy today, our bidding strategy going forward and our bidding strategy in the past has always been the same, and that is to have the most competitive projects for the least cost and least risk for customers. And those projects are winners, they’re good for customers, and they’re good for financing.

Paul Fremont: Okay. And then it looks like there’s a $200 million to $300 million annual increase in CapEx each year. Should we look at the incremental amount of spending as being funded roughly 50% with equity? Is that sort of a fair way to think about the financing?

Joe Trpik: I think when we look to the long-term financings here, we continue to look to over sort of using flexibility, manage our capital structure, continue to move towards 50-50. So assumption that over time, you’d say that would be looked at that balance level, it would be a reasonable way to look at it.

Paul Fremont: Great. And then my last question is a big step up, I think, in transmission and spend in ’28. And I was just wondering what — sort of what’s the explanation of that.

Maria Pope: Sure. That’s the — an answer to Julien’s question earlier, that’s the Pelton [indiscernible] to 230 — planned to be increased to 500 kV in partnership with the confederated tribes of the Warmer Springs. We previously announced a $250 million grant for that work from the Department of Energy. Obviously, that project would cost more than $250 million. It’s over 100 miles long, and it would be a multiyear project, the first year we’re anticipating in 2028.

Paul Fremont: So would the level of transmission spending sort of stay at that higher level for several years?

Paul Fremont: Probably for a couple of years after that in 2029, 2030. The transmission line and the increase also opens up a good portion of the central part of Oregon for additional renewable development in partnership with the tribes. We currently co-own several hydro facilities with them. And so this will allow for a significant expansion, particularly of solar energy, but really making the central part of Oregon and the Confederated Tribes of the Warm Springs Reservation, an opportunity for further development through 2028 and beyond.

Paul Fremont: And then my last question, with sort of the step up in CapEx, what type of rate base does that give you on a percentage basis through ’28?

Joe Trpik: So Paul, in the sort of the sister document that we also filed this morning, for the base capital, which includes the transmission, which includes the line that Maria just mentioned, that would put us at right around an 8% rate base growth. And then we’ve also, in that update, made some scenarios regarding an [indiscernible] outcome and in that update would put you with a 25% outcome, would put you at a 9.2% rate base through ’28.

Paul Fremont: Great. Thank you.

Operator: Thank you. [Operator Instructions] Our next question comes from Travis Miller with Morningstar. Your line is now open.

Travis Miller: Thank you.

Maria Pope: Good morning, Travis.

Joe Trpik: Good morning, everyone. Quick question on the battery stuff. That increase in the 2024 number, is that incremental projects? Or is that some kind of carryover spending from 2023?

Nick White: Specifically, as it relates to the battery, that is the 2021 RFP moving out. In fact, the battery spend you see in ’24 and ’25 was all existing from that RFP, and it is the — the first set of spend is more than — its a console project or the smaller battery and then the spend that goes into 2025 is the seaside battery, which is the larger one.

Travis Miller: Okay. I was thinking about the comp from the previous capital update which was, I think, $100 to something million to $235 million.

Travis Miller: Got it. Okay. These are the same batteries. We have not added any projects. This is the update to the pricing for those same batteries.

Maria Pope: So there were some payments that went from 2023 to 2024.

Travis Miller: Got it. Okay. Okay. Yes. That’s what I was thinking. And then related on that, how much of the battery specifically, CapEx in those payments do you anticipate you’ll be able to get into the rate case given that — and correct me if I’m wrong, given that they’re probably not going to be done, right, operational in the next [indiscernible].

Joseph Trpik: When we update the — so when we do the filing, the filing will look — we’ll use a future amount of rate base. So we’ll use an end of 2024 rate base. And we will — when we decide to file, we will place a structure in there that would expect recovery of the batteries on their in-service date. The first, the [indiscernible] battery, which has an in-service date somewhere right around at the end of 2024 and then also then the seaside battery that goes in service in 2025. As you may recall in our prior case and when we file, whatever we file our next case, we will address the RAC or the renewable adjustment clause that allows for renewables to go into service, we previously had requested that batteries get included there. So they just automatically go in service. We will again look within our filing to address that policy as well as potentially consider other policies to ensure that the batteries are timely into service similar to other renewable assets.

Travis Miller: Okay, great. That’s really helpful. And then a different question. Given the increase in the capital spending and your comments around trying to get back to the certain capital structure, what does that mean for the dividend growth do you anticipate?

Joe Trpik: Our expectation is, as we continue to grow, we are committed to drawing the line as it relates to our 5% to 7% earnings growth and that similar dividend growth. So we have no expectation of changes in our dividend growth rate off of our previously communicated plan.

Travis Miller: Okay. In line with earnings?

Joe Trpik: That’s right.

Travis Miller: Okay. That’s all we had. Thanks so much,

Maria Pope: Thank you.

Joe Trpik: Thank you, Travis.

Operator: Thank you. One moment for our next question. Our next question comes from Willard Grainger with Mizuho. Your line is now open.

Maria Pope: Good morning.

Willard Grainger: Hi. Good morning, everybody. Good morning. Just a question, sort of coming back to the equity, I see in the balance sheet debt to cap, you finished 2023 with around 56% debt to cap. When do you think you’ll be closer to the allowed 50% that you got in the last rate case? Thanks.

Joe Trpik: Sure. Good morning. Good morning, Willard. So we look to — as we built the 5-year plan, we’ve considered a path that will get us towards that 50% over that period with some flexibility on the timing in between peers considering the RFP or considering how with and without RFP scenario. So we have sort of a series of flexible strategies that will work us there over what I’ll call these longer planning.

Willard Grainger: Understood. Thanks for the clarity. And then maybe just thinking about the battery storage, is that something that you’d likely see more of with some of the load growth? Or do you think that the generation spend is more geared towards traditional renewables?

Maria Pope: Well, I think we’ll see both. Clearly, capacity is important as we — in particular, with all of the volatile weather that we’re seeing. So I think you’ll see additional batteries coming through, through RFPs. And I think you’ll also see more traditional renewables of wind and solar. There are also some pump storage projects and some other projects that are farther out that independent power producers have been working on. And so I think this is going to be what I call, all about a set of solutions as we move forward. We are also working very closely with customers on their energy usage and flexibility as well as standby generation to bring all of the resources to bear through this transition.

Willard Grainger: Thank you. I will leave it there. That’s super helpful.

Maria Pope: Thank you.

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: Great. Thank you very much. We appreciate your interest in Portland General Electric. We are excited about 2024, our continued growth in high tech digital customers. Our capital plan to support that growth in renewable development as well as our continued focus on operating costs and operational excellence. We look forward to connecting with you soon, and thank you very much for joining us today.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.