Title

Presentation

Edison International beats earnings expectations. Reported EPS is $1.51, expectations were $1.38.

Operator: Good afternoon, and welcome to the Edison International Third Quarter 2024 Financial Teleconference. My name is Sheila, and I will be your operator today. [Operator Instructions]. Today’s call is being recorded. I would now like to turn the call over to Mr. Sam Ramraj, Vice President of Investor Relations. Mr. Ramraj, you may begin your conference.

Sam Ramraj: Thank you, Sheila, and welcome, everyone. Our speakers today are President and Chief Executive Officer, Pedro Pizarro; and Executive Vice President and Chief Financial Officer, Maria Rigatti. Also on the call are other members of the management team. Materials supporting today’s call are available at www.edisoninvestor.com. These include our Form 10-Q, prepared remarks from Pedro and Maria and the teleconference presentation. Tomorrow, we will distribute our regular business update presentation. During this call, we’ll make forward-looking statements about the outlook for Edison International and its subsidiaries. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our SEC filings.

Please read these carefully. The presentation includes certain outlook assumptions as well as reconciliation of non-GAAP measures to the nearest GAAP measure. During the question-and-answer session, please limit yourself to one question and one follow up. I will now turn the call over to Pedro.

Pedro Pizarro: Well, thanks, Sam, and good afternoon, everyone. Edison International’s core earnings per share for third quarter 2024 was $1.51, bringing year-to-date core EPS to $3.88. With this strong year-to-date performance, we are confident in narrowing our 2024 core EPS guidance to $4.80 to $5. Additionally, we remain confident in our ability to meet our 2025 EPS guidance and delivering a 5% to 7% EPS CAGR through 2028. My remarks today includes three important takeaways. First, SCE continues to demonstrate its ability to navigate the regulatory landscape and is in the final stages of two key regulatory proceedings, reaching a settlement agreement in the TKM cost recovery application and awaiting a proposed decision in the 2025 GRC, which will solidify our financial outlook through 2028.

Second, our team has achieved remarkable success over the last years managing unprecedented external risks, making our operations more resilient and positioning us strongly for the growth ahead. Third, we recently reaffirmed our net zero commitment in our latest white paper. Reaching net zero greenhouse gas emissions by 2045 is a core pillar of our climate-related risk management. Starting with a couple of constructive updates on the regulatory front, SCE is in the final stages of resolving the legacy wildfires. We have provided an update on Page 3. You saw that in August, the utility reached an agreement with Cal Advocates to settle the TKM application. Once approved by the CPUC, the settlement would authorize recovery of 60% of the costs, or $1.6 billion.

This settlement marks a significant milestone and is a good compromise all around. Customers and the state benefit from the demonstration of a strong regulatory framework and constructive negotiations with intervenors, as do you, our owners. It is also another clear indication of the utility’s ability to navigate the complex regulatory landscape. SCE recently filed the Woolsey cost recovery application, which we expect to take about 18 months to complete. SCE made a strong case supporting the prudency of its operations and the claims settlement process. But with the proceeding just underway, it is premature to speculate about the ultimate outcome. As a reminder, we have not factored cost recovery for these legacy events into our earnings targets, thus the TKM settlement and the eventual outcome in Woolsey will be additive to our core operational growth.

SCE’s rapid response to mitigate wildfire risk also resulted in numerous regulatory applications. These included 2021 GRC tracks 2 and 3, a couple of WEMA applications, several CEMAs, three AB 1054 securitizations, and several others. SCE has achieved strong regulatory outcomes, recovering substantial amounts of prior spending in rates and expecting another $3 billion of incremental cash flow over the coming years. Upcoming on the regulatory calendar are decisions on the TKM settlement and the 2025 GRC, both of which we believe could happen in the first half of next year. The decisions will solidify our financial outlook through 2028. Capital investment enabled by the GRC is the driver for the growth and customer benefits necessary to ensure the grid is reliable, resilient, and ready to achieve the clean energy transition.

We are confident in getting a strong outcome for SCE’s customers that will also enable us to deliver on our commitment of a 5% to 7% EPS CAGR through 2028 with minimal equity needs. Staying with the California regulatory environment, a couple of weeks ago, the Commission changed the cost of capital mechanism and the investor-owned utilities’ 2025 ROEs. While it only applies to 2025, we believe the decision is unfortunate and the process was disappointing. That said, this is just one of numerous business and regulatory outcomes that we manage in delivering on our commitments. I reiterate our confidence in delivering on our 2025 EPS and long-term EPS growth commitments. Moving on to SCE’s core operations, I am proud of our team’s ability to manage unprecedented climate challenges and navigate the numerous associated regulatory applications over the last several years.

As you can see on Page 5, we have made remarkable strides in reinforcing our operational resilience and financial stability. Our robust performance is a testament to our strategic initiatives and the dedication of our workforce, my teammates. To address the climate challenges, you have seen the results of SCE’s industry-leading wildfire mitigation plan for several years now. Wildfires will always be a part of California, exacerbated by climate change, and the number of acres burned so far this year is roughly in line with the five-year average. What is important, though, is that SCE has adapted its operations and managed the risk. To drive this point home, Page 6 shows the significant reduction in acres burned from SCE’s ignitions in high fire risk areas since 2017, and that this has happened while ignitions have been relatively flat, despite several of these years having been extremely high fire risk periods.

This is due to SCE’s strong wildfire mitigation plan execution and increased state fire suppression. Importantly, none of the ignitions are from the failure of covered conductor, the cornerstone of SCE’s grid hardening strategy. Now, with more than 6,100 miles of covered conductor deployed, SCE has physically hardened 85% of its distribution grid in high fire risk areas. Consequently, SCE’s grid is more resilient, reliable, and well-positioned to focus on the growth ahead as we lead the clean energy transition. California will also continue to benefit from improved state fire suppression support and as other utilities in the state increase their grid hardening action. Moving to the bigger picture, wildfires are just one way that climate change is impacting California’s health, economy and quality of life.

Edison International is acting to create a safer, more affordable future with cleaner air and reduced risk of climate disasters. Reaching net zero greenhouse gas emissions by 2045 is a core pillar of our climate-related risk management. We recently unveiled our latest white paper, Reaching Net Zero, which builds on our previous analysis of what is needed for California to reach carbon neutrality. The publication focuses on Edison International’s net zero plan and reaffirms our net zero commitment. As you see on Page 7, this plan is centered around delivering 100% carbon-free power to SCE’s customers, as 85% of enterprise-wide emissions are associated with power delivery. In addition, we will reduce operational emissions, primarily by reducing those from the supply chain.

Lastly, we project about 2 million tons of emissions will remain across all scopes in 2045. To fully decarbonize, we will need to neutralize those emissions, preferably through high-quality carbon removal solutions or offsets. As always, we take a pragmatic approach to our analysis and findings. A key point of emphasis is that the state will need substantial deployment of clean firm generation to safely, reliably and affordably supply power 24/7 in any weather. So one of the big, and maybe surprising, conclusions is that California must retain its existing natural gas generation fleet as insurance against delays in new technology development and deployment, though the generators will run significantly less often. The bottom line is that to reach net zero, nearly every sector of the economy will need to incorporate clean electricity.

It will take much investment and cooperation between industry and government. The effort will be worth it for customers who will see a projected 40% reduction in their total energy costs by 2045 With that, let me turn it over to Maria for her financial report.

Maria Rigatti: Thanks, Pedro, and good afternoon. In my comments today, I would like to emphasize three key financial messages. First, we are very pleased with EIX’s year-to-date financial performance, which reinforces our confidence in delivering yet another year of solid results. Second, on the regulatory front, SCE continues to generate cash flow by recovering past costs tracked in memo accounts and is making strong progress through the final stages of resolving the legacy wildfires. Third, we remain confident in our ability to deliver on our commitments for 2025 and beyond. I will note that we plan to update our projections next year following a final decision in SCE’s GRC. Let’s start with a brief review of our third quarter results.

EIX reported core EPS of $1.51. As you can see from the year-over-year quarterly variance analysis shown on Page 8, core earnings grew by $0.13. This EPS growth was primarily due to higher CPUC revenue authorized in Track 4 of the 2021 GRC and higher authorized rates of return. Partially offsetting these drivers was higher interest expense associated with debt for wildfire claims payments. EIX Parent and Other was in line with the same period last year. Our quarterly results bring year-to-date EPS to $3.88, and this strong performance is largely driven by O&M, benefitting from a combination of efficient execution and timing. Pages 9 and 10 show SCE’s capital and rate base forecasts, which are consistent with last quarter’s disclosures. We expect our next major update to the capital plan will follow a final decision in SCE’s 2025 GRC.

In addition to the capital investment supported by the GRC, the utility is working on the standalone application for its next generation enterprise resource planning system, which is expected to be filed in the next six months. Further, SCE expects to file the advanced metering infrastructure 2.0 application toward the end of 2025. Combined, these represent over $2 billion of CPUC-jurisdictional capital investment. SCE also has more than $2 billion of FERC transmission projects in development. Both the incremental CPUC and FERC spending are upside to our current capital plan. Turning to Page 11. Following strong regulatory outcomes in recent years, SCE has recovered about $4.5 billion since 2021. In this quarter’s update, you will notice one new item, the securitization that we expect will follow approval of the TKM settlement agreement.

After a final decision on the settlement, SCE will file an application to request approval to securitize the $1.6 billion recovery, targeting completion of a financing by year-end 2025. In total, the cash flow already received and expected over the next couple of years significantly strengthens our balance sheet and credit metrics. Not only that, but we should also see the amounts recovered through memo accounts decline over time as these activities are built into SCE’s GRCs going forward, simplifying the regulatory process. I would now like to expand on the status of fully resolving the legacy wildfires. SCE has now received demands for 95% of TKM and 94% of Woolsey outstanding individual plaintiff claims and the utility continues to work swiftly to resolve them.

Under the settlement agreement, the same 60% recovery ratio will apply to the remaining TKM costs, net of a previously agreed to disallowance. For Woolsey, SCE also proposed a process to recover claims paid after the date the application was filed. The best estimate of total losses remained unchanged this quarter as additional settlements have been in line with expectations. Turning to EPS guidance, Page 12 shows our 2024 core EPS guidance and modeling considerations. We are pleased with our very strong year-to-date performance which also gives us the opportunity to continue pulling forward O&M for the benefit of customers. With nine months of results behind us and based on our outlook for the remainder of the year, we are very comfortable with narrowing our EPS guidance to $4.80 to $5.

Turning to Page 13. We have refreshed the modeling considerations for 2025. I’ll note a couple of items. First, we’ve updated rate base EPS to reflect the CPUC decision on cost of capital that Pedro mentioned. Secondly, continuing the trend, we see favorable cost management flexibility, driven by the pace of O&M reinvestment and financing benefits. Lastly, I want to emphasize that we have not incorporated the benefits from the TKM settlement agreement into this refresh, which would be incremental to our forecast. I will now discuss the plan for updating our guidance and long-term outlook. At a macro level, let me note that the moderating interest rate environment removes the financing headwind we have faced in recent years. Additionally, cost recovery in the legacy wildfire proceedings provides a tailwind.

Looking at our core operations, SCE’s GRC is the driver for our high-quality earnings growth. As Pedro mentioned, we are hoping to see a CPUC decision in the first half of next year. Once SCE gets a final decision from the CPUC on the GRC, we will update our capital plan, financing plan, 2025 EPS guidance and EPS growth forecast, factoring in the TKM settlement. So what gives us confidence in achieving our 2025 core EPS guidance of $5.50 to $5.90 and growing earnings by 5% to 7% through 2028? There are two key factors. First is the strength of SCE’s GRC and progress throughout the proceeding. SCE made a strong case and even based on intervenors positions, SCE’s rate base growth would still be in line with its range case forecast of 6%. Second is our ability to manage the numerous variables in the business, as we’ve demonstrated year in and year out over the last two decades.

Additionally, it is important to reiterate that our guidance does not incorporate the upside from the TKM settlement. As you saw on Page 3, that total upside to 2025 core EPS is about $0.44, and the ongoing annual benefit beyond 2025 is $0.14. I’ll conclude by saying that our strong financial discipline enables us to deliver not only on our financial targets, but also to continue SCE’s cost leadership for customers. Given that affordability is a key component of the clean energy transition. That concludes my remarks, and back to you, Sam.

Sam Ramraj: Sheila, please open the call for questions. As a reminder, we request you to limit yourself to one question and one follow up, so everyone in line has the opportunity to ask questions.

Operator: [Operator Instructions]. Our first question will come from Mike Lonegan with Evercore ISI. Your line is open.

Michael Lonegan: Hi. Thanks for taking my question. So on the general rate case, I was just wondering if you could share your latest thoughts on it in the context around affordability concerns in California. We’ve seen the change in formula for the cost of capital trigger mechanism and a proposed decision in SDG&E and SoCal Gas rate case that cut attrition to your revenues?

Pedro Pizarro: Yes. Thanks, Michael. Appreciate to having you on the call. And let me start by reminding folks of the comments we’ve made in other places. As we look at the rate trajectory for Southern California Edison, we I think said in the last quarter, we see that going back to levels at or below local inflation from ’24 onto ’28. So we think affordability is key. We are fortunate that the increases embedded in the general rate case are offset by a number of other items so that we can end up delivering that around inflation performance in terms of rate trajectory over the next several years. Looking beyond that, the point that I made quickly in my remarks, and I know we stress at other times is that as we look at the continued investments needed over the longer term, beyond our 2028 guidance period for driving the clean energy transition, we see those continuing to put pressure likely around inflation levels for the electric rates.

We see electric bills increasing because people will be using more electricity. But as you look at the total energy bill of electric plus gasoline plus natural gas, we see that total bill for our average customer going down 40% in real terms to 2045. And importantly, their share of wallet, the amount of their household income that they’re spending on the total energy bill, which today is 7% goes to 3% in our analysis by 2045. So all of those in, I can give you a near-term answer and a long-term answer and both are important as we make the case and help educate our customers and our policymakers.

Maria Rigatti: Yes. Michael, maybe I’ll just add on a little bit. So you definitely referred to affordability being a theme. And you’re right. Every rate case is different, every proceeding is different, but that affordability theme is consistent through all of them. When SCE filed its application, it had that affordability lens in everything that it asks for and all of its justification. In fact, they introduced savings into the GRC that they had already accumulated between GRC periods. I think one really important factor to note is that even intervenor positions in response to our application still have about a 6% growth rate on rate base. So we’ve had this focus on affordability for a long time. We’ve integrated it into our rate case, and we think you’re seeing that sort of responsiveness from interveners and we’ll get the general rate case decision as we noted early in the first part of next year.

Michael Lonegan: Thank you. And secondly from me, you’ve been talking about load growth materializing sooner than expected. You’ve mentioned potentially reprioritizing CapEx in the GRC or pursuing alternative funding approaches through separate applications. Just wondering what your latest thinking is around this.

Pedro Pizarro: Well, we have the benefit of having repaired the GRC forecast in a time period when we’re already seeing some of that acceleration in load. And so I think that as we look at certainly 2025, we have a good beat on what is needed. As we look into the later years of the rate case, we’ll see, first and foremost, what final decision we get and what capital levels embedded in there. We continue to have the ability to reprioritize capital to deploy it against the most pressing needs. And if we were to determine later on that we need more capital support beyond the GRC decision. There’s a couple different avenues. And including the SP410 mechanism or mechanism in the rate case process. And it’s come up in the high distributed energy resource proceeding. So a couple of different avenues. But right now, I think we’re focused on continuing to press for a good rate piece outcome and prioritizing from there. Anything to add Maria or Sam?

Michael Lonegan: Thanks for taking my question.

Operator: Thank you. Next, you will hear from Shar Pourreza with Guggenheim Partners. You may proceed.

Shar Pourreza: So, Pedro, just in terms of the TKM settlement, beyond the $0.14 of run rate EPS improvement, does kind of the balance sheet flexibility from the memo account recovery plus TKM leave room for taking out some of the — maybe the equity-like instruments that were supporting wildfire claims like the prefs and the junior subordinated. So your metrics are improving. Could you take down some of the equity? Would that be accretive to sort of your plan right now?

Maria Rigatti: Shar, thanks for the question. Yes. So I think, first and foremost, we have the framework of 15% to 17% FFO to debt. I think the first thing that we would look at is the $100 million a year of equity that we’ve said is in our plan because as long as we’re solid on the balance sheet, that might not be necessary. As we move forward in time, we will be looking at the hybrids. I think those don’t actually really come into play until ’26 and then even beyond that. But that’s definitely an opportunity that we will be looking at.

Shar Pourreza: Got it. Incremental to the plan, right? So that’s not something that you’re embedding in the plan right now.

Maria Rigatti: Yes. We’ll take a look at that as we get closer and closer to those reset dates.

Shar Pourreza: Okay. Great. And then as you guys note, the assumption changes for ROE in ’25 in the slides, can you clarify if the offset in operation variance is driven by pulling back some of the reinvestment that was originally planned how much of the financing benefit that you’re kind of calling out contribute to that $0.20 positive there?

Maria Rigatti: Yes. So when we obviously got the final decision on the ROE, we wanted to update the rate base math for that. That’s something that we’ve done in the past few cycles because since we’ve given this guidance, we’ve gone through a number of cost of capital situations. At the same time that we did that, we thought it would be a propria to update sort of those high-level modeling considerations that we provided. But remember, those are high-level considerations. We operate the business at a much more granular level. So we took a look at many, many things and many, many factors across the business. One aspect of what we did was we looked at financing costs. We put those assumptions out there a number of years ago. We’ve obviously worked through a number of different interest rate environments at this point, both in terms of the underlying rates as well as spreads.

And we do see cost benefits across the board, including in the operational variances area but across the other elements as well. The other thing that we looked at, which is really a lever that we have every year is that reinvestment rate. I mentioned earlier that even in 2024, we have the flexibility to pull forward O&M costs into 2024 to the benefit of customers, and that gives us further flexibility as we move forward. Did the same thing with 2025. We’re not quantifying every penny down to the net, but I think that, that’s the sort of work that we did as we went through the process for the quarter.

Pedro Pizarro: And I would just stress, Maria, you covered it well. Shar, hopefully, you walked away with a sense of our commitment to managing the business well for our customers and meeting our commitment to all of you around our 2025 and 2028 targets.

Shar Pourreza: Perfect. No, that’s loud and clear. I appreciated that. Thank you. See you in a couple of weeks.

Pedro Pizarro: Thanks, Shar. See you soon.

Operator: Our next question will come from Anthony Crowdell with Mizuho. Your line is open.

Anthony Crowdell: Hi. Good afternoon, Pedro. Good afternoon, Maria. Just I guess two quick questions. I think you talked about giving — or providing an update once you get a GRC decision in ’25. At that time, do you think we’ll have clarity on TKM and Woolsey and the update you provide will incorporate GRC plus the two wildfire proceedings?

Maria Rigatti: So, the schedule for TKM and the GRC we’re thinking in the first half of the year. So hopefully, we’ll have the ability to do both incorporate both of those Woolsey, it’s early in the product, Anthony. I think we just filed the application relatively recently. Interveners having filed their response that will bring us through — we won’t have a prehearing conference until later this year. So, we’re going to work through the process. But what I want to emphasize is the same way that we treated TKM where we weren’t incorporating any benefits from a settlement or a litigated process until we saw it happening and we get a decision. Same thing for Woolsey. I think it’s just much more straightforward if we keep that out and you’ll just see the strength of the underlying business in our numbers.

Anthony Crowdell: Great. And my last question, maybe challenging to answer, but just some of the investors were concerned as the change in the cost of capital happens in year three — three-year mechanism that we thought was kind of set, even though there wasn’t a triggering event. And as you look forward to the next cost of capital period or a cycle, I guess the right word, I mean how do you give investors assurances that we may not see another mid-cycle change? Again, we don’t know what happens on the macro environment, whether it’s a cost of capital trigger. But just the uncertainty that this was really a unique event and that we shouldn’t expect something mid-cycle unless there was a trigger going forward?

Pedro Pizarro: Anthony, let me start on that one. And I’ll take a bit of a broader aperture on it. I mean, you did hear me say in my comments that we were disappointed with that specific decision. But then we put it in the broader context of the regulatory environment in California, right? And so I know as I sit down with investors, and talk about this, I always point to making sure we’re looking at the whole broad picture of the framework here. And the remarkable strengthening of the framework we have lived through over the last half decade, right? And so when you think about when the wildfire period started and the uncertainty around that, and you saw us work through that, you saw the state work through that. And importantly, you’ve seen the CPUC work through implementation of AB 1054.

You’ve seen the CPUC work through a number of other proceedings. Maria talked about the past number of memo accounts where we’ve been recovering cash from them. We got a number of things that have been highly constructive in this environment. And I’m not a big sports guy, but since baseball is a big thing right now, nobody bats 1,000, right? And so you’re going to get a few misses here and there. But I think overall, we’re seeing a CPUC in a state that is committed to having a robust regulatory framework that maintains the financial health of utilities. It gives certainty to investors. We’re going to disagree a few of the things that they do, and that’s a bit of light. But we would expect as we turn to the ’26 to ’28 capital proceeding, I think you’ve seen the table set in terms of some clarity and what came out of ’25, we will come in with very strong arguments for why we see a continued need for the California premium that has been supported over the last couple of decades, and we’ll take it from there.

And in the meantime, we’re going to be looking for constructive regulation out of the general rate case decision. You saw the very constructive set outcome with call advocates on the TKM settlement. So again, a number of other proof points around the continued strengthening of the environment here. And since I said use sports analogy, which I really do. But since I know a number of you are in New York at the risk of Imperia what you’re right about us, go Dodgers.

Anthony Crowdell: Thanks so much for taking my question, Pedro, and see you in Hollywood.

Pedro Pizarro: Take care.

Operator: Our next question will come from Steve Fleishman with Wolfe Research. You may proceed.

Steven Fleishman: Thank you. Ouch, Pedro.

Pedro Pizarro: Sorry, man.

Steven Fleishman: That’s all right. So just maybe a little more color on the GRC timing and just because both PG&E and Sempra’s cases kind of went well into the — toward the end of the year. Are you hopeful on timing of first half just because there’s less differential in positions? Or maybe just a little more color on timing. And I guess also, is there a chance to settle more of the issues before we get to an order?

Maria Rigatti: Yes. So Steve, I think as we’ve worked through the proceeding, we’ve seen the ALJ and all the parties meet every deadline. There are a few days here and there where people got extensions, but it’s been very much according to the schedule. At this point, all of the documents are submitted, everybody is finished with their written briefs, et cetera. And we’re really waiting on the ALJ to write the proposed decision. We think that there certainly is time to get a decision in the first half of the year with the other GRCs now sort of moving past or through to resolution. We think that also that helps a little bit with the staffing issues, not everybody works on everything, but it’s always more helpful when you’re clearing that.

So, we do think that the first half of next year right now looks like a reasonable time frame for us. In terms of additional settlements, procedurally, that is actually behind us now in terms of settling different things. These are very complex cases and to have an overall settlement is typically reasonably difficult. But as you know from some of the discussion last quarter, we have settled a number of different items, which helps to streamline sort of what is remaining for the proposed and final decision. So, we do think that we’ve moved through a fair amount of items, but we’ll be waiting for a final decision in the first half of next year.

Steven Fleishman: Okay. And then I guess the one missing piece would be the cost of capital for the next three years, which, I guess, that won’t affect ’25, but just that won’t be decided probably till the end of ’25 for the…

Maria Rigatti: So we will file in March. And typically, the commission has a very long track record of getting those decisions out before the end of the year. So, you kind of know what you’re dealing with as you get into the first year of the three-year cycle. We’re going to file the same kind of cost of capital proceeding we have in the past, which is to really look at all the issues, both from a quantitative perspective as well as a qualitative perspective. And we will be continuing to emphasize the California premium the thing that the commission has talked about in the past as well and they, in fact, coin the phrase because of all the differential work that we — that the IOUs in California do relative to other jurisdictions.

I’ll note, though, that as we think about the longer term, and we’ve talked about the 5% to 7% compound annual growth through 2028. We’ve said that consistently in different ROE environment. And so, it has moved around a little bit over the past few years. Some have been less than where we are today, some have been more than where we are today. We’ve given some sensitivity so folks can understand sort of the magnitude change, but we’re confident that we can manage the business along those lines, regardless.

Steven Fleishman: Great. Thank you. Appreciated it.

Operator: Our next question comes from Ryan Levine with Citi. Your line is open.

Ryan Levine: Hi, everybody. A couple of quick ones. In your queue you highlighted that there was a change to the nuclear decommissioning trust estimate to $2.3 billion net to Edison. What drove that and what are the impacts to the financing plan?

Maria Rigatti: Sure. So every three years we do update the cost to decommission that’s part of our regulatory process. And as we do that three-year look, we will be refreshing everything. Some of the things that change are just what’s the expectation about when the federal government will remove the spent fuel from the site? So all of those things go into the mix. The trust fund is very well funded and it does — that change in the decommissioning trust has no impact on our financing plan.

Ryan Levine: Okay. And then maybe a follow-up or related in terms of 2025. Is there any additional color you could provide around the — some of the offsetting items to the cost of capital benefit outside of rate case outcomes?

Maria Rigatti: Sure. So in terms of how we managed through and looked at all of those granular issues, it’s a little bit akin to what I said earlier on the call. So we took a look at, as an example, we had a lot of assumptions built in there around financing plans. And over the past 4 years, the time from which we first announced the numbers to now, we’ve actually done a good job at managing through various interest rate environments. And from a portfolio perspective, we do find that we are doing better than we had originally assumed we would. As we look forward into next year, we don’t have too much left to finance for 2025, but we think that we can manage that as well through both timing of when we go out to market as well as again some more positive expectations about what the market will look like next year.

When we think about more about the levers on the reinvestment side, we are always evaluating the timing and the quantum of what we’re investing in the business. And that can range from anywhere around projects like inspections and maintenance. So can we pull some forward into 2024 things like some telecom enhancements that potentially we can move around and that will create some headroom? And frankly, when we first announced changes related to the increase in the cost of capital, we were accelerating some things into 2025 to create benefit faster in the next rate case cycle. We can manage the timing of that as we like.

Ryan Levine: Thank you.

Operator: Next, we will hear from Gregg Orrill with UBS. You may proceed.

Gregg Orrill: Yes. Thanks. Maybe a detail-oriented question. What’s involved in the next filing for the Generation enterprise resource planning system? And maybe just another question on top of that, just your view in terms of the role of gas in California and how long that would that would be around if you could scale that at all? Thank you.

Pedro Pizarro: Thanks, Gregg. Why don’t we start with Steve on the ERP piece?

Steve Powell: Sure. So our — we call it NextGen, our NextGen enterprise resource planning program is going through its solution analysis right now. And it’s focused on both the technology underpinnings as well as the process changes around work management, supply chain and kind of those major functions across the organization. We’re heading to a point where our current ERP system is nearing its end of life or end of service. And so that’s later this decade. So we’re basically redesigning the next generation of that ERP system to go into implementation. Right now, we’re focused on finalizing the filing with the commission, and so we expect that to come in Q1 as we finish that up.

Pedro Pizarro: And then on the gas piece, Gregg, I think you’re probably referring to my comments on reaching for net zero or reaching net zero. And what our team did here was, frankly, pretty important work because they took a look not just at the normal kind of supply the demand balance picture, but this included some level of power flow analysis. It really goes into how does the system really operate in? How do you make sure that power can flow across a number of conditions? What they saw was that, as I mentioned in my comments, California will need a lot of clean firm generation. So think about resources like next-generation geothermal or could be nuclear over that would require a change in law in California. It could be gas paired with stores with carbon capture and storage, but resources that can run 24/7 or when needed.

And what’s interesting is that 1 gigawatt of those clean firm generation resources gives you the same amount of greenhouse gas emissions effectiveness — of reduction effectiveness at 7 to 11 gigawatts of solar paired with storage. We will have lots of solar and storage, but you need it all. And clean firm generation will be an important part of the picture. The challenge, though, is that a number of those resources are still not mature. They need to go up the technology development and maturation curve. And then you also have the citing and permitting challenges for any resource. So that means that there’s a lot of uncertainty in terms of getting the steel in the ground between L and 2045. In the meantime, we have this big insurance policy.

And it’s all the natural gas generation that currently exists in the state. So part of our message is, particularly as we look at scenarios where we might see even higher load where I see greater delays in the technology deployment and deciding and permitting and construction really important to hold on to the existing gas generation fleet as the insurance policy for those potential scenarios. But again, we expect that those generators, gas generator would be running a lot less than they do today. In our prior analysis, we estimated that California would see something like between 4% and 5% of its electrons coming from gas resources in 2045. Now hopefully, that covers the second question.

Gregg Orrill: Yes. Thank you.

Pedro Pizarro: Thanks, Gregg.

Operator: Our next question will come from Nicholas Campanella with Barclays. Your line is open.

Nicholas Campanella: Hi, everyone. Thanks for taking my question. So I know a lot of questions on ’25 and the variance and cost of capital, and you guys seem well positioned to absorb all this. So just to kind of like tie it up, when we kind of think about ’25 and into like ’26 earnings power? Is it as simple as just adding $0.14 to that 570 midpoint and then growing 5 to 7 off that? Is there anything wrong with doing that? And are there offsets that you would flag that we should kind of consider as we kind of think about ’25 and ’26 pro forma TKM? Thank you.

Maria Rigatti: Yes. So the $0.14 is the run rate. So for sure, that’s additive to anything that we’ve put out there for ’26. The slight variation is in 25 because we don’t know exactly when we’ll get the decision during the year, you could have — you might not have the full year run rate on the $0.14 in the first year, but it is a $0.14 run rate as you get out past that.

Nicholas Campanella: And then just on the TKM, you’ve got 50% recovery. I know that you just started the Woolsey request, but can you just kind of talk about what can make that outcome different than the 50% in TKM, like what are the key things to kind of watch for? Thanks.

Pedro Pizarro: You mean on Woolsey as opposed to TKM?

Nicholas Campanella: Yes.

Pedro Pizarro: Yes. Thanks, Nick. I’ll will stay pretty high level here. But the bottom line answer is they’re very different cases, and this is all very case specific. So we can’t look at the TKM number and assume that, that is, therefore, the number for another fire, whether it’s Woolsey or something else. Just to remind you of a couple of the specifics in TKM, you had two different ignition sources. For one of those ignition sources, we acknowledge that Edison equipment was at issue. We still think that SCE was prudent in its operations, but we know that the spark came from that equipment. For the other ignition point, while there was some investigation report by a fire agency that pointed to Edison, there really wasn’t the evidence there.

We don’t think that, that was correct. But in any case, you have one ignition source that — or a point that’s linked to Edison, one that we don’t think is two fire start, then they merge. That’s a complicated case. Woolsey is different. There’s a single ignition point. Again, we know that it’s linked to Edison infrastructure. Once again, we believe that SCE was fully prudent in its operations, it made that case in its filing, but it’s just different, it’s apple and orange when you’re looking at just for starters two different starting ignition points versus ignition point and this other intricacies and specific items for each of those fires. So long-winded way of going back to what I said at the beginning, case specific for different fires.

Nicholas Campanella: Very fair. Appreciate the time. Thank you.

Pedro Pizarro: Thanks.

Operator: Next, you will hear from Jeremy Tonet with JPMorgan. Please go ahead.

Rich Sunderland: Hi. Good afternoon. It’s actually Rich Sunderland on for Jeremy. How are you?

Pedro Pizarro: Hi. All right.

Rich Sunderland: Just one for me. The $2 billion FERC transmission CapEx and the $2 billion across those two CPUC jurisdictional applications, when you give your plan update next year, any sense of that spend and if it would be right for including in the base plan? And then maybe more broadly, just on the FERC stuff, what is the status of your work on that when do you think you’ll have a sense on timing of when that might be deployed and if you’re going to be funding that? Thank you.

Maria Rigatti: So I’ll let Steve talk about the timing of the FERC and how we’re working towards resolution on that, but just in terms of the updates to the plan first. Typically, what we would do is, as we get close to filing the applications, and we know the quantum and the amount and the timing of the spend better that’s when we would roll it into our plan. And that’s why we haven’t rolled it in yet because we’re still working through all the details. I will note that on the FERC side, much of that will be spent post 2028. But Steve, why don’t you talk a little bit about the details.

Steve Powell: So yes, so in the 2022 through ’23 CISO transmission plan, that’s where Edison was awarded about 20 incumbent projects worth over $2 billion. And generally, those projects are, as Maria mentioned, they come online outside the ’28 period. So most of the spend is going to happen out there. In that same process, there also was a competitive project that Edison won in partnership with Lotus Infrastructure partners. And again, that project is, I think the online data is 2032. And so we’ll be working through the other approval processes with the Public Utilities Commission, design and all the stuff it takes to get transmission built. And so as the types of plans continue to come out with new projects, I think it’s important to note that transmission projects still take a long time, and it’s one of the reasons why we’re also focused on getting site in and licensing improvements to help accelerate this because they are very long time frames to get the projects built that are required really to help meet electrification growth as well as the growth in all the new energy resources that will be needed over the next decade and beyond.

Rich Sunderland: Great. Thanks for the time today.

Steve Powell: Thanks.

Operator: Our next question will come from David Arcaro with Morgan Stanley. Your line is open.

David Arcaro: Hi. Thanks so much. How are you?

Pedro Pizarro: Hi, Dave.

David Arcaro: I wanted to just follow up on the Woolsey process here. Is there a time frame where we might watch for the potential for a settlement? Would that be a year from now in terms of just I’m looking at TKM versus Woolsey, when might those discussions become more realistic in the process?

Maria Rigatti: Yes. So just to give you an overall view of the Woolsey schedule as it exists today, at least our proposed schedule. We would expect that on November 12, that we’ll get protests and responses from interveners, we would get a chance then to apply to that and then a prehearing conference probably in early December. Then we would need to wait for the scoping memo. And that is where you’ll get the more definitive schedule as the ALJ lays it out. We have asked SCE has asked for a single phase with an end date that’s about an 18-month schedule, which is consistent with TKM. We get the scoping memo, the scoping memo would be the place to look for in terms of whether or not the ALJ wants to set aside time for a settlement conference, et cetera, that’s exactly what they did on TKM.

But one of the really important parts of TKM. Obviously, we did file the settlement that we reached with Cal Advocates, but a really important there was developing the testimony, having intervenors participate in that. Cal PA submitted quite a few volumes of their own testimony and setting that stage is really important even as you look forward to either a litigated outcome or a settled outcome. And so that’s really what to be looking for.

David Arcaro: Got it. That’s helpful. Very thorough. I appreciate that. And then I was just curious on the ERP and AMI filings, it sounded like those were coming in the near term, or I guess next roughly six to 12 months. How long would those processes be? Like when would the CapEx end up hitting the plan?

Maria Rigatti: So there would be CapEx in the plan for those projects in this next four years. But even for those projects, particularly the metering project, you’ll see spend beyond 2028.

Pedro Pizarro: And in terms of the length of time for the regulatory process, it’s probably also kind of the standard, call it, 18 months it will take.

David Arcaro: Makes sense. All right, awesome. Thanks so much.

Pedro Pizarro: Thanks, David.

Operator: Our next question will come from Angie Storozynski with Seaport. Your line is open.

Maria Rigatti: How are you?

Agnie Storozynski: Great. So I have a question about data centers. I listened to some interview with you, and you mentioned that California is probably not the place or your services are not the place where you will have those hyperscale data center just purely because those should flock to areas with basically cheap electric rates. But I’m just wondering, if there were to be demand-driven increases in electricity prices in California, how that would potentially impact your CapEx and growth plans. And again, even if it’s not related to AI, some additional growth. So that’s number one. And number two is, you mentioned the argument about the decrease in other nonelectric sources of energy costs for end users. And I’m just wondering if based on the your customer feedback, if that’s how your customers actually look at it that they would actually notice that there would be sort of an offset to the rising electric bill that they’re going to see.

Pedro Pizarro: Thanks, Angie. I’ll do a quick one on both of these. And Steve, you might have more to add. On the data center, say, you’re right. I think we’ve been commenting on this. You probably don’t see the big hyperscale centers. And the way I think about it in terms of AI, we are seeing some impact in California. You probably don’t see the big hyperscale training centers here, right? But you are seeing — we are seeing data center growth, and I think some of these are by AI because the inference centers, the centers that are used to answer the question when you put the question in a search engine. Typically, the providers like having those closer to the load so that you can minimize latency issues. And so we are certainly seeing data center applications in SCs territory.

It’s just — since we already have a fairly large data center presence in Southern California, the percent increase is not as dramatic as what you might see in a state. You’re seeing some of the big hyperscale centers showing up. And Steve, I don’t know if you have more to share there, I think built it — some of that is already built into the 35% increase in the 10-year demand forecast we commented on last quarter. All right. Then on the other point, first, when I talked about the 40% reduction in total energy cost. Yes, Angie, that is driven by really at the core, the fact that the appliances that are being replaced. So when you replace a gas water heater with an electric heat pump water heater or a gasoline automobile with an electric automobile, the physics efficiency work into — sorry, energy into workout efficiency of that is a lot higher, right?

And so that’s the main engine driving an intended driving the 40% reduction in total energy costs. Now you’re asking are your customers seeing that. And I think customers who have made the switch are certainly seeing that. I got to tell you my wife when I went to this one and a half years ago when we electrified our whole home and our natural gas bill drop, we still have a barbecue in back. But we’re not seeing the same store research, and we saw our electric bill go up, but we see the efficiency from the new appliances. I think the broader question is, do customers haven’t made the switch yet understand that. And that’s where CEA is working with other utilities, working with EEI, working with the commission to make sure that we’re getting the right sort of consumer education out there because that’s going to be an important part of the picture as well as the education for contractors for a critical part of the business cycle and making these, particularly the home conversions.

Steve, anything else you would add on this one?

Steve Powell: I’d say that, Pedro, to your point, education is going to be critical because today, our average customer — most of the customers out there don’t look at their electricity, their gas and their gasoline bills together, they show up on different credit card charges and they’re on different bills. And so that’s really the challenges as you see some electric vehicles or electrified in some way, and they see their electric bill go up from that usage — they’re not always correlating it to — and by the way, I don’t see the reductions on other parts of my bill. So one part is the education to make sure customers are thinking about it before they make purchases as well once they’ve actually converted and electrified part of their usage.

The other part is we have to look for ways to more simply bring that provide visibility to it. How do you bring that snapshot together? And that’s something that we have to — we can’t do on our own. It’s something we’re going to have to work with stakeholders as we continue to educate and build this out.

Agnie Storozynski: Okay. But also just like a big picture question. So I understand that there is the big basis for natural gas prices in California versus where we currently sit. But what happens to your growth plan, for example, if there were to be any meaningful pickup in electric — electricity prices, be it demand driven or higher natural gas prices? Do you feel like there is some sensitivity to the growth on the back of potentially sharply higher electric prices?

Pedro Pizarro: I might say this, and again, Steve, you might have a different view on it, to be interesting. But here’s how I say, Angie, the endpoint, I think, ends up being the same, right, because California has made an important and very firm commitment to getting to net zero by 2045. And that’s something that we believe is needed not only in California but more broadly, if we’re actually going to keep the planet at a reasonable overall temperature increase. The way you get there, right, you might see those variations in any given year, right? And so where there is gas prices or energy prices you’re talking about, it could also be if you have a different changes in incentives, if you have impact of different rate structures, a number of factors that can impact folks adoption at least new technologies when they’re gas heater brace and they’re sitting at Home Depot deciding on the electric versus gas as an example.

So you might see some ups and downs along the way, but if the thing is going to remain committed, which I believe it is and must to net 0. And if we build our analysis, which we absolutely do that the most affordable and reliable way to get there is by electrifying so much of the economy, then the endpoint ends up being the same. Now hopefully, it happens by 2045. Does it happen a little sooner or a little later? That’s where you might see some variations depending on what happens in between here and there.

Agnie Storozynski: Okay. Thank you.

Pedro Pizarro: Thanks, Angie. Appreciate the interesting, strategic questions.

Operator: That was our last question. I will now turn the call back over to Sam Ramraj for closing remarks.

Sam Ramraj: Thank you for joining us. This concludes the conference call. Have a good rest of the day. You may now disconnect.