Edison International (EIX) — Q4 2021 Earnings Call Transcript

Thank you, Missy, 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. I would like to mention that we are doing this call with our executives in different locations, so please bear with us if you experience any technical difficulties. Materials supporting today's call are available at www.edisoninvestor.com. These include our Form 10-K, 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 1 question and 1 follow-up. I will now turn the call over to Pedro.

Well, thank you, Sam. Today, Edison International reported core earnings per share of $4.59 for 2021, which exceeded the guidance range we provided on last quarter’s call and was higher than $4.52 we had a year ago. We are introducing our 2022 EPS guidance range of $4.40 to $4.70 and we are reiterating our high confidence in our longer-term EPS growth target of 5 to 7% through 2025. Maria will discuss our financial performance and outlook. In my comments today, I want to address 3 key themes that underpin the double-digit total return potential for EIX shares. I want to start with the tremendous progress and results achieved by SCE in recent years in reducing wildfire risk, and what gives us increased confidence of further risk reduction. I will then highlight our clean energy transformation that is underway and the substantial capital investment opportunities over the next few years to support the state’s goals. Lastly, I will discuss our operational excellence culture that will enable us to deliver greater value for customers, investors, employees, and other stakeholders. All these initiatives, combined with our dividend yield, present an attractive total shareholder return potential and that's before even factoring the increase in our price-to-earnings multiple that we believe is merited today by SCE’s wildfire risk reduction and ongoing utility and government wildfire mitigation efforts. I am extremely pleased to say that the 2021 fire season marks the third consecutive year without a catastrophic wildfire associated with SCE’s infrastructure. This is despite another severe wildfire season and intensifying drought conditions in the state. We believe this illustrates the cumulative effect of SCE’s and the state’s wildfire mitigation investments and practices over the last several years, as shown on Page 3 of the presentation. During 2021, the utility continued its strong execution of its wildfire mitigation plan and in many cases exceeded program goals. In its 2022 wildfire mitigation plan update, SCE reiterated that covered conductor is one of the most effective measures to reduce wildfire and PSPS risks in its service area. As shown on Page 4, several factors contribute to our confidence in the covered conductor program. Further SCE is evaluating the potential for additional enhanced mitigation, including undergrounding in certain areas based on unique factors. Reducing wildfire risk will remain a top priority for the company and this will require significant capital investment, including $2.2 billion over the next two years through the GRC track 1 period. Overall, SCE estimates that its mitigation work through December of last year has reduced the probability of losses from catastrophic wildfire by 65 to 70% relative to pre-2018 levels, and please note that this is an increase from the 55% to 65% we reported previously for mitigation work through June 2021. As shown on Page 5, SCE expects to further reduce risk with continued grid hardening investments, including deploying an additional 1,100 miles of covered conductor this year. This encouraging risk reduction metric does not take into account significant improvements at the state and federal levels to date and in progress. The governor’s proposed budget continues the trend of increased wildfire suppression and prevention investment, with CAL FIRE’s headcount set to be 45% higher than just five years ago. It also includes continued funding for aerial resources and the investments to date already have made CAL FIRE’s fleet of aircraft, more than 60 aircraft, the largest civil aerial firefighting fleet in the world. The state budget would also add $1.2 billion to the previously approved $1.5 billion Wildfire and Forest Resilience Strategy to support forest health and fire prevention. We were also pleased to see the Biden Administration’s multibillion dollar plan to bolster fire prevention across the West, as 57% of the forest lands in California are owned by the federal government. Protecting against the threat of extreme weather today lays the foundation for the increasingly reliable and resilient grid necessary for the clean energy transition. Through SCE one of the largest utilities in the country, Edison International is leading this transition through its thought leadership and SCE’s programs to accelerate economywide electrification. On Slide 6, I would like to highlight that Edison International has one of the strongest electrification profiles in the industry. Starting with transportation electrification, SCE has the largest programs among U.S. investor-owned utilities, and California is on the leading edge of electric vehicle adoption. In fact, 1 in 7 EVs registered in the U.S. are in SCE’s service area. EV adoption will be critical to achieving California’s climate goals and we estimate this could add over 50 million megawatt hours of incremental electricity consumption by SCE’s customers by 2045. Building electrification is another critical opportunity to reduce greenhouse gas emissions and it's the area of the California economy where the least amount of progress has been made to date. Last December, SCE proposed a $677 million program to jumpstart widespread adoption of electric heat pumps in buildings, and then last month, Governor Newsom’s budget proposed almost $1 billion to accelerate building decarbonization. The governor’s proposal is a welcome complement to SCE’s plan and is a meaningful addition to help meet California’s climate goals. Additionally, energy storage will be an important part of an electric-led future to ensure reliability of the grid. As we highlighted previously, SCE is investing $1 billion to construct 535 megawatts of utility-owned storage. The CPUC has already approved this investment and the project is on track to be in service by August. These projects and programs all help to advance the vision set forth in SCE’s Pathway 2045 Analysis. Underpinning the need to electrify the economy is substantial continued investment in the grid through 2045. In late January, the California Independent System Operator released its first ever 20-year transmission outlook, which estimates over $30 billion of transmission investment is needed by 2040 to meet the state’s climate goals. We see this as generally consistent with SCE’s Pathway 2045 work and that identified over $40 billion of transmission investment CAISO-wide. SCE estimates that CAISO’s outlook includes approximately $8 billion of transmission investments in our utility’s service area, which supports the potential for continued long-term rate base growth beyond 2025. The SCE team is going to be fully engaged in the CAISO processes that lie ahead. Those processes will turn this conceptual plan into real projects, and they will be focused on bringing ideas to the CAISO table that maximize the value of existing transmission lines, upgrades, and new projects that will all make the clean energy transition as affordable as possible for all California ISO customers. In upcoming regulatory proceedings, including 2021 GRC track 4 and the 2025 GRC, SCE will provide greater visibility into the near-term investments that are needed to ensure we remain on-track to help achieve the state’s climate goals. To achieve our ambitious long-term goals, operational excellence is absolutely imperative and it's going to be a constant focus for our team. For over a decade now, SCE has proactively pursued cost-reduction efforts to manage affordability for its customers. This focus on cost management along with broader operational excellence improvement has allowed the utility to absorb some of the rising cost to serve customers, which in recent years has largely been by investments to reduce wildfire risk and strengthen the grid’s reliability. I want to highlight that SCE’s system average rate has grown less than local inflation over the last 20 years, and SCE’s average rate is the lowest among the large California's investor-owned utilities. Last year, SCE advanced its operational capabilities with new systems and new digital tools deployed across the company, and these resulted in enhanced data quality, improved power line inspection and maintenance, and enriched abilities to gather and to act on customer feedback. To further our capabilities and focus on operational excellence, we launched an employee-led continuous improvement program late last year. Our employees have been wonderful, and they enthusiastically provided thousands of ideas that we believe are going to have real, positive, measurable impact on safety, affordability, and on quality. We expect the ideas that SCE will implement over the next two years will enable delivering greater value for our customers, for our investors, for employees, and for all of our other stakeholders. I'm looking forward to telling you more about the results of this program in the future. With that, I'll turn it over to Maria for her financial report.

Thanks, Pedro, and good afternoon, everyone. My comments today will cover fourth quarter 2021 results, our capital expenditure and rate base forecasts, our 2022 guidance, and updates on other financial topics. Edison International reported core earnings of $1.16 per share for the fourth quarter. Full year 2021 core EPS was $4.59, which exceeded our guidance range. On Page 7, you can see SCE’s key fourth quarter EPS drivers on the right-hand side. Core EPS increased year-over-year primarily due to higher revenue from the 2021 GRC final decision and income tax benefits from the settlement of California tax audits, partially offset by higher O&M expenses and higher net financing costs. The increase in O&M is due to a variety of miscellaneous items. Net financing costs were higher primarily due to the debt issued throughout 2021 to finance the resolution of wildfire-related claims. At EIX Parent and Other, the core loss per share was $0.07 higher than in the fourth quarter of 2020. This was primarily due to dividends on the preferred equity we issued at the parent in March and November of 2021. Now let’s move to SCE’s capital expenditure and rate base forecasts. As shown on Page 8, we continue to see significant capital expenditure opportunities at SCE driven by investments in the safety and reliability of the grid. In 2022, we project the highest capital spending level in our history, which includes SCE’s $1 billion investment in utility-owned storage to support summer 2022 reliability. As shown on Page 9, our capital forecast results in projected rate base growth of 7% to 9% from 2021 to 2025. We are confident in this range, which is driven by continued investment in wildfire mitigation, infrastructure replacement, and SCE’s programs to accelerate electrification. Page 10 provides an update on the 2022 cost of capital proceeding. The CPUC’s scoping memo separates the cost of capital mechanism into two issues: whether extraordinary circumstances warrant a departure from the cost of capital mechanism, and if so, how to set the cost of capital for 2022. SCE recently submitted its opening testimony, reiterating that extraordinary circumstances over the last couple of years warrant a departure from the mechanism and recommending that the 2022 cost of capital components should be left unchanged. Our earnings guidance is based on this position and in consideration of the wide range of potential outcomes in the proceeding. I will address this when I discuss our 2022 earnings guidance. Additionally, the CPUC ruled that this proceeding is limited to 2022 and directed the utilities to file their cost of capital requests for 2023 through 2025 at the regularly scheduled time, which is in April of this year. Turning to Page 11, SCE continues to make solid progress settling individual plaintiff claims across the 2017 and 2018 Wildfire and Mudslide Events. In total, the utility has resolved approximately 78% of the best estimate of total losses. At the appropriate time, SCE will seek CPUC recovery of eligible and prudently incurred costs. As a reminder, SCE is funding claims payments with debt that is outside its ratemaking capital structure. Turning to guidance, Pages 12 and 13 show our 2022 guidance and the key assumptions for modeling purposes. We are initiating a 2022 EPS guidance range of $4.40 to $4.70. To address the components, let’s start with rate base EPS, which we forecast at $5.34. Given the status of SCE’s cost of capital proceeding, we are basing guidance on the current ROE of 10.3%. To help you better understand the sensitivity, a 10-basis point change in ROE results in a 4-cent change in EPS. After receiving a final decision from the CPUC, we will provide an update on guidance to incorporate any changes in the ROE and our outlook for the rest of the year. Let’s next discuss SCE operational variances, which add to rate base earnings. This is forecasted at a net contribution of 11 to 38 cents per share. This includes 10 cents related to the currently authorized costs of debt and preferred equity that will be addressed in the 2022 cost of capital proceeding. Consistent with our approach with ROE, the currently authorized costs of debt and preferred are reflected in guidance. As we expected, the remaining variances are not as large as we have seen in the past. Prior years benefitted from items that aren’t expected to recur going forward. For EIX Parent and Other, we expect a total expense of 70 to 73 cents per share. The year-over-year increase is driven primarily by a full year of dividend expense from the $2 billion of preferred equity issued last year. Lastly, we have 32 cents per share of SCE costs excluded from authorized. The primary increase in this category is the interest expense on debt issued to fund wildfire claims payments. As we previously communicated, SCE will have a full year of interest on the debt issued during 2021 plus interest on debt issued throughout 2022 to fund additional settlements. I would now like to provide the parent company’s 2022 financing plan. Turning to page 14, we project total financing needs of $1.2 billion, including the $300 to $400 million of equity content we previously discussed. We continue to expect to issue securities with an annual average of up to $250 million of equity content from 2022 through 2025. In 2022, the amount is higher than average because of SCE’s $1 billion utility-owned storage investment that was accelerated into this year. However, this does not increase the total expected over the period. Additionally, we expect to refinance the $700 million of maturing parent debt with new debt issuances. Turning to Page 15, we are confident in reiterating our 5% to 7% EPS CAGR from 2021 to 2025. This would result in 2025 earnings of approximately $5.50 to $5.90 per share. We have provided modeling considerations for 2025 EPS to give clarity behind our confidence in achieving this range. As you can see in the table on the right, we expect 2025 EPS to be driven by strong growth in SCE’s rate base earnings, with offsets from increases in financing costs at the parent and costs to fund wildfire claims payments. Our earnings growth is underpinned by the capital investment opportunities at SCE that will create a strong foundation for climate adaptation and the clean energy transition. Thank you. That concludes my remarks.

Missy, please begin the call for questions.

It's actually Rich Sunderland, on for Jeremy. Maybe starting off with the guidance drivers. You outlined the $0.10 of cost of capital financing benefits, just want to be clear on that component alone. Does that mean you're expecting more likely to have kind of a steady-state outcome in the 2022 portion of cost of capital? Or I guess, put simply not after you give that back to ratepayers? Just any high-level thoughts there would be helpful.

Sure. Thanks for the question. So the way we developed our guidance is to base it on the current cost of capital. So basically the carryover, no trigger of the mechanism and having that continue through the end of '22 which will be a normal cycle. We know we're in the middle of a proceeding. In that proceeding, the signed commission's ruling actually really closely defined the questions that can be considered. One is, was there an extraordinary event? And then if there was, how to address the 2022 cost of capital? At this point, we're in the middle of that proceeding itself, all of the hearings, etc., should be done by the end of March, and then there would be a decision sometime thereafter. So what we're really doing is really just developing it from that basis. To the extent that there are changes from the current cost of capital, we just wanted to lay out for you what the impacts might be on earnings for the year. And so we've separated that into 2 parts. One is the ROE sensitivity and one is the embedded cost of debt and preferred sensitivity. And as we get through the proceeding and we see where we stand, because there can be a really wide continuum of outcomes. It could be no impact all the way to sort of the trigger resetting or something else in the middle. And as we get to understand what that outcome would be, then we can take another look at where we stand over the course of the year, and we can provide an updated guidance.

Got it. That's helpful color. And then maybe separately, the high and low end of your underground cost ranges on a dollar per mile basis. Could you parse that and maybe speak to, is that targeting a cost reduction or more representative of just the range of activity across your system?

So Rich, I think the numbers we presented are based on previous experience. Let me hand it over to Steve Powell, the CEO at SCE, to provide more details.

Yes, Pedro, you are correct. The figures we are presenting are derived from our experiences over the years and are incorporated into our wildfire mitigation plan. These costs certainly aren't reflective of a large-scale approach. We have been implementing undergrounding over the past few years, which covers only single digits to about 10 miles. When we examine undergrounding, the average cost is just over $3.5 million per mile. If we were to expand this on a larger scale, especially if we were to establish a more extensive undergrounding plan while assessing possible risk reductions, we would take into account various factors, such as egress, fire frequency, our PSPS thresholds, and the benefits in specific areas. We are evaluating potentially hundreds of miles of undergrounding opportunities that would be implemented over several years. Cost will also be a key consideration, and we would ideally choose options that are lower in cost, but the main driver will be risk mitigation. The range you see is based on past data. We still have work ahead to determine how much we could reduce those costs by implementing them in larger volumes and in targeted areas where cost management is more feasible.

And Rich, one really important thing that Steve has mentioned there is that we're looking at potentially hundreds, but it's not thousands of miles. We continue to see covered conductor as the mitigation of choice for most of our territory and it's just given the terrain that we have, the geography, the specific factors, and so it's really looking at where are there some near applications for undergrounding would be the right choice from a risk basis. But again, it's probably hundreds, not thousands.

It's actually Constantine here picking up for Shar. Appreciate the update today. And just as you're moving closer to the wildfire claims resolution and you seem to be back on pace in terms of reduction of outstanding claims. Is there anything incremental you're seeing in terms of pace of settlement? And along those lines, maybe do you have a sense of what constitutes being reasonably close to completion to start filings or discussions with the CPUC?

Yes, I'll begin, and Maria can certainly add to this. It's important to note that forecasting timing on this matter is quite challenging. However, with each passing quarter, we've demonstrated progress, which helps reduce some of the uncertainty. That said, uncertainty still exists, particularly regarding timing. Each case is unique and case-specific, complicating our ability to project the pace of resolution. While we can't precisely define what substantial completion entails or the volume needed, we believe the CPUC expects us to have a clear understanding of the total exposure involved. This likely means we need to see the majority of cases addressed for a specific bundle. For example, we could consider the substantial completion of the Woolsey cases separately, taking that matter to the CPUC. Similarly, we can think of the Thomas and Koenigstein cases related to mudslides as another distinct bundle. We shouldn't view this as a single bundle for all events in 2017 and 2018. Instead, we need to identify logical collections of cases, whether that's Woolsey or Thomas and Koenigstein, and ensure the majority are resolved to accurately assess total liability. Maria, do you have anything to add or correct?

Something to add, not correct. I'd just say maybe in addition to some of that, it's probably the case for sure that it benefits us to have more clarity as well as to what the quantum is, and just what the types of claims are that we've settled. And could bring that forward and there are fewer open or loose ends when we get to the commission, I think that helps just in terms of the proceeding once it does start. So I think we're weighing all of that as we go forward. It probably doesn't have to have every last person settled, but certainly, we think that there is a benefit to having the vast majority of them settled before we start the process. And I think it's important too to note what Pedro just said is that Thomas and Woolsey are separate events and would have a different set of facts that we would bring forward.

Certainly. I appreciate that detail. And as we're thinking about the tail end of your CapEx plan or kind of the non-GRC years, can you discuss the magnitude of potential upsides that you're seeing. We've seen the CPUC working on various non-GRC investments like microgrids, risk mitigation, and other policy items. Just curious how that's being implemented in your plan, if at all?

I mean, I'll give you a very high-level answer, which is, as we constructed that 5% to 7% range to 2025, we took a look at the large number of opportunities that we have in the state around electrification, around expansion of the grid, items that once we mentioned, storage. I think as you get until later years, transmission starts being more important. And all of those are supportive then at the upper end of the range. So I don't think we're at a point, certainly this early to say here things that could take us beyond the range, but rather we look at all that set of opportunities as being supportive of that 5% to 7% range.

Just picking up on the legacy liabilities, Pedro. I noticed it decreased from 2.2% to 1.6%. Since the overall accrual remains unchanged, it seems reasonable to assume you settled around $600 million in the quarter, which is consistent with the previous two quarters. Is there any reason to think that within the next two to three quarters, you wouldn't be close to resolving this, unless there is a significant adjustment to the accrual?

I refer back to my response to Constantine. I believe your calculations are correct regarding the pace we've seen, but we don't want to suggest a specific timeline. Therefore, it could be X point Y quarters from now if we maintain the same rate. However, all these cases are quite unique and specific. We want to avoid making precise predictions based on our past experiences. We are putting in a lot of effort and are happy with the progress we’re making, but I can’t provide a definite answer. I apologize if this is a bit unsatisfactory.

All right, I understand. Well, maybe I'll try something that you have some control over the timing of. When should we expect you to provide your 2023 guidance? I know you've just shared your 2022 guidance, but now that we are in a more normal rate case cadence, what would you consider the new normal?

Yes. What we're focusing on is the overall five-year cycle from 2021 to 2025, providing visibility on the EPS compound annual growth rate over time. We will give our 2023 guidance following the same schedule as in the past. Today is for 2022, and in the fourth quarter, we will announce 2023. We have started to offer more visibility on our long-term outlook. When you review the slides, you'll see that we have developed some components for 2025 to assist with your longer-term modeling. However, the annual guidance will follow the same timeline as before.

I wanted to follow up on Slide 11 regarding the remaining claims for 2017 and 2018. You mentioned that 22% of the best estimates are still outstanding. Can you clarify if this is approximately the same for Thomas and Woolsey, meaning is the number or percentage similar for both? Or should we expect differences since one of them is ready for filing sooner?

Yes. Thanks, Angie, for the question. We have not split that out in how we report it for a number of reasons. So I don't think you can extrapolate from that, which case might get to that CPUC line sooner.

Okay. And then a bigger picture question. So I understand you're in the midst of your 2022 cost of capital proceeding. We've seen the filings by the consumer advocates with some interesting points being made about no link between the stock performance and the cost of equity, which for an equity analyst is quite an interesting conclusion.

Just confirm that you disagree with that, right?

Yes, I do. I hope so, at least it supports my role. But also, you are raising equity for growth, and the cost and affordability of that equity impact your customer rates. Therefore, you are well-placed to highlight the significance of that cost of equity. We have several new members on the commission, and very few of the current members have participated in the cost of capital proceedings. We currently have the consumer advocate's position. Can you share anything that might assure us that there is a sense of fairness and reasonableness at the commission that will lead to a fair outcome in this 2022 cost of capital proceeding?

So Angie, all the points you just made are reflected in the filings we've already submitted. The signed Commission's ruling on the 2022 cost of capital question clearly indicates that they want the utilities to file for 2023 through 2025. That’s our opportunity. Many of the commissioners haven't participated in a cost of capital proceeding before, which gives us a chance to return to this. We will be presenting similar arguments to those made back in August and recently in January, emphasizing how everything ties back to customer rates in the end. It’s crucial to have a return on equity that accurately represents the real cost of equity. The proceeding itself signals to the market about the jurisdiction, which is ultimately important for long-term affordability. We will make all these points and recognize that we probably didn't address some of the issues you mentioned in our January filing. Moving forward, we also have routine discussions with the staff and the Energy Division where we continuously highlight that if these costs are not managed correctly, it will affect customer rates in the long run.

Well, and I think even more broadly, and Maria, you got it right. But from an even broader perspective, Angie, I think we've seen now over the past number of years that this commission and more broadly, the whole apparatus of government and the state understands the need for financially healthy utilities. And that's been tested, and we've gone through some of the challenges around the wildfire cost recovery framework. We saw legislation passed maybe 10-54 that we think there's a good job addressing that. All that stems from an understanding that the taking financially healthy utilities to do the work that we need to do and ultimately, like Maria said, to minimize customer costs in the long run. And so we would hope and expect that principle will be top of mind for commissioners as they go through the cost of capital proceeding.

Congratulations on the favorable guidance. I'm curious about the long-term outlook, specifically for 2025. There are several factors to consider, such as the SCE costs excluded from authorization, which is $0.35, as well as the $0.20 to $0.30 SCE operating variance that provides a benefit. You don’t consider that, at some point—perhaps during a future General Rate Case or regulatory event—these amounts could be readjusted, including the $0.35 that relates mainly to executive compensation and some interest, which might then be reflected in rates?

Michael, thank you for your question. Looking ahead to 2025, let's separate the operational variances from the costs excluded from authorized. We consider these operational variances every year when we provide guidance. There are specific elements involved, as we noted in our 2022 guidance, including AFUDC and shareholder costs, but it encompasses various factors. This can include the specific assets entering your capital plan that year and the timing of regulatory proceedings, which may require adjustments afterward. We conduct a thorough analysis each year and then arrive at the figures. As time progresses, we gain insight into future developments, which influences our thinking regarding the range of estimates. When assessing O&M savings over time, the 2025 year is important since it marks the start of a GRC cycle, and we are not expecting to see significant O&M savings because the work we are undertaking will ultimately benefit our customers. Regarding costs excluded from authorized, we will advocate in every general rate case for recovering certain expenses that have previously not been included in rates. However, we are not assuming this will happen. Additionally, some of these unrecovered costs are driven by legislation, and we are currently incurring interest expenses on claims payments. We will certainly pursue recovery of these costs, but we are not assuming they will be recouped at this moment.

Got it. Okay, that's really helpful. Pedro, I have a question for you. How do you see the role of hydrogen compared to the hyper electrification of industrial customers? I'm curious about your perspective on the conversation around the best approach to decarbonizing larger users.

Yes, it's a great topic. I'll begin with our Pathway 2045 work. In that discussion, we highlight that most emissions reductions will come from clean electricity and its use throughout society. However, we also recognize that there will be challenging applications to electrify, where low carbon fuels like hydrogen will be necessary. It’s important to note that not all hydrogen is the same; we're specifically referring to hydrogen produced from clean sources, which likely won't include certain methods unless we incorporate carbon capture. We expect some level of carbon capture will be involved, but its availability should be prioritized for situations where fossil fuels are absolutely needed. There's considerable enthusiasm around reducing production costs through electrolysis. Initiatives like the Hydrogen Earthshot at the Department of Energy and other related announcements demonstrate this focus. We are participating in a collaborative five-year project with the Electric Power Research Institute and the Gas Technology Institute, known as the low carbon resources initiative (LCRI), which is examining the potential for low carbon fuels such as hydrogen and addressing the technical challenges involved, such as the compatibility of pipelines with hydrogen. To address your core question, it's not straightforward to say which applications will fully switch to electricity and which will use hydrogen. Generally, heavier-duty and heat-intensive industrial processes seem more likely to benefit from hydrogen, and long-haul transport could also fit this model. In contrast, for light-duty vehicles, it’s difficult to envision hydrogen being a practical solution, as advancements in battery technology make electric vehicles much more efficient. As for the potential competition between hydrogen and electricity, I don’t see it as a strict competition. If hydrogen is to be clean, it will likely need to be generated from clean electricity via electrolysis. Thus, the electric grid will play an essential role in supplying the significant amounts of electricity required for electrolysis plants, which would then supply hydrogen to pipelines. We believe a robust and modern grid is crucial, and that importance extends to the hydrogen sector as well.

What portion of the $8 billion of potential electric transmission highlighted in the prepared remarks does Edison have right of ways to potentially use? And are there any initiatives today underway to enable those opportunities?

I'm going to provide a brief response and pass it to Steve Powell. This is a conceptual plan that needs to be developed into specific projects. Therefore, I can't provide a precise answer to your question, but Steve will take it from here.

Yes, that's correct. The conceptual plan primarily focuses on identifying general pathways for where projects may lead. The projects identified are mostly new initiatives that wouldn't typically fall under the right of first refusal for utilities given the current framework. There is a significant amount of work required to develop these conceptual projects into resource planning processes that will align with CAISO's 10-year plans as we progress. We need to understand how much of our existing system can be managed through upgrades versus how much will necessitate new developments. Overall, the opportunity presented is substantial, and now we need to determine the most cost-effective methods to deliver these solutions to our customers.

Okay. So no right of way is existing, so you have to procure those independently. Am I hearing that correctly?

It would depend on the ultimate projects and paths that these translate into. And so some of them may be close to some of our existing right of ways, but there is a lot more work to do to bring more clarity to what those projects ultimately will entail.

And that financial, we don't know yet, Ryan. But some of it may be accessible to upgrades.

Appreciate that. And then one clarifying question from earlier. Are there potential undergrounding a few hundred miles in place of or in addition to the current cover conductor miles?

Yes. So right now, as we're looking at that, we're focused on the places where we haven't already installed cover conductor. So we've got approximately 3,000 miles of covered conductor installed. As we look forward, we believe that there's thousands more miles that need to be hardened one way or another. And as we do that evaluation, we're going to be looking to figure out where undergrounding might make sense. So the focus right now is on those places where we haven't currently installed covered conductor because there's a lot more of that need to do.

Can you provide more details about the financing benefits related to the 2022 cost of capital proceeding? I understand the cost of capital proceeding, but what does the $0.10 represent?

Sure, Julien. So typically, the cost of capital proceeding covers a 3-year cycle. You make an estimate at the beginning of that 3-year cycle as to what the cost of debt will be and what the cost of prep will be. Certainly, a whole bunch of that is debt that's already been issued, but you're also using a forecast when you start a 3-year cycle. Over the course of that 3-year cycle, you can start to see those costs diverge from the original forecast. And so it's the benefit that you get because the actual embedded cost of your debt once you get to sort of the tail end of the cycle is less than what you anticipated at the beginning of the cycle.

Got it. All right. Excellent. If I may, returning to a broader question, you have addressed many detailed aspects, but I’m interested in your perspective on the accelerated penetration of electric vehicles among other factors. What inflation rate are you forecasting for costs during this period? Additionally, how are you planning to manage that, particularly in light of the NEM resolution? Ultimately, I’m focused on how you aim to spread these costs over a greater number of kilowatt hours.

Sure, here are my thoughts. Firstly, we have not provided a specific long-term estimate of what inflation or bill pressure will look like. We have mentioned that we expect to see some overall pressure in the next few years as we face significant wildfire mitigation work. However, we believe there will be a path back to more standard increases in rates and bills. Additionally, as you mentioned, the push for electrification will lead to more kilowatt hours. In my earlier remarks, I highlighted the increased kilowatt hours anticipated from electric vehicles alone by 2045. It's important to note that we don’t earn from these additional kilowatt hours due to decoupling, which is beneficial. However, the addition of these kilowatt hours will help ease rate pressure for all customers. Importantly, we need to consistently emphasize to our customers and policymakers that this effort goes beyond just our electric utility operations; it’s a broader economic endeavor aimed at achieving net zero carbon emissions. Our Pathway 2045 analysis indicates that the most cost-effective approach for the economy to reach this goal is through increased clean electricity usage and more investments in the grid to distribute that power effectively for widespread electrification. This transition will likely result in higher bills, due not only to the investments but also because consumers will be using more electricity for various aspects of their lives. Simultaneously, we anticipate reductions in gasoline and natural gas usage. It’s worth noting that we previously indicated that the average customer is projected to spend one-third less on their total energy bill in real terms by 2045 compared to today. Customers will spend more on electricity but less on other energy forms, and overall, this is the most economically sound pathway to decarbonization. This shift in focus means discussions regarding affordability should evolve from a narrow emphasis on electric bills to a broader examination of societal costs and the overall expense for customers in the decarbonization process. This could entail bill increases that are around or slightly above inflation, but hopefully not to the exceptional levels we saw in the past couple of years, which were particularly driven by significant wildfire investment needs.

Julien, I want to address your specific question about offsetting some costs of the capital plan with lower operating and maintenance expenses, particularly regarding insurance. Our expectation is that as we demonstrate reduced risk to insurance providers over time, we will see benefits that will directly impact our customers. We are currently in the process of marketing for our next policy year, so we will have an update soon. However, we did not see as significant an increase as we anticipated compared to our 2018 forecast and our current situation, which is positive. Although our current rate is about 41%, or $0.41 for every dollar spent on insurance, it remains high. Additionally, we are not just relying on insurance companies to acknowledge our risk reduction; we are also exploring customer-funded self-insurance. This approach could allow us to apply premiums from one year to the next, meaning customers wouldn't incur out-of-pocket expenses for premiums if there are no losses. We are taking these steps to potentially reduce some costs related to risk mitigation efforts.

I guess my first one is, when I look at your equity and rate base assumptions, are they assuming a certain amount of regulatory recovery of wildfire expenses or are they assuming that anything that you've written off is going to be excluded from those assumptions?

And when you say wildfire expenses, you mean the liabilities?

Yes, yes.

Yes. We do not assume here that we will be getting recovery on those wildfire liabilities. However, I want to reiterate what I said earlier, we will be filing for a recovery. So for all of the prudently incurred costs that we have, we will go back and ask the commission to allow us to recover that in rates. We have not built that into the forecast.

Okay. So that means anything that would be recovered then, I would assume that would be upside then to your rate base numbers?

That wouldn't be considered part of the rate base, Paul. When you mention recovery, I want to clarify that you're referring to the recovery of the wildfire liabilities we've been paying out. Typically, that wouldn't be classified as a rate base asset; it’s somewhat like operating and maintenance costs. The amount involved can be significant, depending on how comfortable the commission is with our recovery. We will need to strategize on ways to reduce the impact on customer rates. There's currently some legislative language that we believe could allow us to potentially securitize that over time if recovery occurs. However, I don't currently view it as a rate base asset.

Great. And then the other question I have is, I think part of the strategy that is being used by your northern neighbor, in terms of undergrounding is trying to use O&M savings that it believes it would be able to achieve on the vegetation management side as an offset to the cost of actually undergrounding its system. Do you see potential O&M savings with your more limited plans to underground?

Yes. And let me both turn it over to Steve for this one as well, but let me start by saying this is another place, Paul, where it’s really important to remember the difference in terrain and geography. And I think Patti and the team have been very open about just the significant amount of veg management cost to the have PG&A. And so the terrain is much more forced. Our terrain is more grasslands. They have more concerns with trees falling into line. We have more concerns with contact from objects blowing in, right? So that’s where the math has still towards cover conductor in our case. But Steve, what else would you say there?

Pedro, the difference in terrain and the risks we encounter from the types of ignitions in our various regions is a major factor in why our plans differ so significantly. If we end up increasing our undergrounding efforts, I would anticipate that in those specific areas, we would see some operational and maintenance savings due to not having to manage vegetation and possibly adjusting our inspection approach for undergrounding as well. However, this would only apply to the locations where we are implementing undergrounding. In terms of covered conductors, we still need to manage trees and vegetation. It's necessary because if large trees fall onto the covered conductor, they could cause significant issues. Over time, we will gain more insights into how our operational and maintenance practices for vegetation management can change and potentially yield savings with covered conductors, but we are not at that stage yet. I would indicate that covered conductors are quite cost-effective for us, and rolling them out quickly has been beneficial in reducing risks upfront. We will also have opportunities for increased undergrounding in the future.

Well, thank you for joining us. This concludes the conference call. Have a good rest of the day and stay safe. You may now disconnect.