愛迪生國際 (EIX) 2021 Q2 法說會逐字稿

Good afternoon, and welcome to the Edison International Second Quarter 2021 Financial Teleconference. My name is Terri, 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.

Thank you, Terri, 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-Q, prepared remarks from Pedro and Maria and the teleconference presentation. Tomorrow, we will distribute our regular business update presentation.

During this call, we will 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. (Operator Instructions) I will now turn the call over to Pedro.

Well, thank you, Sam, and thanks to everybody for joining. I hope all of you and your loved ones are staying healthy and safe. Edison International reported core earnings per share of $0.94 compared to $1 a year ago. However, this comparison is not meaningful because SCE did not receive a final decision in track 1 of its 2021 General Rate Case during the quarter. As many of you are aware, our proposed decision was issued on July 9. The utility will file its opening comments later today and reply comments on August 3. While Maria will cover the PD in more detail, our financial performance for the quarter and other financial topics, let me first give you a few observations, which are summarized on Page 2.

The PD's base rate revenue requirement of $6.9 billion is approximately 90% of SCE's request. The primary drivers of the reduction are lower funding for wildfire insurance premiums, vegetation management and depreciation. The main reduction to SCE's 2021 capital forecast was for the Wildfire Covered Conductor Program. Excluding wildfire mitigation-related capital, the PD would approve 98% of SCE's 2021 capital request, much of which was uncontested.

The PD acknowledged the often-competing objectives of balancing safety and reliability risks with the costs associated with ensuring SCE can make necessary investments to provide safe, reliable and clean energy. The PD also notes that wildfire mitigation is a high priority for the state and the commission. The PD supports critical safety and reliability investments and provides the foundation for capital spending and rate base through 2023. We believe it is generally well reasoned, but it has some major policy implications that are fundamentally inconsistent with where the state is headed. SCE's CEO, Kevin Payne, addressed these implications well during oral arguments earlier this week, and the utility will elaborate on them in his opening comments, which are outlined on Page 3.

The largest area of concern is the significant proposed cuts to SCE's Wildfire Covered Conductor Program. This is SCE's paramount wildfire mitigation program, and the utility's comments will focus on ensuring the program scope is consistent with the appropriate risk analyses, state policy and achieving the desired level of risk mitigation. The proposed reductions would deprive customers of a key risk-reduction tool, so SCE is advocating strongly for a balanced final decision. We believe additional CPUC-authorized funding for SCE's covered conductor deployment is warranted to protect customers' and communities' vital interests and achieve the same objective for minimizing wildfire risk.

As noted in prior discussions, SCE has prioritized covered conductor and other wildfire mitigation activities to urgently reduce wildfire risk. A scorecard of SCE's wildfire mitigation plan progress is on Page 4 of the deck. We believe that through the execution of the WMP and other efforts, SCE has made meaningful progress in reducing the risk that utility equipment will spark a catastrophic wildfire. Page 5 provides a few proof points of how SCE believes it has reduced wildfire risk for its customers.

First, circuits with covered conductor have experienced 69% fewer faults than those without, which demonstrates the efficacy of this tool. In fact, on segments where we have covered the bare wire, there has not been a single CPUC-reportable ignition from contact with objects or wire-to-wire contact.

Second, where SCE has expanded vegetation clearance distances and removed trees that could fall into its lines, there have been 50% fewer tree or vegetation-caused faults than the historic average.

Lastly, since SCE began its high fire risk inspection program in 2019, it has found 66% fewer conditions requiring remediation on the same structures year-over-year. These serve as observable data points of the substantial risk reduction from SCE's wildfire mitigation activities.

The utility will use the tools at its disposal to mitigate wildfire risk. This includes deploying covered conductor at a level informed by the final decision augmented by using Public Safety Power Shutoffs, or PSPS, to achieve the risk reduction originally contemplated for the benefit of customers.

The PD also included comments on the topic of affordability. We agree that affordability is always important and must be weighed against the long-term investments in public safety. I will highlight that SCE's rates have generally tracked local inflation over the last 30 years and have risen the least since 2009 relative to the other major California IOUs. Currently, SCE's system average rate is about 17% lower than PG&E's and 34% lower than SDG&E's, reflecting the emphasis SCE has placed on operational excellence over the years. While we recognize that the increases in the next few years tied to the investments in safety for the communities SCE serves are higher than this historical average, SCE has demonstrated its ability to manage rate increases to the benefit of customers. Underfunding prudent mitigations like covered conductor would be penny wise and pound foolish, as it may ultimately lead to even greater economic pain and even loss of life for communities impacted by wildfires that could have been prevented.

An active wildfire season is under way right now, and I would like to emphasize SCE's substantial progress in executing its WMP. Through the first half of the year, SCE completed over 190,000 high fire risk-informed inspections of its transmission and distribution equipment, achieving over 100% of its full year target. The utility also continues to deploy covered conductor in the highest risk areas. Year-to-date, SCE installed over 540 circuit miles of covered conductor in high fire risk areas. For the full year, SCE expects to cover at least another 460 miles for a total of 1,000 miles deployed in 2021, consistent with its WMP goal.

Additionally, SCE is executing its PSPS action plan to further reduce the risk of utility equipment igniting wildfires and to minimize the effects on customers. SCE is on target to complete its expedited grid hardening efforts on frequently impacted circuits and expects to reduce customer minutes of interruption by 78%, while not increasing risks, assuming the same weather conditions as last year. To support the most vulnerable customers living in high fire risk areas when a PSPS is called, the utility has distributed over 4,000 batteries for backup power through its Critical Care Backup Battery program.

We believe California is also better prepared to combat this wildfire season. The legislature has continued to allocate substantial funding to support wildfire prevention and additional firefighting resources.

Just last week, the state announced that CAL FIRE has secured 12 additional firefighting aircraft for exclusive use in its state-wide response efforts, augmenting the largest civil aerial firefighting fleet in the world. SCE is also supporting the readiness and response efforts of local fire agencies. In June, SCE contributed $18 million to lease 3 fire-suppression helicopters. This includes 2 CH-47 helitankers, the world's largest fire-suppression helicopters; and a Sikorsky-61 helitanker. All 3 aircraft have unique water and fire-retardant-dropping capabilities and can fly day and night. In addition, a Sikorsky-76 command-and-control helicopter, along with ground-based equipment to support rapid retardant refills and drops, will be available to assist with wildfires. The helitankers and command-and-control helicopter will be strategically stationed across SCE's service area and made available to various jurisdictions through existing partnerships and coordination agreements between the agencies through the end of the year.

We also appreciate the strong efforts by President Biden, Energy Secretary Granholm and the broader administration. I was pleased to join the President, Vice President, cabinet members and Western Governors, including Governor Newsom, for a virtual working session on Western wildfire preparedness last month. The group highlighted key areas for continued partnership among the federal government, states and utilities including land and vegetation management, deploying technologies from DOE's national labs and other federal entities and enabling response and recovery.

Let me conclude my comments on SCE's wildfire preparations for this year by pointing out a resource we made available for investors. We recently posted a video to our Investor Relations website featuring SCE subject matter experts discussing the utility's operational and infrastructure mitigation efforts and an overview of state actions to meet California's 2021 drought and wildfire risk. So please go check it out.

Investing to make the grid resilient to climate change-driven wildfires is a critical component of our strategy, and it's just one element of our ESG performance. Our recently published sustainability report details the progress and long-term goals related to the clean energy transition and electrification. In 2020, approximately 43% of the electricity SCE delivered to customers came from carbon-free resources, and the company remains well positioned to achieve its goal to deliver 100% carbon-free power by 2045.

SCE doubled its energy storage capacity during this year and continues to maintain one of the largest storage portfolios in the nation. We have been engaged in federal discussions on potential clean energy provisions and continue to support policies aligned with SCE's Pathway 2045 target of 80% carbon-free electricity by 2030. However, the electric affordability and reliability have to be top of mind as we push to decarbonize the economy through electrification. The dollars needed to eliminate the last molecule of CO2 from power generation will have a much bigger impact when spent instead on an electric vehicle or a heat pump. For example, the utility is spending over $800 million to accelerate vehicle electrification across its service area, and that's a key component to achieve an economy-wide net 0 goal most affordably. Recently, SCE opened its Charge Ready 2 program for customer enrollment. This program is going to support 38,000 new electric car chargers over the next 5 years, with an emphasis on locations with limited access to at-home charging options and disadvantaged communities.

We are really proud that Edison's leadership in transportation and electrification was recently recognized by our peers with EEI's Edison Award. That's our industry's highest honor. SCE has been able to execute on these objectives while maintaining the lowest system average rate among California's investor-owned utilities and monthly residential customer bills that are below the national average.

As we grow our business for the clean energy future, we are also adapting our infrastructure in our operations to a new climate reality. We're striving for best-in-class operations, and importantly, we are aiming to deliver superior value to our customers and to our investors.

With that, let me turn it over to Maria for her financial report.

Thank you, Pedro, and good afternoon, everyone. My comments today will cover second quarter 2021 results, comments on the proposed decision in SCE's General Rate Case, our capital expenditure and rate base forecast and updates on other financial topics.

Edison International reported core earnings of $0.94 per share for the second quarter of 2021, a decrease of $0.06 per share from the same period last year. As Pedro noted earlier, this year-over-year comparison is not meaningful because SCE has not received a final decision in its 2021 General Rate Case and continues to recognize revenue from CPUC activities based on 2020 authorized levels. We will account for the 2021 GRC track 1 final decision in the quarter SCE receives it.

On Page 7, you can see SCE's key second quarter EPS drivers on the right-hand side. I'll highlight the primary contributors to the variance.

To begin, revenue was higher by $0.10 per share. CPUC-related revenue contributed $0.06 to this variance. However, this was offset by balancing account expenses. FERC-related revenue contributed $0.04 to the variance, driven by higher rate base and a true-up associated with filings SCE's annual formula rate update.

O&M had a positive variance of $0.11, and 2 items account for the bulk of this variance. First, cost recovery activities, which have no effect on earnings, were $0.05. This variance is largely due to costs recognized last year following the approval of cost tracked in a memo account. Second, lower wildfire mitigation-related O&M drove a $0.02 positive variance, primarily because fewer remediations were identified through the inspection process. This continues the trend we observed in the first quarter. Over the past few years, SCE has accelerated and enhanced its approach to risk-informed inspections of its assets. Inspections continue to be one of the important measures for reducing the probability of ignitions. For the first half of the year, while we have maintained the pace of inspections and met our annual target, we have observed fewer findings of equipment requiring remediation. Lastly, depreciation and property taxes had a combined negative variance of $0.10, driven by higher asset base resulting from SCE's continued execution of its capital plan.

As Pedro mentioned earlier, SCE received a proposed decision on track 1 of its 2021 General Rate Case on July 9. If adopted, the PD would result in base rate revenue requirements of $6.9 billion in 2021, $7.2 billion in 2022 and $7.6 billion in 2023. This is lower than SCE's request primarily related to lower authorized expenses for wildfire insurance premiums, vegetation management, employee benefits and depreciation.

For wildfire insurance, the PD would allow SCE to track premiums above authorized in a memo account for future recovery applications. The PD would also approve the vegetation management balancing account for costs above authorized. In its opening comments, SCE will address the PD's procedural error that resulted in the exclusion of increased vegetation management labor costs, driven by updated wage rates. Vegetation management costs that exceeded defined cap, including these higher labor costs, would be deferred to the vegetation management balancing account. The earliest the commission can vote on the proposed decision is at its August 19 voting meeting. Consistent with our past practice, we will provide 2021 EPS guidance a few weeks after receiving a final decision.

I would also like to comment on SCE's capital expenditure and rate base growth forecast. As shown on Page 8, over the Track 1 period of 2021 through 2023, rate base growth would be approximately 7% based on SCE's request and approximately 6% based on the proposed decision. In the absence of the 2021 GRC final decision, SCE continues to execute a capital plan for 2021 that would result in spending in the range of $5.4 billion to $5.5 billion. SCE will adjust spending for what is ultimately authorized in the 2021 GRC final decision while minimizing the risk of disallowed spending. We have updated our 2021 through 2023 rate base forecast to include the Customer Service Replatform Project. SCE filed a cost recovery application for the project last week. I will note that this rate base forecast does not include capital spending for fire restoration related to wildfires affecting SCE's facilities and equipment in late 2020. This could add approximately $350 million to rate base by 2023.

Page 9 provides a summary of the approved and pending cost recovery applications for incremental wildfire-related costs. SCE recently received a proposed decision in the CEMA proceeding for drought and 2017 fire-related costs. The PD would authorize recovery of $81 million of the requested revenue. As you can see on Page 10, during the quarter, SCE requested a financing order that would allow us to issue up to $1 billion of recovery bonds to securitize the costs authorized in GRC track 2, 2020 residential uncollectibles and additional AB 1054 capital authorized in GRC track 1. SCE expects a final decision on the financing order in the fourth quarter.

Turning to Page 11. SCE continues to make solid progress settling the remaining individual plaintiff claims arising from the 2017 and 2018 wildfire and mudslide events. During the second quarter, SCE resolved approximately $560 million of individual plaintiff claims. That leaves about $1.4 billion of claims to be resolved or less than 23% of the best estimate of total losses.

Turning to Page 12. Let me conclude by building on Pedro's earlier comments on sustainability. I will emphasize the strong alignment between the strategy and drivers of EIX' business and the clean energy transition that is under way. In June, we published our sustainable financing framework outlining our intention to continue aligning capital raising activities with sustainability principles. We have identified several eligible project categories, both green and social, which capture a sizable portion of our capital plan, including T&D infrastructure for the interconnection and delivery of renewable generation using our grid, our EV charging infrastructure programs, grid modernization and grid resiliency investments. Shortly after publishing the framework, SCE issued $900 million of sustainability bonds that will be allocated to eligible projects and reported on next year.

Our commitment to sustainability is core to the company's values and a key element of our stakeholder engagement efforts. Importantly, our approach to sustainability drives the large capital investment plan that needs to be implemented to address the impacts of climate change and to serve our customers safely, reliably and affordably.

That concludes my remarks.

Terri, could you please open the call for questions? (Operator Instructions)

(Operator Instructions) And our first question comes from Jeremy Tonet with JPMorgan.

I wanted to start off here with undergrounding. How helpful could undergrounding be in your service territory? Is this an option you'd explore? And how does the covered conductor pushback kind of inform your thought process here?

Yes. Happy to pick up on that one, Jeremy. So I think as you've seen us say in the past, we are looking at all the tools in the toolbox. Given our terrain and the fact that the really predominant -- one of the predominant forms of ignition in the past has been from contacts with foreign objects. We find that covered conductor has really provided the optimal tool for reducing risk while maintaining affordability for customers. And so we see that covered conductor has something like 70% of the risk reduction that undergrounding has. The cost difference in the numbers we've seen to date, obviously, the team continues to keep track of what's going on and talking with our peers and talking with experts about potential improvements. But I think the latest numbers we've seen are that covered conductor cost us something like $456,000 a mile whereas underground, on average, in our territory, it will cost you about $3.4 million a mile.

We have seen some spot applications, and in fact, there's about 17 miles that we targeted to underground between this year and next year. And we'll continue to look at the tool in the toolbox, but at least with our territory, with our incidence of historical ignitions, we believe that covered conductor provides a -- really an optimal tool in terms of both risk reduction and affordability.

Got it. That's helpful. Maybe just kind of shifting gears here a bit, if you could speak more to the policy implications from the PD and how you see intervenors positioned here on these policies versus just pure cost considerations here.

Yes. I'll give you some thoughts. Maria may have more, and Kevin Payne is here as well if we miss anything. Look, there'll be 2 thoughts that come right away to mind. First is GRCs are litigated proceedings, right? And so you always have at least 2 sites -- actually multiple sites with multiple intervenors. You have some intervenors that are more focused on purely the affordability side of things. I think as the utility, we're really working hard to provide well-supported testimony and analysis that is looking at finding the right balance, right?

We're balancing -- first of all, having a reliable system -- actually above all, having a safe system that needs to be inviolate. But you really see trade-offs between reliability and affordability, right? You could always spend more to get an extra percentage point in reliability, but at some point, it becomes unaffordable for the customer. So it's how do you find the right balance.

I think as you heard me say in the prepared remarks already, the -- really the largest issue here -- it's not the only but the largest issue has been the position that TURN took in terms of the risk reduction provided by covered conductor and how many miles are enough. And we just have a fundamental difference in view in terms of the policy argument that they're making.

We are facing a significant wildfire risk across the state. We've seen it in our area. We strongly believe that the wildfire mitigation plans that we prepared really help address that risk. And you saw the data that we shared in the deck and that I mentioned in my remarks around some of these early returns that we're experiencing with significant decreases in some of the risks that we had just 3 years ago, right?

So I cited the figures on reduction in faults, and frankly, no CPUC-reportable ignitions yet on miles that we've covered, where we used to have bare wire. So the fundamental policy debate here is the -- TURN has what we think of some flawed math about stopping at 2,700 miles. And we believe that the plan we've laid out that will go to over 6,000 miles, covering about 60% of the 10,000 miles in high fire risk areas, provides that kind of risk protection that our customers need. That's consistent with the emphasis the state has on fire mitigation, fire suppression.

So affordability is always really important. But one final point I'll give you is one that Kevin Payne made really well during the oral argument. Affordability is not just about the bill that you get tomorrow. Affordability is about the entire economic equation. And if we allow unmitigated wildfire risk to persist and a fire takes place that could have been prevented, that's a much bigger affordability shock for that community in the long run, in addition to the health and safety impact that it can have.

So we think we've got it right in terms of the policy trade-offs, and we hope that the 5 commissioners will agree with that in the final decision.

Maria, if you have anything to add there? Or did I cover it?

No, I think from a policy perspective, Pedro, that really is the biggest discussion we want to have with the commission and with the intervenors. It's around covered conductor and the affordability and risk trade-off that you just described. There are some other things - when we file our comments later today, there will be some other things that outlined some of them on one of the slides in the deck today. Those are things that certainly we think we should be treated equally as other utilities or in line with precedent. But I think the big discussion, as you can probably tell from the oral argument, was really around and is really around covered conductor and the efficacy of that and the proof points also that we've seen as Pedro mentioned.

And our next question comes from Angie Storozynski with Seaport.

Okay. I have 2 questions. The first one, given what happened with the bond yields and the cost of capital having the bond yield driven true-up, what do we expect here for -- I mean, obviously, it all depends on what happens with the interest rates between now and October. But should we expect some filings from you guys trying to preempt this lowering of the ROE, which would be implied from current bond yields?

So Angie, I think the average bond yield has to be in that dead band. Right now, if you look at sort of the amount of time remaining until the measurement period is over, yields would have to average just over 4% to kind of make the whole year average within the dead band. So what happens, the end of the measurement period is the end of September.

We all know that the PTC has taken positions on prior requests to either extend and defer changes on the cost of capital for others. And we also know from our experience back in 2017 that they really prefer to see litigated cases, and we're preparing testimony that's going to focus on the differentiated role and the risks that California IOUs have and that notwithstanding these lower interest rates, that's really driven by these extraordinary events over the past 18 months in all of the government programs that have been implemented to alleviate the impact of the pandemic. But that should not really imply that a change in the ROE is necessary. And I think that the changes in the volatility certainly underscore that. And I think regardless of what happens, we have to file next spring for another cost of capital proceeding. So those are the sorts of things that we are thinking about.

I think since that basic issue, we really need to demonstrate that notwithstanding the interest rate environment, the cost of equity is, in fact, lower. We'll continue to look at everything that's going on, options on how to best get that point across to the commission, to the intervenors and also to really underscore the point that financially stable IOUs and California IOUs that are attractive to investors ultimately support customer affordability in the long run, too. So I think we're just going to continue to monitor the situation. We're preparing testimony already, and we'll go from there.

Okay. And my second question is on your financing needs this year. You continue to settle more wildfire claims. You haven't yet issued enough equity to meet your guidance for this year. So are we waiting for the final decision and the GRC? Is it that there is some movement in the total number that you might need given, again, ongoing settlement of claims?

Certainly, I'll kind of bifurcate that into a couple of different parts, if you don't mind. So I'll just kind of go back to sort of where I always like to start with this. Our financing plan is really built from the perspective of maintaining investment-grade ratings, and back when we moved to a best estimate for the wildfire liability last year, we said we would issue approximately $1 billion of equity to support the ratings and then that would allow SCE to continue to issue debt to fund the wildfire claims payment. And since then, we've been evaluating our needs, and we focused on different financing options. And back in March, we issued the $1.25 billion of pref and that had the 50% equity content.

We've also said in the past that we do think we have flexibility regarding the timing. And so we're continuing to have that belief that we can be flexible in terms of timing. And we're continuing to monitor market conditions, and that's going to inform our next steps. We're going to continue to consider, and I think we've talked about this a little bit before, the tools that we would use. So continue to consider preferred equity, internal programs and then, if needed, the ATM. Now that's that piece associated with sort of the ongoing discussion around the wildfire claims and the liabilities in '17 and '18.

Separately, we've also talked about the need on an ongoing basis what we think is a minimal equity requirement. That piece of it, that ongoing minimal equity need associated with the core business, is one that we will provide more specificity around once we get the final decision. So that piece does kind of tie back to the final decision.

And our next question comes from Shar Pourreza with Guggenheim.

It's actually Constantine here for Shar. I just wanted to kind of follow up a little bit on the PD and kind of the views that it takes on wildfire insurance, covered conductors and such. And does that change your approach to procuring wildfire insurance? And are you comfortable with the level of insurance that you have? And would you anticipate that costs would come down as kind of more areas are converted to covered conductor?

Actually, Maria, I'll pick up that last part first, and then turn the first part to you. We would expect -- certainly hope that over time, as the risk envelope continues to be narrowed in the state, right, and it's not just a utility work but what the state is doing in terms of fire suppression, further constraining the overall risk envelope. We certainly hope that over time, that translates into insurers seeing that the risks they're insuring is not as large as it used to be, and that should reflect itself in premiums. But of course, the market's the market, so we'll see how that progresses on its own.

Maria, let me turn it over to you for the first part.

Sure. So Constantine, you know that our policy year is July 1 through June 30, so we just started a new policy year. In terms of the PD, the original request in the PD when we file the application rates were increasing by big percentages year-over-year, and our request had something like a $600 million wildfire insurance premium embedded in it.

What came out in the PD is that, one, very importantly, they reiterated that wildfire insurance premiums are a cost of service, so customers will pay for that as part of their rate. They approved a number or an authorized revenue of about $460 million, which is actually, as it turns out, sufficient or at least if we were to look at the balance of this year and then the beginning part of the year, which was the last policy year, that is comparable or at least a little bit more than what the premiums are.

We expect the expense for this year to be about $425 million for about -- for $1 billion gross of insurance, but net, once you deduct out the self-insured retention and a little bit of coinsurance, is about $875 million of wildfire insurance, which is consistent once you get right through to it with what's required under AB 1054. So from that perspective, good policy points on cost of service aligned with, at least for this year, what premiums would be.

The third piece of it is that they also reiterated that to the extent premiums go up in the future, we can use that memo account feature that we have used in the past and successfully recovered premiums under in the future as well. So that's all good.

The one piece of conversation that we will continue to have with them is whether or not it is better to actually collect a little bit more from customers, not just the amount of the wildfire insurance premium but also collect a little bit for customer-funded health insurance, which may over time be more economical for customers since, to the extent you don't have a loss, you keep it and roll it over to the next year, which is different than what you do with the premium.

Excellent. That makes a lot of sense. And just shifting a little bit to the wildfire -- to the legacy wildfire loss estimates. I guess, can you qualify the level of comfort that the estimates will not change? And is the best estimate at this point pretty much derisked now that you have all the settlements in place and kind of the remaining $1.4 billion of the kind of loss estimate is just kind of progressing towards completion? Do you kind of have any estimates on the duration of kind of settlement -- the settlement processes or any qualitative statements around that?

Probably a statement that sounds a lot like what we said before. Even though the number more -- even though more claims have been settled, it's still very dynamic. Every claim is different and has to be addressed differently. We continue to monitor the situation, obviously. It's one of the biggest areas of management judgment. And we sit down and have that conversation every quarter to be sure that we're reflecting the things that we know in the reserve. But I would say there's still an error band around that, and we'll have to address that as time passes.

And I guess just as a point, is it fair to assume that since the estimate hasn't moved in a while that it's been kind of close to your -- the settlements that have been coming through are kind of close to your best estimate?

Yes. I mean as Maria said, we -- Constantine, we look at this every quarter, recognize that we still have several thousand plaintiffs. These are typically smaller than the large settlements we did earlier on, for example, for the [subros].

So such a wide diversity of cases and plaintiffs, everything from homeowners to smaller businesses, to avocado growers, to just a whole broad range. So that's why we'll continue to test that every quarter and keep you posted if there's any changes. But it's difficult for us and probably not appropriate for us to try and give some perspective on the probability of changes. I think under the accounting rules, we provide you what our current best estimate is. And that, as you say, has not changed.

And our next question comes from Michael Lapides with Goldman Sachs.

A little bit of a high-level one, which is if you think about things that are not in the GRC and track 1 through 4 but might be upside over the next 3 to 4 years to your potential capital spend level, can you highlight what those may be and which ones you've actually already filed for but you don't have approval for yet and which ones you haven't even filed for yet but somewhere embedded within the SCE organization you've got a team of people who are pencil-to-paper and started to put together numbers?

Well, particularly with the pandemic, we're less pencil-to-paper and all electronics. It's all very high tech now, all virtual. But joking aside, and Maria, maybe you can come in here with details. I'll give you a high-level answer to your high-level question. It's similar to what you heard from us before, right? What you see in the rate case, obviously, is very concrete, and we'll see where the final decision comes out. But as we look forward and we think about the clean energy transition, right, there's a number of things as part of the transition that will either support our view that we'll continue to have robust investment needs for a long time or potentially create upside to that.

Areas like -- we -- I talked a little bit in my remarks about Charge Ready. Open question right now as to whether there will be a further role needed for utilities to continue to support the charging infrastructure market or whether private entities will be able to step in and do that fully.

Interestingly, I think -- Maria said Commissioner Rechtschaffen, who had a recent commission meeting, was, I just think, thinking out loud about now there may well be the need to have utilities step in and do more, just given the scale of the transition. And in particular, as I look at it, it's not just about getting charging infrastructure to the average customer and making sure that the transition is equitable. So therefore, making sure there's enough penetration in disadvantaged communities, low-income communities, where private players might not be as economically enticed to do that and where there might be a case to socialize more of that to the build. So transportation is certainly one area. Storage is another.

We know that the -- our GRC request included in there, I think, an assumption of, what's it, 60 megawatts or so of new storage over the pendency of the rate case period. But as we see the amounts of storage that will continue to be needed moving forward and the -- certainly the potential for some of that to be part and parcel of utility operations might make a lot of sense for some portion of that to be in rate case, right? And so that also creates either support for an overall investment trajectory or potentially even further upside.

Building electrification is another area where we've seen, frankly, relatively little progress to date compared to what we think will be needed as we head out -- as we, the state, heads out to 2030 and 2045.

And so right now, the utility team is thinking about are there places where the utility will be able to help and where it will be economic for our customers to support that rate. Because you need both of those, right? And so there's some good thinking under way right now around are there potential programs where we might be able to be helpful to the state's transition.

So that gives you a few examples. Maria, you may have more specific things.

Yes. I think maybe in terms of numerical examples because I think there are obviously a lot of opportunities in the list that Pedro provided. More detail to come as the team, as you say, with the pencil to paper or virtually the pencil to paper works more on the specifics. But in terms of things that have been filed already, where the numbers are more explicit, we did recently include in our rate base forecast, so already in the numbers, but we did recently include our Customer Service Replatform project. So that's -- that reflects about $500 million or so of rate base by the time you get out to 2023. So that's now embedded. Application was filed last week.

Also, we did, as you know, experience wildfires in our service territory late last year up in the Big Creek area. A lot of restoration had to go on there. We haven't yet applied for recovery of that, but that would be, say, about another $350 million of rate base if approved. I'll say in the year 2023, it's probably a reasonable time frame.

So those are more specific things, Michael, in addition to what I would view as [all] clean energy transition opportunities that Pedro mentioned.

And our next question comes from Jonathan Arnold with Vertical Research Partners.

I think you just answered my question, which is that the Customer Replatform is effectively what's driving the higher range and sort of main rate base forecast versus last quarter. Is that pretty much all of it? Or was there something else in there?

That should be it, Jonathan. I think we haven't changed any -- we've shown you what the PD numbers are, obviously, but we haven't really changed anything yet until we get the final decision.

And your sort of confidence in recovery of that, can you just sort of talk to that a little bit, please?

Sure. Well, the Customer Service Replatform project replaces a very, very old system, so it was very much needed. Some of it was written in software languages that we couldn't even get people to -- who knew them anymore. So I think from that perspective, very much needed. I think over the course of the implementation, the team has had ongoing dialogue with energy division and the like to keep them apprised of what's been happening at the project.

There have been, over time, some cost increases, obviously, because we had to wrap more into the project given the complexity of our system. But we think that all the work that we've done really is well justified, and the testimony that we filed supports that. We're now in stabilization mode. And so we keep keeping a close eye on just customer satisfaction, ability to answer customers' questions, all of the things that you would expect to happen when your -- when a new system goes live. But the team is very, very attuned to that, and we've added extra folks in the stabilization mode as well. So I think we've done all the things that we should be doing in order to ensure that we can make a good case with the commission.

Okay. And then maybe -- well, I think while you've been speaking, the shelf filing came across. Is that just a refresh of maybe something expiring? Could you just speak to that?

Yes, both SCE and EIX, the shelf registrations were expiring. So that's -- this is just normal course. For EIX, the only thing we did was -- we used to have 2 separate ones. We put them together, so that we don't have to have -- have the, I'll say, the administrative burden of 2 filings. So very normal course.

And our next question comes from Sophie Karp with KeyBanc Capital Markets.

Actually, it's Sangita for Sophie. So we did go through the PD and understandably, the covered conductor is the point of difference here. Would you consider -- let's say, the final decision comes in close to where the PD is, would you still consider building on your covered conductor program over the plan to seek the recovery at a future date?

I think as Kevin Payne said during the oral argument, we will strongly factor in the guidance from the CPUC, right? And so ultimately, they will be ruling on a certain risk level -- risk trade-off level as they think about balancing affordability and risk and safety. We certainly feel strongly about what the right answer is here, right, which is not the PD. It's more like what we proposed. To the extent that the guidance it provide us would limit spending, we will use some of the other tools that we have in the toolbox, including PSPS, much more adequately, right, or as needed in order to make sure that we maintain an appropriate risk level for our customers.

And our next question comes from Julien Dumoulin-Smith with Bank of America.

I suppose -- if I can come back to the crux of the conversation around affordability, how do you think about the different scenarios around what the commission could do here in creating the bill affordability, right? It seems evident that one needs to try to continue to push as much as possible towards addressing and mitigating wildfire risk. How do you think about creating bill headroom, whether through OpEx or effectively shifting out other projects from a CapEx perspective?

I'm just thinking out loud and putting it back to you on sort of the different levers here that might exist to create that affordability that seems necessary to move forward with the wildfire spending at your proposed [pace].

Yes. Julien, it's a great question. A few reactions right away, and Maria may have more. First, it's what we've been doing for the last 5, 6, 7, 8 years, right? And you've seen us create a lot of rate headroom in order to do the work that we needed to do. I commented in my prepared remarks on the way that we've maintained O&M cost increases and frankly, total system rate -- system average rate increases at around the level of inflation for the last 3 decades. And I know we've talked with you and with other investors and analysts significantly about that in the past. We've continued that track record. Obviously, this GRC is a major departure from that driven in large part by the wildfire-related needs. But we will continue to look at opportunities to do better cost management, to do more use of technology that can help make our work more effective, more efficient. That's definitely an ongoing tool. And I don't think on that one you're ever done, right? Because the reality is the bar keeps going up. The digital tools, the data analytics, all of these continue to improve and open up new opportunities that I don't think any of us imagined 5 or 10 years ago. So I'd say that's part 1 of the answer.

Part 2 kind of goes back to some of the discussion in -- for some of the earlier questions. There is a there's a balance there, right? And it's important that the commission be thinking about affordability broadly not only in terms of the near-term rate increase but the impacts of that over time, the risk that it either mitigates or doesn't mitigate the risk it might leave behind on the table that might then increase the risk of wildfire in the future that would have a much more devastating economic impact on the community, or the risk that by not spending enough on covered conductor, we might have to continue using PSPS for a longer period of time in a particular community, which has its own set of impacts, right? I know that the commission has appropriately been very sensitive to those.

So there is absolutely a balancing act there. It's a tough job the regulator has, a tough job that we have. But I think we've put together a well-thought-out approach for balancing those risks. So just a few reactions. Maria, you may have others.

Yes. I guess, Julien, the one thing I would also add to that are maybe 2 things. If we go all the way back to when we filed our application for this GRC, we actually teed that up for the commission and said we know we have to balance a lot of different things between what we need to invest for safety and also in wildfire risk mitigation and then affordability for our customers. So we actually told them that some of our investments in infrastructure replacement, we would hold on to and not propose for this GRC cycle and instead take that up again when more of the wildfire mitigation CapEx had been spent.

So I think that balance is one that we always try to strike. And I think it's the conversation with the commission, and the commission raised it during their own affordability en banc because they recognize that over the longer term, more electrification is actually going to drive lower cost for customers.

You've seen it in our pathway paper. The commission themselves recognize that electrification will reduce energy as a customer -- as the share of customer wallet. So we have to focus on the near term with a view not just on affordability, what's on the bill. As Kevin said in his oral argument, it's the overall economic proposition that we have to think about with our customers.

And so let's get this done. I think one of the numbers he quoted in his oral arguments was that if we increase covered conductor to the level that we had in the request, that's really about $2 a month on the customer bill. I'm not trying to minimize that. I know people are in different situations economically. But when you think about the alternative, that's really, I think, the most economical choice. And then that resiliency tees up the system and the customers for the long term when electrification really does minimize costs.

Yes. And Maria, let me just pick up one more thing triggered by your comments. Julien, a lot of the focus right now, certainly in this rate case, is on the affordability trade-off relative to wildfire mitigation. I think as we move forward over the next decade or 2, to Maria's point, aligned with our Pathway 2045 analysis, I think we'll see more of the discussion shift to the affordability trade-offs relative to meeting clean energy targets and decarbonizing the economy. Because it's so important that, frankly, the analytical work we've done that demonstrates that using clean electricity to electrify a lot of the economy is the cheapest way for the economy to get to net 0, right?

This will put pressure on the electric bill. I don't think it will be the sort of rate increases year-on-year that we see in this rate case, right? But we might see excursions to a little bit of local inflation in order to build out the infrastructure needed to electrify much more of the economy and, therefore, decarbonize, right?

And so frankly, part of our job and the job of future teams at Edison over the next 2 decades will be to constantly be putting good educational materials out there, good analysis around the world, not just the cents per kilowatt-hour world but the world in a dollars per ton of GHG removed perspective because that's just as important a metric as the cents per kilowatt-hour.

Yes. And quick, if I could -- if I can throw one in quick here, just to follow up. How do you think about -- obviously, there's some fairly transparent cost of capital dynamics out there that could put pressure on numbers. How do you think about offsetting factors? Again, I'm coming back to O&M, thinking about that as being a lever both in the near term and the long term. How do you think about offsetting some of the cost of capital with O&M or refinancing opportunities, et cetera? Just trying to reconcile rate base back to earnings growth here, if you will.

Yes. I'll give you one reaction. Maria may have different ones. First -- look, at the end of the day, the customer sees one bill, right? And so we want to make sure we're pulling on all the levers to provide them an affordable experience that's also safe and reliable and clean and also to make sure that we have an appropriate opportunity for our investors to get a return on and off their capital, right?

So kind of stating the blindingly obvious that's important. The other reaction though is that we do have separate proceedings in California. We think we've seen a lot of value in having a separate rate case proceeding from a different cost of capital proceeding. And particularly, as we get to a cost of capital filing, while clearly, I'm sure in the commission's minds, in our minds, we'll all be thinking about the impacts on customers of various increments.

Cost of capital in California is really constructed around ensuring that there's a fair opportunity for investors, for shareholders to -- can get that return often on capital in order to make the California investment an attractive one relative to investments elsewhere in the country and in other marketplaces, right?

And so particularly as we head into a period over the next decade or 2 where the country as a whole will see a dramatic need for investment across all sectors of the economy to decarbonize, it's really important that the regulatory framework in California remain one that is viewed as fair, as stable, as compensatory to shareholders and to all stakeholders and one where, frankly, cost of service principles are respected, right?

And so you're seeing a lot of our advocacy focused on making sure that we are constantly coming back to the central line in terms of what's a fair cost of service and how do we get recovery in that versus what things -- in what areas should the shareholder bear risk of recovery.

And so that's why I like the idea about fairly pure cost of capital proceeding that's just looking at the math and the principles of the policy around what a fair return given the unique risks that utilities are asked to bear in California, given that we are at the leading edge of the clean energy transition.

So anyway, just a few rambling thoughts there, Julien. Maria, anything you want to clean up or change there?

No. I think you've captured it, Pedro.

Thank you. And that was our last question. So I will now turn the call back to Mr. Sam Ramraj.

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