Edison International

Good afternoon and welcome to the Edison International third quarter 2021 financial teleconference. My name is Michelle and I will be your operator today. When we get to the question and answer session, if you have a question, press star one on your phone. 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, Michelle, and welcome, everyone. Our speakers today are President and Chief Executive Officer Pedro Pizarro and Executive Vice President and Chief Financial Officer Maria Rigotti. 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 a Form 10-Q, prepared remarks from Pedro and Maria, and the teleconference presentation. Tomorrow, we will distribute our regular business update presentation. During this call, we'll make forward-looking statements about the outlook for Edison International and its subsidiaries. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our SEC filings. Please read these carefully. The presentation includes certain outlook assumptions as well as reconciliation of non-GAAP measures to the nearest GAAP measure. During the question and answer session, please limit yourself to one question and one follow-up. I will now turn the call over to Pedro.

Well, thank you, Sam. And before I start commenting on the quarter, I wanted to note the senior leadership changes that we announced last week. Kevin Payne, FCE's president and CEO, plans to retire on December 1st, and this is after 35 years with the company. Kevin's had a profound impact of the utility, most particularly with its customer-centric focus, leading our wildfire risk mitigation efforts, and advocating for and advancing the company's clean energy strategy. While I am going to miss my good friend very much, I am delighted with our deep bench. Steve Powell will succeed Kevin as president and CEO, and Jill Anderson, currently Senior Vice President of Customer Service, will succeed Steve as EVP of Operations. Promoting Edison talent will ensure a seamless transition, and I believe that Steve and Jill both bring exceptional experience to their new roles. I know that a number of you have already met Steve and Jill, and many of you will have an opportunity to meet them next week at EEI's financial conference as well. Turning to the quarter, today Edison International reported core earnings per share of $1.69 compared to $1.67 a year ago. This comparison is not meaningful because during the quarter, SCE recorded a true-up for the final decision in track one of its 2021 general rate case, which is retroactive to January 1st. Reflecting the year-to-date performance and our outlook for the remainder of the year, we are narrowing our 2021 EPS guidance range to $4.42 to $4.52. We are also reiterating our longer-term EPS growth target of 5% to 7% through 2025. Maria will discuss her financial performance in detail in her report. Now, starting with past events, FCE today announced two updates related to the 2017 and 2018 wildfire and mudslide events. Page 3 in the slide deck provides an overall summary. First, SCE revised the best estimate of potential losses to $7.5 billion from $6.2 billion. As we have mentioned in our continuing communications on this topic, we evaluate the best estimate quarterly. As part of the ongoing and very complex litigation process, we diligently consider new information that arises to provide all of you with our best estimate. Based on additional information across a broad set of claim types collected during the quarter, along with an agreement with the CPUC Safety and Enforcement Division, or SED, which I'll talk about in a minute, SCE revised its estimate of the total potential losses. While the total estimate increased this quarter, SCE continued to make meaningful progress settling claims and completed approximately $485 million of settlements. SCE has now settled about 70% of the estimated exposure for the 2017 and 2018 events. I want to emphasize that we do not need equity above our previously disclosed 2021 financing plan to fund the higher estimated losses. Maria will address this topic later on the call. Second, the utility reached an agreement with the SED to resolve its investigations into the 2017 and 2018 wildfire and mudslide events and three other 2017 wildfires. As we have previously disclosed, the SED has conducted investigations to assess SED's compliance with applicable rules and regulations in areas affected by the Thomas, Konigstein, and Woolsey fires. It was possible that CPUC would initiate formal enforcement proceedings to pursue fines and penalties for alleged violations, though we were unable to estimate the magnitude or the timing as part of our best estimate. The recently executed agreement, which is subject to CPUC approval, would resolve that uncertainty. The agreement has a total value of $550 million, composed of a $110 million fine, $65 million of shareholder-funded safety measures, and an agreement by SCE to seek cost recovery for $375 million of uninsured claims payments out of the $5.2 billion total in the current best estimate. In the SED agreement, SCE did not admit imprudence, negligence, or liability with respect to the 2017 and 2018 wildfire and mudslide events, and will seek rate recovery of prudently incurred actual losses in excess of available insurance, other than for the $375 million waived under the SED agreement. While SCE disputes a number of the alleged violations, reaching an agreement puts one additional uncertainty behind us. Let me now address the Southern California wildfire season. SCE continues to make solid progress on the execution of its Wildfire Mitigation Plan, or WMP, and its PSPS Action Plan. SCE has installed over 1,000 miles of covered conductor year-to-date, bringing the total to 2,500 miles since program inception. Over the past three years, the utility has replaced about 25% of its overhead distribution power lines in high-fire risk areas with covered conductor. SCE has also performed another annual cycle of inspections in high-fire risk areas, supplemented with additional inspections targeting dry fuel areas. This resulted in approximately 195,000 assets undergoing 360-degree inspections in SCE's high-fire risk area. SCE also continues to be on track to meet most of its goals outlined in our WMP by end of the year, and the scorecard is shown on page four of the slide deck. All these ongoing mitigation actions continue to strengthen our confidence in our utility's overall improved risk profile with respect to wildfires. Turning to page five, we highlight the metrics we showed you last quarter, which are proof points of how FCE believes it has reduced wildfire risk for its customers. We have added an additional metric. Looking back at past wildfire events and considering the utility's current PSPS protocols, we can't quantify the damage that would have been prevented. Using red flag warning days as a proxy for when the utility would use PSPS today, SCE would have prevented over 90% of the structures damaged or destroyed for fires larger than 1,000 acres associated with its infrastructure. However, we think it is much more important to assess how much total risk SCE has reduced on a forward-looking basis. And we have summarizes on page six. In total, considering physical mitigation measures such as covered conductor, operational practices such as street removals, inspections, and vegetation management, and the use of PSPS, SCE estimates that it has reduced the probability of losses from catastrophic wildfires by 55 to 65 percent relative to pre-2018 levels. This is based on a recent analysis using risk management solutions industry-leading wildfire model and SCE's data related to actual mitigations deployed and mitigation effectiveness, which enabled us to quantify the risk reduction. While the risk can never be fully eliminated, the utility does expect to further reduce risk and to decrease the need for PSPS to achieve this risk reduction with continued grid hardening investments. As California continues to transition to a clean energy economy, maintaining and even improving system reliability becomes essential, particularly with greater reliance on electricity. SCE worked closely with the governor's office, CalISO, the CPUC, customers, and many stakeholders to avoid rolling outages this past summer, when the state and the entire West once again faced record temperatures. Major California energy agencies, including the Cal ISO, California Energy Commission, and CPUC have indicated that additional capacity is needed to support summer 2020, summer 2022, pardon me, under extreme conditions like the heat, drought, and wildfires we have seen repeatedly over the past several years. To accelerate construction of new capacity, the governor issued an emergency proclamation that requested the CPUC to work with load serving entities to accelerate construction of energy storage for 2021 and 2022. To this end, in addition to securing over 230 megawatts of additional capacity from third parties, SCE plans to construct about 535 megawatts of utility-owned storage for this upcoming summer. This is a material increase in incremental capacity to mitigate the risk of statewide customer outages for summer 2022, caused by extreme weather events and continued drought conditions. While the governor signed the largest climate package in state history, which included 24 bills and over $15 billion in climate, clean energy, and wildfire preparedness funding, there is still an ongoing need for a lot more to be done. So I would like to highlight a paper that we recently released, and it's entitled Mind the Gap, Policies for California's Countdown to 2030. This policy paper is Edison International's latest contribution to identify policies and actions needed to help California reduce emissions and decarbonize the economy. In the paper, we identified state and federal policy recommendations needed for California to meet its 2030 climate target, which is a foundational waypoint for the states to achieve its goal to decarbonize its economy by 2045. While California has made progress in reducing GHG emissions, Closing the gap between the current trajectory and its 2030 goal requires a significant acceleration of effort. It means quadrupling the average 1% annual reduction in GHG emissions achieved by the state since 2006, quadrupling that to 4.1% per year between 2021 and 2030. That's a tall order, but it's feasible. It will require market transforming policies and incentives to advance critical areas such as de-carbonizing the power supply, preparing the grid for shifts in usage and increasing demands, and electrifying transportation and buildings. As the only all-electric investor-owned utility in California, SCE is well-positioned to lead this transition. We will continue to work in close partnership with policymakers and stakeholders to identify ways to improve funding, planning, standard setting, and other approaches to successfully achieve the equitable and affordable transition to a clean energy economy. To emphasize affordability, our analysis shows that an electric-led transition is the most affordable pathway, since the greater efficiency of electric motors and appliances will reduce customers' total costs across all energy commodities by one-third by 2045. Edison International is committed to achieving net-zero GHG emissions across scopes one, two, and three by 2045, and this covers the power SCE delivers to customers as well as Edison International's enterprise-wide operations, including supply chain. This all continues our alignment with the broad policies needed to address climate change and ensure a resilient grid. We will also continue to engage with state, national, and global leaders to advance the clean energy transition, which is why today I am joining you by phone from COP26 in Glasgow, Scotland, where I am representing both Edison and EEI. And with that, Maria will provide her financial report.

Thank you, Pedro, and good afternoon, everyone. My comments today will cover third quarter 2021 results, our capital expenditure and rate-based forecasts, and updates on other financial topics. Edison International reported core earnings of $1.69 per share for the third quarter 2021, an increase of 2 cents per share from the same period last year. As Pedro noted earlier, this year-over-year comparison is not particularly meaningful. because SCE recorded a true-up for the final decision in its 2021 general rate case, and that's retroactive back to January 1st. On page seven, you can see SCE's key third quarter EPS drivers on the right-hand side. I will highlight the primary contributors to the variance. To begin, SCE received a final decision in the 2021 GRC during the third quarter. Because first and second quarter results were based on 2020 authorized revenue, a true-up was recorded during the quarter for the first six months of 2021. This true-up is reflected in several line items on the income statement for a net increase in earnings of $0.35. The components are listed in Footnote 3. Higher 2021 revenues contributed $0.55, including $0.50 related to the 2021 GRC decision, $0.04 for CPC revenues related to certain tracking accounts, and $0.01 at FERC. O&M had a positive variance of 28 cents, mainly due to the establishment of the vegetation management and risk management balancing accounts, partially offset by increased wildfire mitigation costs due to the timing of regulatory deferrals in the third quarter of 2020. Depreciation had a negative variance of 20 cents, primarily driven by a higher asset base and a higher depreciation rate resulting from the 2021 GRC decision. Income taxes had a negative variance of 41 cents. This includes 39 cents of lower tax benefits related to balancing accounts and the GRC True-Ups, which are offset in revenue and have no earnings impact. At EIX, Parents and Other, the loss per share was nine cents higher than in third quarter 2020. The primary driver was preferred dividends on the $1.25 billion of preferred equity issued at the parent in March of this year. Now let's move to SCE's capital expenditure and rate-based growth forecast. As shown on page eight, we have updated our capital forecast primarily to reflect the recently announced utility-owned storage investment. As Pedro mentioned, SCE filed an advice letter for cost recovery of $1 billion of capital spending to construct about 535 megawatts of utility-owned storage. SCE is seeking expedited approval of the advice letter to maximize the likelihood of the projects meeting their expected online dates for the incremental capacity needed for summer 2022. These projects are a prime example of the essential role utilities can play in quickly ensuring California has a safe, reliable, and clean electricity supply. We increased our 2022 capital expenditure forecast by approximately $900 million and lowered the forecast somewhat for 2023 through 2025. because these storage projects accelerate some, but not all, of the capacity we previously forecasted in those years. The net increase in the high end of the capital forecast for 2021 through 2025 is approximately $500 million. As shown on page nine, we have also updated our rate-based forecast to reflect the storage investments I just mentioned. This is the primary driver of the increase to 2022 For 2021, we also fine-tuned the forecast to reflect adjustments related to wildfire mitigation tracking counts following the implementation of the 2021 GRC decision and quarter-end estimates of the spending related to these accounts. The results of these updates is a reduction to the 2021 rate base of $300 million. Overall, these updates result in a projected rate-based growth rate of 7 to 9 percent from 2021 to 2025. Page 10 provides an update on several major approved and pending applications for recovery of amounts in regulatory assets. This will result in significant incremental cash flow to SCE over the next few years. SCE expects to collect over $1.4 billion in rates between now and 2024 related to already approved applications. About half of that balance will be recovered in 2022. For the three pending applications shown in the middle of the slide, Assuming timely regulatory decisions, SCE expects to collect another $844 million by the end of 2023. Lastly, we show the remaining expected securitizations of AB 1054 capital expenditures. The utility recently received a final decision in its second securitization application. This will allow SCE to securitize $518 million of wildfire mitigation capital expenditures. SCE expects to complete the securitization in Q4 of this year or Q1 2022. The securitizations, along with the rate recovery of the other regulatory assets, will allow SCE to pay down short-term debt and strengthen our balance sheet and credit metrics. Turning to page 11, during the quarter, SCE filed an application to establish its CPUC cost of capital for 2022 through 2024 and reset the cost of capital mechanism. SCE is requesting an ROE of 10.53% with resets to its cost of debt and preferred financing, which would keep customer rates unchanged. The utility's alternative request to maintain its ROE at 10.3% and reset the cost of debt and preferred would reduce customer rates by about $50 million in 2022. When SCE filed the cost of capital request in August, it paused any other filings related to the trigger mechanism. Last week, SCE was directed by the CPC to file the information that would have normally been provided in those other filings. The next step from here is that the Commission will issue a scoping memo to outline the issues and procedural schedule. Turning to guidance, pages 12 and 13 show our 2021 guidance and the preliminary modeling considerations for 2022. As Pedro mentioned earlier, we are narrowing the 2021 EPS guidance range. to $4.42 to $4.52. Turning to page 14, we see an average need of up to $250 million of equity content annually through 2025. The specific annual amounts will depend on the level of spending within our capital plan for that year. The significant new investment of $1 billion of utility-owned storage considerably accelerates the timing of the capital investment program and increases the overall opportunity as noted earlier. To fund this growth, which is well above the high end of the capital spending range previously disclosed for next year, equity content securities from 2023 through 2025 period into 2022. The 2022 equity need will be in the range of $300 to $400 million, and we will provide more specifics on the financing plan when we provide 2022 EPS guidance on the fourth quarter 2021 earnings call. Additionally, let me reiterate Pedro's comment that the SED agreement and update to the best estimate of potential losses associated with the 2017 and 2018 wildfire and mudslide events do not require equity above the levels previously announced in our 2021 financing plan. Consistent with our prior disclosure, we plan to issue securities with up to $1 billion of equity content to support investment grade ratings. In closing, I want to underscore the important role that SCE plays in ensuring safety and resiliency. This can be seen in the ongoing investment in risk-reducing wildfire mitigation, as well as utility-owned storage to enhance near-term reliability. These investments are indicative of the longer-term opportunity associated with meeting customer needs and clean energy objectives, and gives us confidence in reiterating our long-term EPS growth rate of 5 to 7 percent for 2021 through 2025. That concludes my remarks.

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

Thank you, sir. If you would like to ask a question, please press star 1 on your phone. One moment for the first question, please. Jeremy Tenet from J.P. Morgan, you may go ahead, sir.

Hi, good afternoon and good evening.

Thanks, Jeremy.

First question here, just wondering, how does the Safety Enforcement Division agreement impact the settlement process for those remaining claims, if at all? And then do you have any updated thoughts on when you would be able to file for recovery here?

Yeah, so let me take both of those. We don't really see any impact that the SCD settlement will have, the SCD agreement will have on settlement activity. And importantly, as you heard me say, we didn't admit any claims there of ourselves of imprudence or the like. In terms of timing for cost recovery, that continues to be uncertain because we really need to work our way through a substantial portion of the claims in each of the events. We could potentially... get through Thomas and Koenigstein on one track and separately on Woolsey. But I think we need to get through the bulk of the claims in each of the events before we would be able to go file the PUC. And as I've said in prior calls, it's just really difficult to handicap the timing. Now, we've made good progress. And as I mentioned, we've worked our way to something like 70% of the claims. But it's difficult to handicap when exactly we'll complete that process.

Got it. That's helpful. And then just wanted to pivot a little bit here and want to talk about resiliency investment potential. Just wondering if I, I guess, updated thoughts on what the total opportunity set could look for, for capital investments and resiliency investments.

Yeah. You know, I, you know, I would point you back to the rate base, you know, forecast that we provided, you know, the five-year view and say that, elements like the storage project that we just announced is, you know, supportive of that range we've painted. So, you know, you heard us, you know, reaffirm that view of, you know, when you translate it into earnings or EPS growth, you know, 5% to 7%, you know, EPS growth coming from that. And so we would view the opportunity set as falling within that range. You know, the storage project shows you that sometimes there can be needs that pop up sooner than we might think and, you know, the ability to step in and take a meaningful action that will help the state with its resiliency and reliability in case that next summer ends up being one with extreme weather just like the last couple summers have been. It's just one indication that, you know, sometimes you can be called on to take those steps more quickly or in a large quantum like you see with this storage project. But I would say that we would continue to see the opportunities falling within the range that we provided. Maria, anything you would say differently there?

No, I think that we have covered the waterfront in that range, Jeremy. We think about resiliency from the perspective of additional wildfire mitigation. We think about resiliency from the perspective of storage. building electrification because we know we have to pursue those sorts of investments if we're going to get to those GHG emissions reductions. So I think that that whole range is covered in the capital forecast that we've laid out for you.

Got it. That's helpful. I'll leave it there. Thanks.

Thanks, Jeremy. Thank you. Our next caller is Char Pereza with Guggenheim. Partners, you may go ahead, sir.

Hey, guys.

Hey, Char. Hey, Char.

Hey, guys. Hey, Patrice. Just maybe just bridging today's disclosures to your equity needs. So with the new estimates for the aggregate wildfire liability going up by 1.3 and the CPC agreement to not seek recovery of a portion of that, just on the reiterated equity of $1 billion, is that for the current plan 325, i.e., does the timing of paying out the claims impact that equity? And kind of related, Pedro, Why settle now if you feel strong enough about prudence ahead of seeking recovery?

Yeah, let me take your last question first, and then Maria can fill in on the equity piece. And, you know, I refer again to my prepared remarks here. The LCD has... you know, powers and responsibility to do investigations. There's always uncertainty when you go into those processes. There's uncertainty as well in terms of how the CPUC will ultimately, you know, view, you know, the facts. We, as I mentioned, don't agree with a number of the claims, but we recognize that there's a process here and we believe it was a thoughtful thing, a prudent thing for us to do to, put one more uncertainty behind us. And we therefore feel that the settlement is a way to do that. And so that's really the why now, an opportunity presented itself to work with the SED. And you see the makeup of the pieces here. We don't see that interfering with our ability to go seek cost recovery for prudently incurred expenses other than for the $375 million that were set aside in the settlement. And so, again, it's frankly all about understanding that there's a lot of uncertainty and sometimes it's rational and kind of the right thing to do to do something there. Maybe we might not have agreed with, you know, overall in their different circumstances. But in this case, by entering the settlement and, you know, working constructively with SED, we can put that uncertainty behind us. Maria, do you take the equity piece?

Sure. So, Char, you know, we talked a bunch before about our 2021 financing plan and the, you know, need to issue up to a billion dollars of equity content securities. And that was really, you know, to support the the 15-70% FFO to debt framework that we have at the company. And so as we assess the change in the reserve level, we think that that billion dollars of equity content in 2021 still supports our overall, you know, financing framework objective. And, you know, we've been pretty measured in how we approach issuing that additional equity or equity content securities. At the same time, at the same time, SCE does issue debt to make claims payments. So if you think about the EIX financing plan that's in support of the metrics, and then SCE's cash flow is tied to sort of when they issue debt to pay the claims. At that level, the SCE level, they are basically pacing their financing plan along the same lines as when they make claims payments. I think when you think about the equity requirement that we have for this year, we've already done $1.25 billion of that. preferred financing to get a certain amount of the equity content, and we'll continue to evaluate market conditions as we undertake the balance of the program.

Got it, got it. And then just lastly for me, just on thoughts on the capex and rate-based growth from 24 to 25, there's like a significant step up in the expectations in slide A with sort of the range case staying flat from 23. What is included in that top end of that capex on the slide, any color in what is covered, you know, under the GRC versus incremental programs like, you know, reliability storage spending in 22. Thanks.

Sure. And you cut out just a tiny bit at the end, at least for me, but I think I got your question, Char. So if you move out in time, obviously, in the front end, we have authorized, you know, we have the 2021 GRC decision. Now, harking back to the utility on storage, you can have things happen. even in the near term, that increase your capital expenditure opportunities. But if you move out to 24 and 25, I think there are a few things going on. One, 2024 is a year in this rate case cycle that we haven't yet gotten authorization for. So while it might look a lot like the attrition mechanism that's embedded in 2021 and 22 and 23, we do know there are some budget-based opportunities approaches that we can use for wildfire mitigation. So we'll be focused on that and that can expand the range. If you look out beyond that, 2025 is actually a new rate case cycle. And so things like ongoing wildfire mitigation, but as we start to get back potentially to more infrastructure replacement and the like, you know, that could drive, you know, the wider range that you see in the back end. In addition, there are opportunities, you know, potentially to file applications outside of the general rate case proceedings. And so all the things that I think Pedro mentioned earlier around, you know, are there things around greenhouse gas emissions reductions on the path to 2045, areas around transportation electrification or building electrification or more energy storage or transmission. Those are all things that move the range up and down.

Got it. Fantastic, guys. I appreciate it. I'll stop there. See you soon.

Thanks, Howard.

Thank you. Our next caller is Steve Fleshman with Wolf. You may go ahead, sir.

Hey, Steve. Hello. Just I guess in terms of the reserve for the wildfire claims, could you maybe explain as best as possible why the number went up and this has happened a couple times and why we should assume it's not going to happen more?

Yeah, thanks, Steve. And I think we covered it a bit in the previous remarks, but it's definitely worth doubling down on. Simply put, the more claims we go through, the more settlements we do, the more we learn. And I would hope that that uncertainty band continues to narrow. As I mentioned, we're now a process around 70% of the exposure rate. And so we have been testing quarterly to see whether there are new pieces of information, you know, more detail in terms of specific claims that are, you know, waiting down the pipe, et cetera, that, you know, would call for a need to change the reserves. We did not need to do that the prior quarter as we got through this quarter. we had enough new information in hand that this was, you know, the right thing to do, the appropriate thing to do under GAAP was to, you know, make the reserve adjustment. I would, you know, and as we say in our disclosures, right, we're providing you the best estimate. There is uncertainty around that best estimate. In the end, we might find that things go yet higher again. We might find that things, you know, end up lower than this. but I would hope that as more time goes on and, again, as we get more of the volume behind us, that picture will, you know, continue to sharpen. That's probably the best I can do here, Steve, you know, and I realize that it would be great if we could provide, you know, more chapter and verse on what drove it, but given the active litigation that we have going on, that's challenging to do. Maria, anything to say differently? Or Adam Umanoff, if you want to come on the line from a legal perspective, feel free.

Okay. Okay, thanks.

And so just a related question on the SED settlement portion. So on the one hand, you agreed not to seek $375 million. On the other hand, that would imply that theoretically you might seek recovery of a lot of the other cost of this, which obviously is not assumed in your plan. So even though on the surface that seems like a negative, is it possible to read this as that you still have a claim and potential to seek recovery of these costs?

Yeah, Steve, we've been pretty consistent in saying all along that our plan expectation is to seek recovery for prudently incurred costs. For purposes of striking the settlement and removing this uncertainty, we agreed to set aside that $375 million. But importantly, as I said earlier, we're not admitting to imprudence. We're not admitting to negligence. Uh, we're preserving every rights to go, uh, and seek cost recovery. Um, I can't tell you today, uh, you know, the precise figure for which we'll seek recovery, um, because we'll continue complete investigations. I think I said this in prior quarters, believe it or not, it's still true that I believe we still don't have our hands on some pieces of equipment, uh, because they're still being held, uh, by, by, um, fire agencies. And that's just as part of the process. But our expectation is that there are certainly a number of strong arguments we'll be able to bring to the table and we'd expect to seek recovery for everything that we believe we should seek recovery for. Now, the reason that you're not seeing that level of, I'll say confidence, show up in adjusting the reserve to include the assumption of recovery is that since these are 2017 and 2018 events, and the only CPUC precedent that exists prior to the timeframe of AB 1054 is the precedent in the San Diego Gas and Electric case under GAP, we're really not able to assume any CPUC recovery. That said, you see that we've continued to assume recovery from FERC for the same set of facts. And so that, I think, points to... our sense that recovery would be appropriate based on the facts. We can't assume it from the CPUC based on the San Diego Gas and Electric precedent, but we will plan to make our case. And we said before also that we believe that the CPUC's determination in the San Diego case was inconsistent with what we understood the facts to be in that case. So while AB 1054 provides us a strengthening of the framework We do believe that, you know, we had the ability all along to, even prior to AB 1054, to make our case for just and reasonable cost recovery based on facts, and we believe we'll have those facts here.

Great. Thank you. Thanks, Steve.

Thank you. Ryan Levine from Citi. You may go ahead, sir.

Hi, everybody. During the quarter, it looked like FCE received about $400 million of cash from the Morongo transaction. transmission asset for use of the asset for about 30 years. Are there any other similar opportunities in the portfolio to raise capital to help offset some of these equity needs?

Hi, Ryan, it's Maria. Yeah, so that actual transaction has been part of that project for many, many years. And the trigger for it was when the project was completed and became commercial. So that was the genesis of that $400 million. And you're right, it did happen over the summer. I think we've talked a little bit about this before in terms of just the overall portfolio. The things that FDE owns, basically, they're really customer assets, and so the opportunity to sell a bunch of assets isn't really available to us in the sense that you're talking about. I think from time to time, people have asked about real estate and the like, but there's really not an opportunity in this portfolio.

Thank you. And then in the prepared material, it was referenced that the settlement process for Woolsey and TKM increased in pace, which helped drive the increased estimate. What's the current outlook from the pace from here for the settlement process?

Well, I think that's what I touched on earlier, right? We continue to work really diligently on this. But, Ryan, you know, it's just really hard for us to forecast when we will be substantially complete with it. So the good news is there's, you know, we've mentioned this in prior calls, there's structural processes in place for both the Thomas Connick Stein and, you know, we'll see cases that are allowing us to work our way through, you know, a good volume of these cases every month. But just really difficult to handicap what that means in terms of ultimate timing.

Okay, and then last one. As you continue to implement the Covered Conductor Plan, are you noticing any improvement in the cost per mile as the plan is implemented?

I think we've been pretty constant around the cost per mile. I mean, we haven't seen big increases, but we haven't seen decreases either. I think we actually got it pretty spot on when we made the initial estimates.

Appreciate it. Thank you. Thanks a lot, Ryan.

Thank you. Our next caller is Michael Lapidus from Goldman Sachs. You may go ahead.

Hey, guys. Hey, Pedro. Just a little bit of a macro question, which is you're proposing, as you did in the GRC, covered conductors. Your neighbor to the north is proposing kind of a, you know, kind of more the undergrounding program. I hadn't seen anything material different out of SDG&E in a while. Just curious, do you think there is a need for a piece of follow-on legislation where the state develops a formal multi-year, maybe more multi-decade, kind of similar to like what Illinois has with gas distribution or what Florida has with storm hardening, to help kind of think through both the timeline, the pace of investment, the cost recovery, and and kind of the broader state strategy in terms of doing things for wildfire mitigation and prevention?

Yeah, that's an interesting question, Michael. Thanks. I'll give you my quick reaction to that, which is I don't think we need legislation for that. I actually say that in many ways, AB 1054 provided the framework for that already, right? Because it set up the whole wildfire mitigation plan process It has review by OEIS. It has certification by the CPUC. In addition, the state budget this year included a line item for an outside consultant who is advising the governor's office and is actually working with the utilities. you know, it's become a good venue for conversation and comparing of notes in addition to the work that we do, you know, interfacing directly with our peers at the other utilities. But ultimately, I view the welfare mitigation plan framework as the place where utilities are bringing, you know, updated information and, you know, new ideas about what what tools they should be using to prevent fires. And then ultimately that feeds into the ramp and GRC processes. The other reason that that's my reaction, Michael, is that this is something that's important in the WMP framework. The reality is that each of the utilities have fairly different territories. I mean, from the outside, it looks like it's all California, right? But PG&E has 70,000 square miles. We have 50,000. San Diego has a much smaller territory. But even if you look at PG&E versus ourselves, and I have mentioned this in prior calls, the territory for PG&E, the high fire risk area territory, includes a lot more geography that's more heavily forested. And so, for example, for them, as we understand it from our discussions with them, they see a lot higher probability of ignition from trees falling into lines. Those could be trees well outside of the vegetation management zone, the foliage trimming zone. In Edison's case, much of the high-fire risk area is not forest. It's chaparral. It's grasslands. There's a much higher probability of ignition throughout the Edison area for ignition from contact from objects, you know, stuff blowing into the lines. And so, you know, that helps give a little bit of insight into why for PG&E as they run the math, and I think generally we're all using the same math equation, but the variable, the values of the variables are different, right? And so as they look at the cost-benefit analysis for undergrounding versus covered conductor or other tools, My understanding is that the trees falling in drives a lot of the incremental benefit from undergrounding. In our case, we see that covered conductor provides significant risk reduction at a much lower all-in cost. In addition, in SE's territory, since we had already gone through a pole loading program that led to pole replacements, That means that a lot of our covered conductor installations, we don't have to go out and replace the pole, right? And so that takes out another cost increment that, you know, a utility might have if they need to not only replace the wires, but also replace the poles they hang on. That's a little long-winded. The bottom line on that is that we have fairly different territories. different needs we're comparing notes i think we used to have seen fundamental concepts um but the the values you stick into the equation are leading to different results you know for each of us but we're staying connected right and to the extent that um you know engineering continues to learn more and see different results with underground and you know we could potentially see more miles coming to scope for underground and for edison so we certainly continue to learn there

Got it. Thank you, Pedro.

Much appreciated. Pedro. Yeah, Maria. Michael, just one more thing, since you're asking about it from sort of a macro perspective. While legislation to help the utilities might be something that's already been addressed in AB 1064, we do keep an eye on and definitely would support additional legislation that really addresses things like land management and forest management and home hardening and development in the WUI, because those are things that are going to have to be addressed if we really want to have a long-term mitigation to this issue.

It's a great point, Maria. Thank you, Maria.

Thank you. Jonathan Arnold from Vertical Research. You may go ahead. Hi, Jonathan.

Good afternoon, guys. Just to make sure I understand these numbers on the accrual correctly, is the $550 million settlement that's now in the best, that's part of the increase in the best estimate, is that correct?

Yeah, so there are three components to the 550, Jonathan. There's 110 that's a payment to the general fund, there's $65 million of mitigation activity that we'll undertake, and there's that $375 million of foregone recovery. Because we haven't taken a regulatory asset against the 375, that has already been part of our overall cost of the events of 2017 and 2018. So that's part of the $7.5 billion best estimate, effectively, all of it. Yep, all of it. But it's not part of the...

resolved? Is it all considered unresolved from the perspective of the difference between the 7-5 and the 2-2?

Well, it's all in that number, the 7-5. In terms of cash flows, obviously, we have different timeframes around which we have to make payments to the general fund and we have to make the mitigation investments. So those cash flows haven't gone yet. I think your question is the cash flow question.

My question is if the CPUC approves the settlement, will the $2.2 billion of remaining expected losses effectively go down by $5.50 because that will now be resolved or at least no longer uncertain?

No, the $2.2 remaining will go down as we make actual cash payments for settlements or payment to the general fund, or, you know, mitigation payment.

Okay, so that's still the difference. That's how the 2-2 does.

So just to be really clear, the SCD is viewed as resolved, not unresolved.

It's viewed as resolved.

Right.

Okay. Pending approval.

This is pending approval, but I think for purposes of the 6.2 versus 7.5.

Great. Thank you.

Thanks, Jonathan.

Thank you. Julian Dumoulin-Smith from Bank of America. You may go ahead, sir.

Hey, Julian. Hey, afternoon team. Thank you for the time. If I can just review the fact pattern here, I just want to make sure we're crystal clear about the equity needs here and the moving pieces here. So in the remarks, you specifically called out the 21 financing plan does not require incremental equity, and then you also kept intact the incremental equity from 22 to 25. I just want to understand how that fits together considering the fine piece and considering – well, I'll leave it open-ended. Can you rehash that quickly?

Sure, absolutely. And I think, Julian, you know that we've been really measured in the approach that we've taken to issuing additional equity and equity content securities. And we've been watching the cash flows and the like. And in our 2021 financing plan, we did envision that up to a billion dollars of equity content. And so as we thought about and assessed the change in the reserve level, we were looking at what we had already announced as our 2021 plan, and we think that it's still consistent, even with the reserve level changing, with the objective of improving credit metrics over time with that focus on the 15% to 17%. Now, the equity that we've discussed for next year and that we'll discuss in more detail when we get to – the Q4 call, that really relates to sort of how we were thinking about, you know, the equity needs over the next, you know, four years through 2025 related to the growth of the utility. And so let's think back a little bit on how that ties together. So previously, when we laid out that 21 through 2025 EPS CAGR, we talked about the EPS CAGR of 5% to 7%. We still firmly believe that that is the range that we're in. And in terms of total equity needs over the period, we talked about, you know, up to $250 million a year, to some extent, you know, varying based on the capital that was needed in that year. As we look over that period, while we've got $900 million more capex in 2022, which obviously that's in response to customer needs and the state needs with some reliability, and that's on top of an already robust capital plan, we want to basically take some of the equity that otherwise otherwise would have turned up in later years and rebalance that to 2022. And that's, again, in support of our metrics. So, you know, that's, you know, just kind of the balance that we're always trying to strike. And so those are how I think about the pieces of the equity need and how we thought through them, you know, as we developed the plan for the balance of this year and then for next year.

Got it. Excellent. All righty. Well, I will leave it there.

All right.

Thanks, Julian.

Thank you. And that was the last question. I will now turn the call back over to Mr. Sam Ramraj. Thank you, sir.

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

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.