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Hello. My name is Chris, and I’ll be your conference operator today. At this time, I’d like to welcome everyone to the PG&E Corporation Third Quarter 2023 Earnings Release. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. [Operator Instructions] Thank you, Jonathan Arnold, Vice President, Investor Relations. You may begin.

Good morning, everyone, and thank you for joining us for PG&E’s Third Quarter 2023 Earnings Call. With us today are Patti Poppe, Chief Executive Officer; and Carolyn Burke, Executive Vice President and Chief Financial Officer. We also have other members of the leadership team here with us in our Oakland headquarters. First, I should remind you that today’s discussion will include forward-looking statements about our outlook for future financial results. These statements are based on information currently available to management. Some of the important factors, which could affect our actual financial results are described on the second page of today’s third quarter presentation. The presentation also includes a reconciliation between non-GAAP and GAAP financial measures. The slides along with other relevant information can be found online at investor.pgecorp.com. We would also encourage you to review our quarterly report on Form 10-Q for the quarter ended September 30, 2023. With that, it’s my pleasure to hand the call over to our CEO, Patti Poppe.

Thank you, Jonathan, and good morning, everyone. I’m pleased to report another quarter of solid progress. As you’ll see on Slide three, our core earnings per share of $0.24 for the third quarter bring us to $0.76 for the first 9 months of 2023. We continue to work through the review process of our general rate case at the California Public Utilities Commission and have, therefore, not yet recognized the benefit in our earnings. With the customary memo account in place, once we receive the final order, we will book the new GRC revenues starting from the January 1, 2023 effective date. As you may know, our general rate case is on the agenda for CPUC’s November 2 voting meeting next week, and we trust that the commission appreciates the importance of reaching a timely and constructive resolution, one which provides sufficient cash flow to support the critical work we have in front of us. If the GRC is not voted out next week, there are two further voting meetings in November one on the 16th and one on the 30th. Resolving our GRC will be a key milestone as it sets our CPUC base revenue through 2026. While we await the final decision, our memo account allows us to reaffirm our 2023 guidance range of $1.19 to $1.23. We also reaffirm our commitment to at least 10% earnings per share growth in 2024 and at least 9% in both 2025 and 2026, along with our plan for no new equity issuance through 2024. Looking ahead, once we have the final GRC decision, we anticipate scheduling a follow-up investor call, and we look forward to providing you with a more granular update on our financial plan at the time. Then on our year-end call in February, you should expect further detail around our investment plans. With respect to reinstating our common dividend, we recognize how important this is to traditional utility and income investors, and we look forward to recommending this important step to our Board soon. Turning back to our GRC. In our filed comments with the CPUC as well as in our public advocacy, we have been vocal that we view the ALJ’s proposed decision or PD and the assigned commissioner’s alternate proposal proposed decision, or APD, as falling short of providing the funding to accomplish the necessary safety work we have proposed on behalf of customers. As we have said, we are disappointed at the PDs apparent willingness to trade safety and reliability for short-term cost considerations. This is critical work, and in many cases, work that is required for us to execute on the safety commitments we make in our annual wildfire mitigation plan or under other regulatory orders. One good example, and there are others, is that the current PDs declined to fund over $260 million of capital for corrective maintenance of our gas meters. This work is not optional and is, in fact, required for compliance with CPUC General Order 58-A, which sets the state-wide standards for gas service in California. Unless the CPUC makes meaningful changes to the cash flow elements of the current PDs, we will have to slow down making our system safer and delay meeting legislative directives and regulatory requirements. My management team and I stand for delivering safety, reliability and affordability. We believe that our plan, thanks to the simple affordable model offers a clear pathway to keep build growth well below the current level of inflation at 2% to 4% annually over the rate case period. The CPUC’s GRC process is designed to get the best outcome, and the state has been very clear about the infrastructure they want us to build. We stand by our filing and continue to view our undergrounding plan as the fastest and most affordable path to keep our customers safe. To that end, we have been encouraged by significant statements of support received from our local leaders and stakeholders. Aside from the GRC on Slide four, we continue to mitigate physical and financial risk. On the physical side, we’re pleased with our continued progress mitigating wildfire risk through our layers of protection strategy. This remains at the heart of our plan, and we stand unapologetically on the side of public safety. In Sacramento, this year’s legislative session included a number of bills which sought to address the very real challenges utilities have had keeping up with customer growth. Since our last update, the SB 410 Energization Bill was passed by the legislature and signed into law by Governor Newsom. We viewed SB 410 as a constructive solution, allowing us to deliver the necessary work for our customers with more timely cost recovery. One key provision is for the CPUC to establish a ratemaking mechanism allowing for recovery of energization investment above what is approved in our GRC. We believe this is appropriate given the fast-moving and unpredictable nature of electrification-related customer demand and emerging and high-quality problem for any utility would love to have. In the newly opened Phase 2 of our GRC, we’ve proposed a new balancing account to implement the provisions of SB 410. Keeping affordability in mind, our proposal would cap annual incremental customer bill impact at 2.5% of electric distribution rates. This could amount to over $200 million of annual revenue, supporting close to $1.5 billion of increase of incremental capital investment. The ratemaking mechanism in addition to the GRC authorized funding will allow an estimated 300-plus distribution capacity projects and over 35,000 new business connections over the next three years if the proposed rate-making mechanism is adopted. As with the pending GRC decision, it’s critical that the Phase 2 proceeding support the necessary cash flow and timely resolution to do the work our legislature has directed and on the time line our customers are requesting. Since our last call, we’ve also made progress on legacy legal risk, reaching a settlement with the CPUC’s Safety and Enforcement Division with respect to the Dixie fire. This was for $45 million, most to be spent on the new electronic record system over five years. We continue to maintain we were a prudent operator and our settlement with SED specifically preserves our ability to apply for cost recovery, both from the CPUC and from the state Wildfire Fund. Turning to Slide five. Our layers of protection strategy continue to underpin our approach to wildfire risk as we strive to make our communities safer each and every day. We’ve now completed the work, which improves our risk reduction from 90% at the start of the year to 94%, in line with our 2023 wildfire mitigation plan. Much of this year’s improvement relates to installing down conductor detection technology, supplementing our enhanced power line safety settings and public safety power shutoff programs. Other improvements this year include securing AFA [Ph] approval for beyond line of sight drone inspections and integration of artificial intelligence for smoke detection on 610 cameras covering over 91% of PG&E’s high fire risk areas. Our latest wildfire mitigation plan is working through the review process with the Office of Energy Infrastructure Safety or OEIS. Last month, we submitted our supplemental response to their revision notice and their updated schedule calls for a draft decision by November 14 with a final decision by December 29. As directed, we’re expecting to file for our 2023 safety certificate by December 12. And remember that under AB 1054, the current certificate remains in full force, while OEIS reviews the new request. Turning slide six. Let’s review our wildfire season performance to date. First, we are pleased to report that we are on track with our primary goal of zero catastrophic wildfire ignitions associated with PG&E equipment. As of October 22, CPUC reportable admissions in our high-risk zones are down 27% from last year and down 67% from 2017. The extended period of winter storms we experienced in 2023 certainly delayed the start of fire season, but this also led to an abundance of growth and fuel once conditions dried out. While we are really pleased with the headline data, variances and weather conditions from year-to-year can create some comparability challenges. To account for this, we track a weather-normalized ignition rate. We expressed this as ignitions per 100,000 circuit mile days under R3 or higher conditions, as measured by our Fire Potential Index. We’ve seen the ignition rate decline by 70% overall since 2017, including significant step-downs in 2021 and 2022, validating our layers of protection approach. This year, through mid-October, I am pleased to report that we’ve seen our weather-normalized ignition rate come down by a further 7% versus 2022. One point I want to reinforce, at PG&E, we’re ready every day for dangerous conditions. Our layers of protection do not rely on weather being in our favor. We’ve implemented state-of-the-art situational readiness technology, tools and people -- we treat every day as a high-risk day. This is the mind-set that will protect our customers and our communities. No matter the conditions we are ready. A good example is our use of public safety power shutoffs. Last year, we didn’t need to activate any PSPS events since we did not experience sufficiently high-risk wind conditions. This year, we’ve initiated two PSPS events, one in August and one in September, and both were quite localized. Through our enhanced situational awareness, which breaks the system down into 2-kilometer polygons, along with our extensive use of data and advanced meteorology, we are continuing to refine our PSPS capabilities. Our program is now far more surgical than when we first rolled it out in 2018. Because of those improvements, our PSPS events only affected around 3,900 customers in August and 1,200 in September. Our post-event analysis shows that our 2023 shutoffs prevented two likely ignitions and close to 30,000 acres, which might have otherwise burned. We are standing for our hometown and are resolved the catastrophic wildfires shall stop. PSPS and EPSS our enhanced Powerline safety settings program have been very effective at reducing ignitions. But both present unacceptable reliability challenges for customers. That’s why we see undergrounding as the right long-term infrastructure for the very specific high-risk miles identified in our 10,000-mile plan and affordable for customers at $3.40 per month for the average noncare residential customers. In fact, based on our analysis over the expected life of the assets to be installed during the GRC period, our proposal returns billions of dollars more in net present value compared to the APD. Just like our layers of physical protection, our financial plan also includes multiple layers of protection as illustrated on Slide seven. The orange wedge represents the difference between the APD rate base and our guidance midpoint. Most critically, our layers of protection include improving on the cash elements of the rate case PDs, which we are working hard to do in our advocacy. There are also three items where the PDs do not recommend this allowances, but instead shift cost recovery into other future proceedings. These include future Whimsy [Ph] or equivalent filings incremental spending on energization as provided under SB 410 and our 10-year undergrounding plan under SB 884. We also see no shortage of incremental investment headroom in our FERC jurisdiction rate base. Keep in mind that capital investment for the benefit of customers’ needs can be offset with O&M reductions and efficient financing, along with low growth to make sure safe infrastructure is also affordable. This is the heart of our simple, affordable model. Our regulators and key stakeholders are just becoming familiar with this model. And we must implement it in a very trustworthy way so that California can have the modern infrastructure in place that keeps people safe and energized, which takes me to my story of the month on Slide eight. A couple of weeks ago, I visited a site in Vacaville, where my co-workers are burying lines in a high-fire threat area. The project manager and field engineer were on site and could not have been more excited about what they were accomplishing for their home talent. This undergrounding project was originally estimated to cost close to $3.5 million a mile with a completion date in 2024. The team is now estimating a unit cost of approximately $2.9 million a mile and finishing in early December. Using Lean and the principles of waste elimination, my co-workers found opportunities to reduce materials and labor costs by challenging the status quo. They reduce trench depth and width while staying in compliance with county standards and they found additional cost savings during the backfill process. The combination of these solutions brought down the unit cost and they reduced total active construction time, making it safer, faster and reducing the impact on the community. As you can imagine, each project comes with its unique challenges, and this one was no different. What is different now at PG&E is the standard set of tools and the mind-set that my co-workers bring to every job. It’s consistent application of lean and problem solving that drives predictable and in some cases, extraordinary breakthrough results no matter what challenges we face. Sticking with undergrounding, I should note that we currently have more than 2,000 qualified personnel working safely on undergrounding in our service territory every day. Earlier this month, we announced that we had finished 100% of the heavy construction work necessary to complete the 350 miles targeted for this year. We expect to energize an average of 20 additional miles per week through the end of the year, and I could not be prouder of the team for overcoming the significant challenges presented by the weather we experienced earlier this year. Day by day, week by week, we are managing our progress, leveraging visual management and operating reviews, giving me the confidence to affirm that we are right on track with our plan for 2023 and with line of sight running well into 2024. And with that, let me hand you over to Carolyn for our financial highlights.

Thank you, Patti, and good morning, everyone. This morning, I’ll cover three main topics with you. Our 2023 year-to-date results, why we feel confident reaffirming our year-end and longer-term outlook and our simple affordable model. Let’s start with our 2023 report card here on slide nine. As Patti discussed earlier, we are solidly on track with our operational metrics. We also have confidence that we are on track to deliver our 2023 financial commitments. Today, we are reaffirming our 2023 EPS guidance range of $1.19 to $1.23, along with our EPS growth target of at least 10% for 2024 and at least 9% for 2025 and 2026. We are also reaffirming our commitment to no new equity in 2023 or 2024. We may have noticed our Amber dial signaling a potential challenge to reaching our FFO to debt target in 2024. While we remain committed to achieving our mid-teens FFO to debt as quickly as possible, as discussed in our public comments throughout the past several weeks, the PD and APD in our general rate case fall short on cash flow in two notable areas. First, both the PD and APD extend the amortization period for collecting our incremental 2023 revenue increases to 36 months, packing an additional 2 years onto our requested 12-month collection period. This longer amortization period pushes out cash flow and unnecessarily burdens customers in the form of additional interest cost. Second, the APD allows only 25% of the customary inflation index adjustment, which risks lowering the pace of our balance sheet recovery as intervening parties acknowledge that last week’s oral argument, our request and the index supporting it are consistent with commission precedent. Taken together, these cuts will constrain future cash flows. And as we’ve said to the commission, we will be forced to make some difficult choices on what priority work to dial back on and what to complete. We simply are not willing to compromise on safety. Nor can the state afford to see us take a step backwards in terms of the progress we’ve made improving our credit metrics. As Patti mentioned, we are advocating strongly for improvements in the PD. And we trust the CPU understands the importance of a financially healthy utility, just as we understand the importance of keeping bills affordable for customers. The simple affordable model makes both financial health and affordability possible. Turning to Slide 10. As we’ve said, we are on track to meet our 2023 EPS guidance of $1.19 to $1.23. On a year-to-date basis, our result is $0.76 per share, including $0.24 in the third quarter. During the first nine months of 2023, we’ve realized $0.03 of favorability from operating and maintenance cost reductions, which we have fully redeployed right back into the business. And we’re on track for at least our annual 2% nonfuel O&M reduction target. The $0.04 of timing is expected to fully reverse by year-end. And includes the typical tax driver, which results in variances between quarterly and annual earnings. This driver is even more pronounced this year as we await the final decision in our GRC. And the $0.04 of other has not changed from last quarter. Once we receive a final GRC decision, we will record the catch-up revenues supporting our customer capital investments for the full year 2023 as tracked in our approved memo accounts. This incremental catch-up revenue is the largest discrete driver of earnings that we project for the fourth quarter. As you may have seen, we have adjusted our accrual for the 2021 Dixie fire this quarter. Our focus continues to be on making it right for the victims, and we are making a non-cash increase to our accrual of $425 million to reflect our claims settlement experience to date. At the same time, we recorded an offsetting receivable from the state Wildfire Fund, reflecting our continued confidence in the protections provided by AB 1054. On Slide 11, our 10-year capital investment plan has not changed. As I mentioned earlier, we continue to advocate for improvements in the final outcome of our GRC. At the same time, we have several layers of financial protection to support our plan, including opportunities to seek cost recovery for the needed safety and reliability investments that our system requires. Our customers demand and which are legislative and regulatory stakeholder support. You can be sure that we’re not taking our foot off the pedal to find and realize opportunities to further improve quality and reduce cost. Reducing costs and delivering more for our customers are core to our simple affordable model shown here on Slide 12. Coupled with load growth and efficient financing, this is how we plan to keep customer bills affordable. In fact, while we expect a step up in average customer bills in 2024 with the GRC implementation, our internal forecast for 2025 and 2026 show a declining bill trajectory. As we progress our lean tools, lower O&M costs and as legacy cost items, including [Indiscernible] recoveries roll off. This permits us to sustain average annual bill increases from 2023 through 2026 at or below assumed inflation in the 2% to 4% range, even with the first year GRC step up. Part of our affordable model is efficient financing. Our sale of a minority stake in our nonnuclear generating assets, Pacific Generation has received robust inbound interest for this attractive and unique portfolio. The regulatory record closed earlier this month and a PD is due early next year. We are targeting a transaction closing date in mid-2024. I’ll end here on Slide 13, looking forward to 2024. On October 13, you saw this file an advice letter with the CPUC seeking to implement the cost of capital adjusted adjustment mechanism effective January 1, 2024, subject to commission disposition. Based on market interest rates, the mechanism has triggered, resulting in a formulaic 70 basis point upward adjustment to our return on equity and a 35 basis point upward adjustment to our cost of long-term debt. We believe the increase is well justified by market conditions. And if improved, we anticipate reinvesting any upside beyond our targeted earnings growth right back into the system for the benefit of our customers. On the same day, we also filed our TO21 rate case application with FERC seeking a 12.87% ROE, inclusive of the 50 basis point CAISO participation adder. A FERC order, except in the filing is expected by mid-December for rates to be effective January 1, 2024. Our filing includes $1.9 billion in forecasted capital additions during 2023 and 2024. As a reminder, a nice feature of our formula rate structure is the annual true-up mechanism, which adjusts rates to reflect actual costs, including customer capital investment, which, as we’ve said, is an area where we see abundant growth opportunities. To summarize, we are mitigating both our physical and financial risk with layers of protection. Although we are concerned that the PDs and our GRC risk setting us back to -- in our quest to restore our credit ratings. We believe we can make our system safer faster and more affordable for our customers. At the same time, we are offering attractive earnings growth to investors. We are looking forward to reinstating our common dividend soon and we look forward to catching up with many of you at EEI next month. With that, I’ll hand it back to Patti.

Thank you, Carolyn. Before we take your questions, I just wanted to take a moment to review our regulatory and legislative time line shown here on Slide 14 and reflect on some of our highlights in 2023, starting with our wildfire self-insurance settlement in January which we see saving customers up to $1.8 billion through this 4-year GRC period. Other milestones include resolving our safety culture OII. Settlements with the CPUC Safety and Enforcement Division for both the

[Operator Instructions] First question is from Shar Pourreza with Guggenheim. Your line is open.

Hey guys good morning.

Good morning, Shar.

Good morning, Patti. Just on the core drivers in the metric away from on track for FFO by 2024. I mean obviously, Carolyn mentioned in the prepared remarks, did I quote like you have to make some pretty difficult decisions, but most of your spending being somewhat crucial for the state. I guess what difficult decisions were you referring to? I guess, how do you manage this headwind under an assumption that the various rate requests are adverse and don’t work into your planning assumptions? And could we see incremental equity as a result of that as you try to right size the metrics? Thanks.

Yes. Thanks, Shar, for the question. These are all things, obviously, on our mind. Look, first of all, the process isn’t finished. We’re in the throes of completing the final decision for our rate case. We know how important it is. We also know the important work that we want to do for customers. And that is at the heart of what we requested in the rate case and the heart of our advocacy. In terms of difficult choices, I think what we look at, we see without the necessary cash flow, it definitely slows down our ability to complete the work, but we also know that we’re committed to improving the health of our balance sheet. I’ll address your equity point, but then I want to make a broader point about the regulatory environment here in California. First, on the equity point, we’re still committed for sure, to our commitment to not issue equity through 2024. We stand by that plan. We know that issuing equity at this valuation is not good for customers. We need to make sure that we have the equity and access to the capital markets that attracts capital to California, so we can make those necessary investments. So we’re standing by our plan there through 2024. But back to the construct and to your question about how do we make these choices. Look, the California regulatory construct is good. It has a lot to love and I’ve learned that as I’ve been here it provides many earnings mechanisms and provide certainty in those earnings mechanisms. Let me give you one example. We had these major storms back at the beginning of the year, like 14 storms in the first quarter. And we were able to recognize the revenue associated with covering the cost of those storms through our CEMA mechanism. But we don’t collect the cash. There’s a delay in that. And so that’s the part that I think people are coming to terms with. Here in California, specifically about PG&E is that given our we’re on a path to become healthy. We’re on a path to recover our balance sheet. We’re committed to FFO to debt in the mid-teens. In order to do that, we have to have timely cash recovery. And that’s the point we’ve been trying to make about these proposed decisions that they allow too much cash flow lag and we don’t have a balance sheet that can afford that. I think a typical investment-grade utility can handle that buffer. And so the regulatory construct works. But given that we are in the situation we are with our credit metrics, we’ve got to improve those credit metrics and this is essential to returning us to the position so that. And this is the part that’s most important, Shar, so that we can do that necessary work on time. We don’t want to have to slow down the deployment of the work. We don’t want to have to make choices for customers about which essential work we do first. We want to be able to do that work in parallel. I have the work team -- I have the team here at PG&E who’s ready to go, who can do that work for customers that can make the system safer, faster, but we need the cash flow. And so I think it’s a new issue here in California. It’s a new issue for our regulators to deal with the fact that our credit ratings are where they are. But we do see a path that if we all work together. And if PG&E proves itself trustworthy as we work to do every day, and I think the progress we’ve made to date is starting to provide that evidence that we can do what we said we’re going to do. That we have earned the right to be trusted to deploy this cash to the best benefit of customers, and that’s really what we’re focused on doing Shar.

Got it, Pat. And then just lastly for me on Slide 7, you pointed out that the APD run you in the bottom half of the rate base guidance. Can you just comment on the cadence of the customer investments that you back that gets you back to the midpoint? What are, I guess, some of the more additive construct? Is it SB 410, is it WMCE? And if like this whole undergrounding issue is reduced I guess, how long would it take you to ramp up to that 10-year plan, especially there seems to be a lot of stakeholders pushing back on the undergrounding costs. Thanks a lot guys.

Yes. Good question, Shar. Thank you. I would say, first of all, these new mechanisms, particularly those that are reflected in the new legislation, SB 410 and last year’s legislation around undergrounding do provide for us to do the work. But again, it all comes back to our access to cash and the cash flow. And so we think that we definitely can catch up on the work and do the work if we have the cash. And so that’s an important role that these PDs play as we move forward. I will also say that on the undergrounding specifically, it’s a relatively small cost in the overall rate case. So in terms of customer cost, as we’ve calculated and have been sharing $3.40 a month is the impact to customers at the peak of the rate case for customers to do the undergrounding. And the customers I talked to are pretty excited about us doing that work. And so we continue to make the case that undergrounding in very specific miles. And I think it seems to some in some cases, it feels like people are trying to do an all or nothing. It’s either we do undergrounding or we do covered conductor. The reality is we have 1,000 miles of covered conductor, there are places on our system where covered conductor is the right choice. What we’re talking about is a very specific highest-risk miles with a very unique geography, particularly suspect for vegetation strike. And that vegetation management expense that we are doing every year customers have to pay for. And I think people don’t understand it actually is less expensive to do the undergrounding. And people understand it costs something $3.40 a month, but it will cost more to continue to do vegetation management and overhead hardening and the maintenance of those overhead lines in these specific areas. So we continue to make the case. Look, Shar, we see a path forward to do all of the necessary work that our customers have been begging us to do. We’re excited about being able to do that work, and we’re sure that we can get to a good constructive outcome with our regulators.

Fantastic guys. I’ll jump back in the queue. Appreciate it.

Thanks, Shar.

The next question is from Steve Fleishman with Wolfe. Your line is open.

Yes, thanks hi, good morning. So the -- you talked about the -- obviously, to get more cash, there’d be more rate increase upfront, but then you talked about the declining bill trajectory and rollover and such that, obviously, you need to do the work and you want to get into that declining build trajectory. Could you just talk about that aspect and some of the things that help in 2025, 2026?

Yes, you bet. Yes, it’s a great question, Steve. And I also think it’s something that’s been hard to understand in all of the public comments and advocacy. Look, there’s some catch-up that needs to be done here. And in California, we have this construct where we need to do necessary work and the utility bears the risk of doing all the wildfire preventive work. And so there are some onetime short-term costs that are embedded in the early years of this rate proceeding. But as the years progress, then those things come out of the bill. So for example, as we do the recovery of the 2023 revenues that obviously needs to be captured then. And our proposal is a 12-month capture in 2024. So if you can imagine a customer would be collecting bills in 2024, that we are paying bills in 2024 that reflect 2024 and 2023s revenue. And then that comes off. And then the bills come down significantly. And so what we’re -- the point we’re trying to make is that there is some catch-up in this, but bills can definitely improve, that’s just math. But what I think is really important and the part that people don’t necessarily yet appreciate about the new PG&E model is our simple affordable model. This is not just a slogan, it’s not just a thing we say, this is something that we do every day. And that is funding capital investment through cost savings, cost reduction we have had dramatic cost improvements already on our undergrounding, on our vegetation management. Our next big hurdle is our system inspections. We’ve got major improvements that we can make there. Then we add in the efficient financing. Look, getting our credit ratings in the right place will save customers money, not spreading out the collection of the 2023 revenues over 3 and 4 years will save customers money. We have the ability to reduce costs in the bills, and that’s what we’re focused on every day. I think that’s a new habit, a new pattern for PG&E to be recognized for. And so I can appreciate that regulators and others have questions and wonder if that’s actually what we’re going to do. All I can say, Steve, I think you know my track record, we can do real cost savings that benefit customers while we’re making these very necessary investments in the infrastructure.

Okay. Great. And then just -- could you just go through the steps here. So the GRCs on the agenda for the meeting next week. Is that mean they likely will rule or could they delay it? And could we still get another alternate? Or are we likely just going to kind of get a final order.

Well we’re hopeful, Steve, that November 2 reflects a final decision. But what’s on our mind is we want to make sure that it’s the right final decision. And so -- if -- I think there’s still two meetings, November 16 and November 30. If in fact, they wanted to take more time to get it right. But we’re hopeful that November 2 represents a final decision.

Okay, great. Thank you.

Thanks, Steve.

The next question is from Nicholas Campanella with Barclays. Your line is open.

Hey thanks for taking the question. I guess just very clear on the FFO to debt disclosures here, but just can you elaborate on just the agency conversations on the path to IG right here right now? And how we should think about if this PD is adopted your path to get there? Thanks.

Yes. Thanks for the question. We have been in continuous conversation with the rating agencies about our rating. And we’ve actually already spoken to them about the GRC and the PDs and the impact on FFO to debt. But we’ve also talked to them about our commitment to achieving mid-teens in 2024 and other ways that we can get there if we need to. But it is challenged, and it’s going to slow -- it will slow our progress on our balance sheet. So the path to get there really is about FFO to debt and getting to at least the 13% to the 14%, and that’s what we’re committed to doing over the course of the next 2 years for sure, and we’re committed to getting to mid-teens by the end of 2024.

That’s helpful. And I think you also said in regards to the wildfire fund, you booked like a $400 million and change receivable. Is this the first time the fund has been tapped? And correct me if I’m wrong there, but just what’s the process around actually receiving that?

So we haven’t actually tapped the wildfire fund. So on the Dixie accrual, we did increase the accrual by $425 million. We have an accrual of $1.6 billion in total at this point in time. But what’s important is that you can’t tap the fund until you actually -- until we have actually paid out $1 billion in settlement. So to date, we have a 730 -- we’ve settled around $730 million, and we’ve paid out $575 million. So we have a ways to go to fully paying out $1 billion. But the statute limitations on Dixie actually runs out in October of 2024. So we are in preparing for that filing as we speak and working with the fund on how to ensure a smooth of a process as possible.

And this is Patti. I’ll just add in. So no, it hasn’t been done before, Nicolas. And so we’re working through what that process will be. And so that’s not perfectly clear, but I do want to remind everyone that the benefits of AB 1054, there’s -- it’s a fundamental change in California that really helps create the certainty required to number one, prevent a liquidity issue in the event of a significant incident. It allows us if, in fact, we had did have to, in a hurry, get access to that fund, we could access it to pay third-party damages. But as Carolyn said, it’s actually -- it takes time to settle and to pay out those settlements, but the enhanced prudency standard that comes with AB 1054 is another enhancement that will be good to see as we move forward here. And so I think there’s a lot to appreciate about AB 1054 and the protections it provides and the certainty it allows for here in California as we do this necessary safety work to make the system safer faster.

Yes. And I’ll just remind you that we also just -- we did record an offsetting receivable for that -- for the state wildfire fund for that accrual?

Yes. Thank you for the clarification and [Indiscernible] thanks.

Thanks, Nicholas.

The next question is from Julien Dumoulin-Smith with Bank of America. Your line is open.

Hey good morning, team. Thank you very much guys. Appreciate the time. Just first off here, on the undergrounding and the timing-related matter here. I mean, obviously, sort of for the purpose of efficiency, you want to keep this going in a more linear fashion and you guys are up and going here. Do you want to talk about sort of funding and ensuring consistency and execution through the near term, barring whatever comes out in some subsequent process here on longer-term undergrounding. Obviously, you’ve carefully negotiated the -- with the various contractors in the medium term here, if you don’t mind.

Yes. Well, first and foremost, let me be clear, we won’t do work that the commission didn’t fund. And so our plan right now is the most efficient plan we agree. We have done negotiations with contractors. We’ve developed a workforce. As I mentioned in the script, I’ve got 2,000 people right now today, doing undergrounding and those people are skilled and qualified -- boy, I don’t want to tell them that they have to step off the job. But the reality is we’ve got 350 miles planned for this year, and we’ve got engineering in the hopper to prepare us for next year’s 450-mile target. And then we’re focused on 550 miles in 2025 and 750 miles in 2026, but all of this is contingent upon regulator approval. So if the CPUC decides we should do less undergrounding or to slow down the path, it will cost more for customers, but obviously, we’ll take their direction, and we’ll then file our 10-year plan and make sure that it does its best job of compelling a more favorable decision to get the scale because that’s the beauty of what we’ve observed already, just like the story of the month that I shared on the call, we are finding savings on every job. And scale is essential to realizing those savings for customers. So that’s really what’s on our mind as we move forward. We will be filing that 10-year plan when the OEIS is prepared to receive it.

Right. Exactly. And maybe the point is, to the extent which that has a process that could take a couple of years here. If you really want to be watching your ability and/or rather the commission’s decision tree on not just 2024 but also 2025 in terms of what’s right in the near term?

Yes, exactly. We certainly don’t want to come to a cold hard stop. Like we want to be able to keep moving and keep the acceleration of the benefits for customers rolling every mile buried as another mile of risk virtually eliminated. And so we’re really focused on these very specific miles and getting these specific miles done as soon as possible to protect the people of California, and we think we can do that at a very affordable price.

Excellent. And Patti, just following up on our prior conversation on SB 410 and enabling timely interconnect. I mean, do you want to talk about how that bolsters the cash flow conversation you had a second ago here on the call vis-a-vis ratings and targets?

Yes. We’re very grateful for the legislature and the great work that they did this year in recognizing that when you do a 4-year forward-looking rate making, you don’t -- you can’t perfectly predict the demand that we’re actually experiencing. And so as demand increases, SB 410 allows for an annual true-up of recoveries for the work that needs to be done to enable electric vehicle transition to electrification in the state. And I’m very proud of my team. We’ve been working hard to improve our own process while we get the necessary funding. What’s important is that we are able to do our work more timely. And so here’s some news from this year we delivered a 17% increase in volume of requests this year. So in 2022, we did 7,900 new business connections. We’re up to 9,200 here in 2023. So that’s a 17% increase. Really proud of the team, things all of our lean operating system being put to work, have deployed things like we are estimating, which is our engineering and work preparation is a critical part, but can be a bottleneck in the process. That team has gone to work reimagining how they do estimating, and they’ve reduced their cycle time from 116 days down to 71 days. I mean that’s a 50% improvement in really a 1-year focused effort. So the ability for us to improve throughput and meet the needs of customers is real. We’re starting to prove to people that we can, again, do what we said we’re going to do and the cash flow that’s enabled by SB 410 is helpful because it’s more timely, but there is still a year’s lag. And so again, we’ve got to get these credit ratings back up into investment grade so that we can attract the debt markets at the lowest cost for customers. And this whole -- the plan hangs together extremely well when we are -- when we have a balance sheet to fund all this really important work that we need to do for customers.

Excellent. Thank you.

Thanks, Julien.

The next question is from Gregg Orrill with UBS. Your line is open.

Yes, thank you good morning. On PacGen [Ph] I know there’s been a lot of support in the process. Could you sort of remind us about what has to happen to close the transaction from here and any sort of risks or concerns you might have around it? Thank you.

Yes, good morning. Thanks for the question. So PacGen is on track. We’re following the process, as we’ve mentioned, that we had kicked off our Phase 1 of the sales process at the end of June and July, and we’re now in what we would call Phase 2. So we’re tracking the marketing and sales process right along with the regulatory process. I think the major milestone on the regulatory really is that the PD is due in January of are within 90 days of the record closing, which occurred on October 5, 2023. So we still expect the closing to occur in the first half of we have seen very robust interest from what we expected in terms of interest in these very unique differentiated assets, largely from infrastructure funds, but we’re pleased with the interest and still expect the time line to be as we’ve discussed in past earnings calls.

And I’ll add. This is Patti. The PacGen the whole purpose of that is for efficient financing for customers. And so this is a good example of how we’re not just counting on others. We’re not just counting on the regulators to fix our balance sheet. There are things self-action that we can take that we are taking that is really intended to help enable customers to get the value that they’re demanding, the value they deserve in this infrastructure that we have the privilege to build for them. And so this is just another example of our simple affordable model, efficient financing as a piece of the puzzle to make sure that we can invest in the infrastructure and save customers money. And so that’s what we’re up to on this transaction.

Okay, good wishes.

Thanks, Gregg.

The next question is from Ryan Levine with Citi. Your line is open.

Good morning. As the company engages the CPUC ahead of the November 2 potential decision, is the company open to accelerating or open to committing to accelerate the undergrounding of the top 5% risk lines. And to the extent that permitting is a limitation, is there a political solution that could help advance both the company and key stakeholders’ interest on this front?

Yes. Our plan is dynamic enough that in 2025 and 2026, we can adjust the miles and make sure that they’re mutually agreeable, if you will. I will say that as we designed the sequencing of the miles, we picked -- well -- and let me just start with every mile in the 10,000 miles is high risk. So if you do mile 8,000 or mile 2000, you’re still tackling a high-risk mile. So we’ll start with that. But as we sequence those 10,000 miles, we did include the adjacent miles that also will be underground for an efficiency. That’s how we get to the lower unit cost. But if there’s certain miles that the regulators instruct us to do sooner as we work with OEIS on our risk reduction plan will definitely be prioritized. We definitely are focused on making sure that the system is safe today because of our mechanisms like EPSS and public safety power shutoffs but those cause outages. The public safety power shutoffs and the EPSS mechanisms are working. We showed that with our ignition reduction. And so we know customers are safe today, but we want them to be resilient. We don’t want customers to have to choose between having safety or having power. We want them to have both and undergrounding as the lowest cost path to that future.

I appreciate the response. And then one other unrelated. In terms of the details on SB 410 impact, what is the nature of the 300-plus projects highlighted in the prepared remarks, any color you could share there?

Yes. So we have demands every day on capacity increases, EV charging infrastructure. And so that’s just -- and that demands some of that we can’t -- we don’t know the project request yet because it will come in a very -- it happens all the time. And so that’s the point about SB 410. We can’t perfectly predict what those 300 projects would be. Otherwise, we wouldn’t need the mechanism. Because it comes in as EV penetration increases to meet the state’s direction as EV charging infrastructure gets built out. That will vary year after year. And so that’s the beauty of SB 410, whatever the demand is, we can meet it. And we won’t recover more than we install, we’ll just have good timely true-up of that work that gets demanded by customers. And so that’s more of a calculated 300 than actual specific 300 projects. .

Great. Thanks for taking my question.

Thanks, Ryan.

The next question is from Jeremy Tonet with JPMorgan. Your line is open.

Hi, good morning. Richard Sunderland on for Jeremy. Can you hear me?

We sure can. Good morning.

Great. Thank you. Slide 7, I know we’ve parsed this from a couple of different angles, but I just wanted to circle back to those categories broadly under customer investments. Could you speak a little bit more to, I guess, timing and dollar of those? I don’t know if it’s best if they’ve gone sort of a cash basis or a CapEx basis. But when you might have clarity on some of those should the PD or APD stand as it is today?

Yes. Well, we’ll be working that. First and foremost, we think a revision to the PD will be good and enable us to do more faster, so number one. Number two, though, as we look at the SB 410, that’s going to be driven by customer demand, and that’s good work to be done. Our whimsy proceedings, we’ll continue to file those on a timely basis. Those certainly help with cash flow. It’s a good example of a delayed recovery that doesn’t affect earnings, but it certainly affects our credit metrics and our balance sheet. And so WIMS [Ph] will be important to be resolved in a timely manner. But the 10-year undergrounding plan just provides the pathway to the lowest cost safest infrastructure. And then certainly, FERC transmission, as you saw, we filed our TO filing earlier in October. We’ll continue to leverage the ability to do that at those transmission projects as well as key components of the whole picture. One of the things that is really important to understand is I rattle off all those things, there is so much work to be done here. Work that customers deserve work that customers will greatly value and benefit from work that customers have been asking us to do for some time. And so what’s important to recognize is we always self-regulate the volume of work we do on customers’ ability to afford. That is the simple affordable model. That we can invest in this capital infrastructure as indicated in -- on Slide 7, but we offset it with cost savings for customers every single day. And so those cost savings is what makes it possible to grow rate base like that without putting an undue burden on customers and their ability to pay. So it’s value for customers and cost savings that make up that simple, affordable model, good for customers, good for investors.

Understood. Very helpful. And maybe since you referenced the 21 application, curious if there are any notable request in that beyond ROE and cap structure? Any other potential areas you’re focused on with that?

No, it’s good bread and butter transmission investment, stuff that helps enable the clean energy transition that’s happening here in California and work that improves both reliability and access to that clean energy.

Great. Thanks very much for the time.

Thank you.

That will conclude our question-and-answer session. I’ll turn it back over to Patti Poppe, Chief Executive Officer of PG&E for any closing remarks.

Thank you, Chris. Well, thanks, everyone, for joining us. We definitely enjoy this time together, but we appreciate certainly your patience on this GRC. It has a long-term impact. And it is worth the way to get it right and to make sure that we are aligned with our regulators. We all want the same thing. We want the safest system as fast as possible that customers can afford. And so we’re working together to get to a good outcome and we appreciate your patience. We will hold a special call once we have a final decision to review the details and share more of our insights when we get to a final resolution. We look forward to seeing you at EEI and please be safe out there.