Thank you for standing by and welcome to PG&E Corporation Third Quarter 2021 earnings call. I would now like to turn the conference over to Matt Fallon, Senior Director of Investor Relations. Please go ahead.

Thanks, Jenny. Good morning, everyone, and thank you for participating in PG&E's Third Quarter earnings call. Joining us today are Patti Poppe, our Chief Executive Officer, and Chris Foster, Executive Vice President, and Chief Financial Officer. I want to remind you that today's discussion will include forward-looking statements about our outlook for future financial results. These statements are based on assumptions, forecasts, expectations, and information currently available to management. Some of the important factors that could affect the Company's actual financial results are described in the second page of today's Third Quarter Earnings Call Presentation. The presentation also includes a reconciliation between non-GAAP and GAAP measures. The presentation can be found online along with other information at investor.pgecorp.com. We also encourage you to review our quarterly report on Form 10-Q for the quarter ended September 30th, 2021. Before I hand it over to Patti, I would like to thank all of you who attended Investor Day, either in person or virtually, and we look forward to seeing you again at EEI.

Thanks, Matt. Hello, everybody. Thank you for joining us today. This quarter, we delivered non-GAAP core earnings of $0.24 per share. We're reaffirming our 2021 non-GAAP core earnings per share guidance of $0.95 to $1.05. We no longer expect to issue equity in 2021. We continue to see rate-based growth of 8.5% and longer-term earnings per share growth of 10%. Chris will provide more details on the financials in just a bit. As you saw at Investor Day, our experienced team is driven and focused on delivering clean energy safely every day. We have a very sophisticated and continually improving PS algorithm year-over-year. In fact, when we backcast our current models to the previous utility cost fires between 2012 and 2020, we would have prevented 96% of the structural damage had the current model been in place. This year, we also implemented enhanced power lines safety settings to address wildfire risks we face from extreme drought conditions. In fact, since the end of July through mid-October, we saw a 46% decrease in CPUC reportable ignitions in high-fire threat districts. There was an 80% reduction in ignitions on enabled circuits. These enhanced safety settings make our system and our customers safer. We're delivering on the 2021 Wildfire Mitigation Plan with our lean operating system and deploying it across the entire company to deliver predictable outcomes for customers and investors. In addition to quarterly operational, financial, and regulatory updates, I'd like to spend some time on the work done and the changes made since 2019 that have made our system safer and more resilient. Let's start on Slide 4 with how we've improved our QPS and WPS programs since 2019. In 2019, we had seven events that impacted over 2 million customers. Since then, we've installed approximately 1,300 weather stations, 500 high-definition cameras, and over 1,100 analyzing devices to better pinpoint exactly where we need to initiate PSPS. Our 2021 PSPS algorithms are informed by more granular weather forecasting. We are using Technosylva software to incorporate machine learning into our fire spread modeling, so we can better predict where the risk is on our system in real time. Our continuous improvement approach applies to addressing safety risks while minimizing disruption to our customers. As you can see on slide 5, our model shows that by backcasting our new 2021 PSPS algorithm onto 2012 to 2020, we would have prevented 96% of the structural damage from fires caused by overhead electrical equipment in our service area. As you know, this year, we experienced extreme drought conditions in our service area. Due to these conditions, we saw fires spread on non-red flag warning days. We assessed these risks and identified where we needed to focus. Guided by former CAL fire and local fire authority personnel who now work for PG&E, we implemented additional Wildfire Mitigation in our high-fire threat areas. You can see the results of our safety focus on slide six. We've compared the data since we implemented our enhanced power line safety settings against the most recent three-year averages. What we've seen is a 46% reduction in CPUC reportable emissions in our high-fire threat districts from the end of July to mid-October. On the specific circuits where we first implemented the enhanced power line safety settings, we've seen an 80% decrease in ignitions over the same time period. We're working hard to reduce the customer impact from these new necessary protocols. We've optimized our protective device settings on all circuits that have enhanced power line safety settings, and we've adjusted our circuit restoration procedures. These enhancements are making outages smaller and faster to restore while still removing the ignition risk. We are communicating transparently our commitment to preventing fires of consequence in communities where enhanced power line safety settings are in place. Let me make it real with one story. On Monday, October 11th, we initiated a PSPS event that affected about 20,000 people. The winds came in as forecasted, and in 33 instances outside of the PSPS zones, in the highest wind areas, our lines automatically de-energized due to the unpredictable disturbances, and potential risks were mitigated. We know our protocols are working. We will continue to work around the clock to make these solutions less disruptive to customers while knowing that we are keeping them safe. Our experience since implementing these settings in late July will serve as an important guide for our 2022 planning. As we continue to keep people safe each day, I want to talk a bit about the risk reduction work we've completed since 2019. Let's start on slide 7, with our enhanced inspections. As you can see, we're on track to complete our enhanced inspections on 0.5 million assets in 2021 in our high-fire threat areas. These inspections are scheduled to be conducted every year on all assets in Tier 3 and every three years for all assets in Tier 2. At the bottom of this slide, you'll see a couple of points on our routine inspection program, which gets a lot of attention internally but isn't well known outside of PG&E. As you can see in the green box, we conduct vegetation management inspections across our entire system annually, and in high-fire threat areas, we patrol those conductors twice a year. In 2021, we plan to complete 1,800 miles of enhanced vegetation management work, which, combined with what we completed in 2019 and 2020, adds up to over 6,000 miles by the end of this year. While we're focused on keeping people safe with inspections and vegetation management, we're also focused on the long-term hardening of our system. In the last three months, we've made great progress against our multi-year 10,000-mile undergrounding program. Our engineering team is scoping out the work, as you'll begin to see in our 2022 Wildfire Mitigation Plan. Our goal is to engage the entire community around the imperative of undergrounding, and we are succeeding. We are engaging stakeholders through our undergrounding advisory group with representatives from environmental groups, labor, telecom, and consumer advocacy groups, among others. We're gathering ideas on innovations in engineering, equipment, and construction from the world's best through our RFI process. We're continuing to work on system hardening as you can see here, and we'll provide an update on how we're thinking about that work as we further develop our undergrounding program. As a sneak peek, I'll share one project we completed this year. In September, we completed undergrounding power lines in Santa Rosa, which resulted in 11,000 customers who will no longer be impacted by PSPS. This is one of many projects. This is the right solution for our customers in that area, and that's why we did it. Simple solutions based on customer needs. As I mentioned, more to come on our undergrounding plans as we move into early 2022. At PG&E, effective implementation of our Wildfire Mitigation Plan is enabled by our lean operating system, which we're deploying across the entire company. Every day, we have over 1,200 daily operating reviews beginning with our crews closest to the work first thing in the morning and cascading to our executive operating review. These brief 15-minute huddles provide daily visibility on the metrics that matter most, help us identify gaps, and quickly develop plans to support our teams closest to our customers, giving us control and predictability in our operations. As you know, this summer, we were challenged by the Dixie Fire and the impact of fire hit all of our customers. I'll repeat what we said since Investor Day. Our actions around Dixie were those of a reasonable operator, and we're confident in the framework created by AB 1054. AB 1054 resulted in a Wildfire fund to provide liquidity for results claims, a maximum liability cap for reimbursement by investor-owned utilities, and enhanced prudency standards when determining that reimbursement amount. We're reflecting that view in our financial statements, which show a gross charge of $1.15 billion. We've booked an offsetting $1.15 billion receivable that reflects our confidence in recovering costs. As I highlighted, PG&E is working hard every day to deliver clean energy safely. We're building on the mitigation programs we started in 2019. We're staying nimble to respond to current conditions, and we are improving our performance enterprise-wide. For example, our team just last week responded to an atmospheric river weather event that included among the highest rainfall totals observed in a 48-hour time frame, ranging from 16 inches at Mt. Tam to 5 inches in Downtown Sacramento. The strongest wind gust recorded was 92 miles per hour in Alameda County, with at least a dozen other locations experiencing gusts greater than 69 miles per hour. Even in the face of returning service to 632,000 of the 851,000 customers impacted within 12 hours, I am very proud of the safe and rapid response of our team. Now I'll hand it over to Chris to cover financial and regulatory items.

Thank you, Patti. As Patti referenced earlier, our financial plan remains on track and is supported by a regulatory construct. I'll cover the highlights first, then go into more detail. Today we're announcing that we no longer see a need for equity in 2021, and we anticipate issuing our 2022 guidance on our Q4 earnings call. Additionally, we're seeing progress on recoveries related to prior wildfire risk reduction investments to help the balance sheet. Let's start with the share count used for Q3 2021, and year-to-date GAAP and non-GAAP core earnings per share were at a GAAP loss position for both Q3 2021, as well as year-to-date 2021, due to our grantor trust election this quarter. As a result, we're required to use basic shares outstanding to calculate both GAAP EPS and non-GAAP core EPS for Q3 and year-to-date. Our full-year guidance, as always, assumed a GAAP positive year, and our full-year non-GAAP core EPS of $0.95 to $1.05 per share reflects our fully diluted share count. So there's no impact there. I'll start with our Q3 results. We continue to be on track for the 2021 non-GAAP operating EPS of $0.95 to $1.05. This is calculated using our fully diluted share count I just mentioned, consistent with our assumption when we initiated guidance. Slide 9 shows the results for the third quarter. Non-GAAP core earnings per share for the quarter came in at $0.24. We recorded a GAAP loss of $0.55, including non-core items. This quarter we recorded a $1.3 billion charge we've previously guided to as a result of our grantor trust election. As you recall, this charge is expected to reverse over time, as the fund within the trust sells shares. Moving to slide 10, as Patti mentioned, we took a $1.15 billion charge this quarter for the Dixie Fire. We also recorded $1.15 billion of offsetting receivables, which reflect our confidence to recover costs based on the facts and information available to us today. As a reminder, we recognize the receivable if we believe recovery is probable under the applicable accounting standard. Due to the fact that currently available facts do not make probable the recovery of amounts exceeding insurance for the 2019 Kincaid and 2020 Dolan fires, we haven't recorded offsetting receivables for either of those fires. On Slide 11, we show the quarter-over-quarter comparison for non-GAAP core earnings of $0.24 per share for Q3 2021 versus $0.22 per share for Q3 2020. EPS increased due to $0.03 of growth in re-based earnings, $0.02 from using basic share count as a result of the GAAP loss I mentioned earlier, and a penny from lower wildfire mitigation costs, partially offset by a penny decrease due to timing of taxes that will net to zero over the year. We expect a stronger fourth quarter due to the timing of regulatory revenue and efficient work execution. Moving to Slide 12, we are reaffirming our non-GAAP core EPS of $0.95 to $1.05. On the debt side, we expect to complete an initial $860 million 10-54 securitization transaction this month. Our separate rate-neutral securitization has also been approved by the CPUC, and once we resolve the final legal steps, we anticipate we'll start issuing bonds early next year. Now some updates on regulatory matters, I’ll specifically highlight important filings reflecting both our focus on timely cost recovery for historical spend and our focus on supporting California's clean energy future. Turning to slide 13. At the end of the third quarter, we've requested cost recovery for approximately 80% of the unrecovered wildfire-related costs on our balance sheet. And we already have final decisions, settlement agreements, or interim rates for roughly 60%. In September, we filed a settlement agreement for our 2020 Wildfire Mitigation and Catastrophic Event application. Our request is $1.28 billion comprised of prior wildfire expense, including costs that were incurred in 2018. Given some of these costs predated the Wildfire Mitigation Plan construct, we feel the settlement of $1.04 billion is a reasonable outcome. Most recently, on this front, in September, we filed for recovery of $1.4 billion of additional Wildfire Mitigation and Catastrophic Event costs. Most of the costs were incurred last year, and under our proposal, most of the revenue would be recovered in 2023 and 2024. You should expect to see similar filings in coming years as we seek timely recovery of any incremental spend in these areas. Next, I will cover a brief update on our cost of capital application. In late August, we filed a cost of capital application for a rate increase in the cost of capital for California utilities, as seen from higher interest costs and equity issuance costs. At this stage, we will follow the recent direction from the administrative law judge and file materials that would have been included in the cost of capital adjustment mechanism advice letter by next Monday. The filing will include calculations of the ROE, half the debt, and the resulting overall return on rate base from the operation of the adjustment mechanism. The ALJ's order admitted the relevant information into the cost of capital proceeding, rather than requesting us to file an advice letter. Our focus on the triple bottom line of people, the planet, and prosperity is also not being overlooked in the adoption of under-staffed communities, and of course, supporting California's greenhouse gas reduction goals. We requested a total revenue requirement of roughly $225 million from 2023 through 2030 to provide the infrastructure to support 16,000 new charging ports, which is just scratching the surface to meet the demands of our customers who today are driving nearly 20% of the electric vehicles in the country. We are proud to serve the largest base of customers owning and purchasing EVs in the U.S. — we need to reduce wildfire risk in the near-term while running the business effectively for the long-term. And we’ve eliminated our 2021 equity needs. We'll continue to make the right investments to deliver clean energy safely to our customers. And with that, I’ll hand it back to Patti.

Thanks, Chris. Every day we are more and more excited about the future we're creating here at PG&E. We can see the difference that's being made and the value to be unlocked. We continue to reduce wildfire risk and we're encouraged by the enhanced safety settings that are necessary and effective in reducing ignitions and the resulting damage given our current drought conditions. We're focusing our work to make our system safer every day. We're adapting based on what we learn so we can best serve our customers and you, our investors. We'll deliver on the financials and we will continue to implement the necessary processes to run a high-performing utility. Jenny, please open the line for Q&A.

Your first question is from Jonathan Arnold with Article of Research.

Morning guys. Thank you for the update.

Good morning, Jonathan.

A couple of questions. Chris, picking up on your comment on cost of capital, the fact that the ALJ didn't require the resolution of the applications, is it a little early to tell and we need to wait for the scoping memo or some other directive on that?

Sure. Good morning, Jonathan. Again, this is a reminder for everyone that the trigger mechanism itself would have implied a 60 basis point reduction, which for us is roughly $0.6 of EPS. In terms of the current state of affairs, we'll be filing this next set of information next Monday, but it is true, Jonathan, that our position is that the rates are not adjusted January 1st, 2022 by the ALJ's ruling, and so that's the scoping memo, but we do think that was a good development in terms of how the judge is treating that next step.

Okay. Great. Thank you. And then just I guess sort of stepping back a little bit and considering the taking equity out of the picture this year and then the securitization you're about to do, at what point in your forward outlook does the utility arrive at a point where it can stop paying a dividend to the parent and then we can start to think about some strategy leveraging?

Absolutely. We're looking forward to that, Jonathan. Again, our commitment is really two-fold, right? First, the delay on that period in which we would have non-GAAP core earnings exceeding a cumulative $6.2 billion dividend and certainly we'll be partnering — Patti and myself partnering with our board to the reinstatement level and growth rate at that stage.

Matt, that restriction is on the common dividend to the parent company, but does the utility stock dividend to the parent before that or is it also?

At this stage, you may have seen that we have disclosed this quarter actually in intercompany loan. So, I think at this point, we've got the path to make sure that we're really stable by mid-year 2023.

Your next question is from Steve Fleishman with Wolfe Research.

Hi. Good morning. Can you hear me?

Morning, Steve. Yes, we can hear you, Steve. Good morning.

Thanks. Curious on the last week we got the proposals from the Democrats in their infrastructure bill, however we want to call it. One of the proposals is this minimum effective tax rate. I know it's early on, I know it's not passed, but is there any risk that that could impact the ability to get all your NOL and also the securitization tied to the NOL?

Sure, Steve. Good morning. Thanks for the question. I think at its highest level it is definitely a little bit early in terms of our initial read of this, just given a draft was provided, I believe last Thursday, there’s really a couple of things going on. First, the tax NOLs are derived separately and are not impacted by the book minimum tax, and the proposal really is focused on book and wealth. And then second, as you can imagine, going forward very traditionally, these costs are considered costs that are part of cost of service and are passed through to customers. So it’s a bit early to know exactly how this will play out. Certainly, the draft again in D.C. could change again, but at this stage, I don’t see an immediate impact coming through from the minimum tax.

Okay. Great. And then question just on the 0 equity this year; it does also look like the contribution — the billion-dollar contribution for securitization was moved to next year. Does that mean the equity could have been moved to next year then or not clear yet?

Not necessarily, Steve. We've consistently articulated that our focus has been on resolving really prior legacy legal issues that have driven some of the equity needs. As we disclosed today, we made some progress in particular on the Zalk fire. What I would say is it is true and we've been signaled pretty clearly here that any additional impact there as it relates specifically to the customer credit trusts would be something that would move into 2020, meaning that first billion payment would only occur after we have completed the securitization itself. So don't see a risk there.

Okay. That’s great. And then just lastly, on the Dixie Fire cost, I know that was obviously a large fire in terms of the acreage, but the impact in terms of structures seemed to be relatively small, and so I'm a little surprised at the size of costs relative to the structures. Could you just maybe give us a better sense of what might explain that?

Sure. Traditionally, what we'll do, Steve, every quarter is we'll consistently update this at this stage. When you look at the totality of structures impacted, what's going on there is you have a mix of a few things: First, it's the roughly 1,400 structures that were damaged or destroyed. Second, there's often a significant element of commercial area-specific affinity. Third, there are some areas where we have to contemplate the potential for private timber operations, which would all pile on top of each other to the point where we reach in terms of those private claims recoveries in the charge we disclosed today of $1.15 billion.

Okay. In your ability, the AB 10-54 is what allows you to be able to offset the write-offs, which shows, I guess, being prudent.

And Steve, just to add, acting as a reasonable operator, we look at the fact pattern. We've disclosed much of our information publicly through these questions. The fact pattern is very much aligned with a reasonable operator, and with the new prudent standard under AB 1054, it gives us a solid foundation.

Great, thank you so much for all those answers.

Yeah.

Cheers, Steve. Thanks for those questions. And again, what we did in terms of the material this morning for everyone is if you go to slide 10, we give a gentle recovery mechanism there. Certainly, AB 1054 and its key protections are there, but there are a few other points we discussed this morning. Thanks for that question, Steve.

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

Good morning, Julien.

Good morning. So maybe to follow up on Steve's question there briefly, can you talk a little bit more of the process just in terms of seeing that affirmed through the system effectively truing it up with the $600 million plus of suppression costs? When do we get that affirmation that the process under the AB 1054 Wildfire Fund 'works,' if you will? And I know it is early here, but how do you practically see it from here given now that you've established receivable?

Sure thing. First, we have to work our way through the claims themselves. It's very early in terms of any kind of claims interface we're having. Traditionally, a time period passes in the first couple of years before the initial statute limitations stage. Once we've resolved the claims, we would then bring things forward to the Wildfire Fund Administrator — really to seek potential recovery. Any guidance, Julien, this could be a few years before we're having that explicit interaction. Things related to fire suppression costs and additional acreage impacted in national and state forest land are areas we provided disclosures about today, and we will continue to take a look at. Frankly, those are the things that will fluctuate, and this will be the amount over $1 billion, roughly a 100 excess items.

Right. Indeed. Excellent. And then if I can get to a slightly different subject here, if you don't mind, on the resource adequacy front, we made it through the summer relatively unscathed, I’m curious to see where the state stands after the summer.

Yeah, great question. It's definitely top of mind. We did see some delays, particularly with battery storage. However, we expect to have over 900 megawatts added to the system by the end of this year. That's valuable for next year. In total, our plan is to have 4,000 megawatts by the end of 2023. We're working hard to address the delays that continue to plague the supply chain. I would also say that I think the state of California is actually doing a good job looking statewide at who's responsible for procuring what. We've developed a strong working relationship with CAISO. CAISO has had some new leadership, and we're working together to ensure that we have the kind of transparency and visibility into what is required by when. So, lots of positive momentum exists in working together as a state to make sure we have adequate resources. It gets very important, and we see the potential of distributed resources and clean energy resources in this unique time — this unique moment in time is a generational opportunity to clean the energy resources as we transition and provide more resource adequacy for the state. So I would say very positive signals moving forward.

If I can just quickly —

Hi, Julien, it's Chris. There's not much more detail we can provide there. They do relate broadly to the Dixie Fire. What I would offer as well is that you can imagine we have an enormous amount of information in the public domain at this stage through requests that have come through from Judge Alsup and the federal monitor, so quite a bit of information is already out. We've shared certainly what we've seen at this stage, and at this point, we'd certainly be compliant with any request from the U.S. Attorney.

At the end of the day, we continue to say that the fact pattern reinforces, that we are a reasonable operator and will continue to cooperate.

Thank you for the responses, guys. Best of luck.

Thanks, Julien.

The next question is from Michael Lapides with Goldman Sachs.

Hey, guys. Thank you for taking my question. Just a high-level one: commodity prices have moved a lot, and everybody can look every day of the week. They have come down in the last couple of days a little bit. How are you thinking about the bill? Because you've got a pretty sizable General Rate Case request out there. You've got various cost recoveries related to wildfire spins that are starting to flow to the bill, maybe not on the income statement, but on the cash-flow statement and online customer sales. And then you’ve got the move in gas and purchase power costs, which have been pretty material lately. How do you think about things that can help offset that to mitigate significant bill creep for your customer base?

Michael, great question. This is obviously top of mind; affordability is always very important to us. There are lots of things that we can do at PG&E to protect customers from bill increases. But just a couple of facts for you: our average monthly gas bill is around $50, so a 10% increase in gas prices would increase the bill about 2%. The commodity portion of the bill is about 25% of the bill. The impact is muted, but more importantly, I would say that because we have pipeline access to many gas production basins, we’re able to get the lowest cost gas as it’s available and use our gas storage to protect customers from these unusual upticks in price. That’s an important thing. And I would also say that as gas fuels electric prices, a 50% increase in electric power prices would have less than a 10% increase on our customers' overall bill. Again, this is because we have limited exposure to natural gas for our customers' electric usage. So overall, I would say among many jurisdictions, our customers are well-positioned given the commodity prices. More importantly, I would suggest that we also have our lean operating system in place to protect customers' bills and make great investments in permanent long-term, higher-value capital replacements that serve customers very well and better than deliver for investors. So that’s definitely our game plan and path forward.

Can you believe since material Millennium cost decreased potential in the Company in the next couple of years or do you think it's more beyond that?

Well, I think we're seeing cost improvements today. By the way, with our daily operating review cadence, we're experiencing great visibility, and I suggest those cost savings will materialize, and they are materializing now, and they won't materialize for years. And I will share with you that during every moment I spend there observing our operations, I see great opportunities for waste elimination and cost savings for our customers.

Got it. Thank you, Patti. Much appreciated.

You're welcome, Michael.

Your next question is from Stephen Byrd with Morgan Stanley.

Hey, good morning. Thanks for taking my questions.

Good morning, Stephen.

Morning. I wanted to step back on federal draft legislation again, building on Steve's question. Just thinking about other provisions that I notice, certainly think about quite a bit of capital climate change impacts. What that might be able to do from both PG&E's perspective in reducing fires could be significant. Secondly, just very broadly, what other impacts from federal legislation are you thinking about?

Stephen, we have been actively engaged early on in the discussions regarding resilience and climate adaptation components of much of the infrastructure package. We want to ensure that support for our customers includes vegetation management, which is a high expense item for us, as well as other grid hardening solutions, microgrids, or even undergrounding. We see those elements in the package today. Your guess is as good as mine regarding what they will actually get passed, but they continue to be in the revisions we see coming forward, so we think that’s a positive sign. We are also very focused on the Federal Forest Service, which has a very important role to play here in California. We’re working in partnership with them on fire prevention and fire mitigation efforts and making sure they have appropriate staffing so that in the event of fires, they can adequately respond. We’re supportive of additional funding for the U.S. Forest Service. Overall, we want to ensure that the infrastructure package reflects the advancements we've made early in clean energy.

That's really helpful. Patti, maybe just building on the point about fire risk cost mitigation, I guess I'm thinking a lot about that magical 8-to-1 ratio of CapEx to O&M. To the extent that O&M costs can be deferred by federal support, could that potentially allow you to accelerate the undergrounding effort in a way that does not harm customer bills because of that total support or is it unclear at this point?

I would say there are lots of reasons why our customers will not be harmed economically by our program. First and foremost, even without federal assistance, your point about the trade-off between OpEx and capital is a key enabler to funding that undergrounding program. We know that the ongoing enhanced vegetation management has a large expense for customers. We spend $1.4 billion a year on vegetation management, being able to trade off some of that for our capital investments in hardening the system, including undergrounding for sure but also microgrids and other hardening solutions. Depending on the circumstances, that trade-off is very favorable for customers, and we think there’s a strong potential to demonstrate some of that in our long-term financial plans and the Wildfire Mitigation Plan you will see early in 2022. We don’t believe there’s an economic trade-off for customer safety; we think we can provide both affordable energy and safe, resilient energy.

Understood. But I was also thinking as well that that could get accelerated even further if you could get federal support that could lower your cost structure. I guess we'll stay tuned to see how specifics shake up for that.

Yeah. No, your intuition is right on that, Stephen. Certainly, any support from this package will be good for customers. We believe we have ample capital to deploy, and if we can defray some of the costs through federal support, we are all for it. There's definitely lots to be done out here in California.

Very good. Thank you so much.

Thanks, Stephen.

The next question is from Shar Pourreza with Guggenheim Partners.

Good morning, guys.

Morning, Shar.

Morning, Shar.

Just real quick on the equity. Obviously, you guys removed the need for this year, but I'd love to get a little bit of a sense of the moving pieces as you're thinking about financing, which seems to be a relatively ambitious CapEx plan. As you're thinking about undergrounding, distributed generation microgrids, would any of those programs push you to issue equity? I guess the broader question is, what would push you from 0 or do you think, Patti, with the amount of leverage that you have at your disposal, like on the O&M side that you can leverage that opportunity versus having to mitigate — versus having to actually raise future equity?

Hey, Shar, it's Chris. I think there are a couple of factors. First, we'll be growing into our undergrounding plan gradually. That's the way I would think about it. As we start to reduce operating expenses and work into that undergrounding plan, it will occur over time. We'll start to disclose more details there as part of our 2022 Wildfire Mitigation Plan in February. We haven't guided toward 2022 equity needs at this stage specifically, but we would intend to do so again at Q4 and provide more color at that stage. I wouldn’t necessarily just think that undergrounding or, for that matter, distributed generation will drive an immediate equity need; rather it’s something we’ll be growing into over time.

Just on undergrounding. I'm curious, right? And I know you kind of mentioned it, but I'd love to get a little bit more of an early indication on sort of the cost and scaling up that 10,000-mile program, right? I mean, obviously the slides reiterate the plan through 2026 with undergrounding remaining, quote-unquote, a potential opportunities bucket. Are there any changes to the scope or timing that you're contemplating for such an undertaking from your prior messaging as the CPUC is starting to more actively inquire into your plans? So net-net, I guess, can you do more faster and cheaper?

I would say we are very bullish on that, Shar. We have started to have — we've issued a global RFI for construction and engineering firms and received about 25 responses. We’re doing face-to-face discussions with seven of the firms, and they're all very affirming. It’s exciting, and we can’t wait to share more details. I can tell you that we feel more convicted than ever that this is an important part of the solution. We do think there are substantial opportunities here—just last week, I heard about a job where we’re undergrounding as we speak. We’re seeing tremendous opportunities to reduce costs as we are at scale. In fact, that project was in about the $2.5 million to $2.7 million per mile range, and that's for the current active projects which I would not describe at scale. We will be at scale and when we are, the costs are inherently lower. We are very, very bullish and all of the feedback is very positive. We’re respectful of the CPUC's role to affirm that, and we are confident moving forward.

That's helpful metric; investors would like to see that 10,000-mile target tripled. Thank you for that. And then just the last thing, I apologize I had to hop on and off the call, but can you comment on the recent wildfire safety division resolution ratifying actions from the 2021 WMT update? Especially as the resolution would require the 2022 WMP update to be included in the GRC proceeding, including an explanation of the undergrounding plans? Does it complicate the proceeding or is it in line with your GRC strategy? Thank you.

So the good news is the Wildfire Mitigation Plan was approved by OEIS. The CPUC ratified our plan on April 21st, 2021, and then we will shortly file for our safety certificate. We have a required safety meeting on Wednesday, November 10th with the CPUC and OEIS. We look forward to that opportunity to continue discussing our plans. Shortly thereafter, we will file our 2022 Wildfire Safety Certificate for OEIS. Currently, the Wildfire Safety Certificate we have remains in place until the following proceeding occurs. So we feel very positive; the process is happening as discussed. We think it’s a great opportunity to talk more about our undergrounding plans in our 2022 Wildfire Mitigation Plan, and we will file that in February of next year. So no red flags as far as we’re concerned, we feel good about how it's progressing.

Fantastic. Thank you guys. See you in a few days; appreciate it.

Thanks, Shar.

If you have a question, please press star. Your next question comes from an indiscernible source.

Good morning.

Morning, Jeremy.

Morning. I think regarding recent years and just wondering if this might be a faster recovery given the weather conditions, and how much might be evidence of any mitigation that investments you've been doing so far are really starting to turn the corner?

Well, Jeremy, I appreciate you asking the question because it's a good opportunity for us to reiterate that we believe that our safety measures that we've put in place, the investments we've made, the vegetation management, inspections, and the enhanced power lines safety settings combined with PSPS, have made our system safer and our customers are safer, and therefore our investors are as well. Certainly, we were not disappointed to have a little early rain, and rain is forecasted today and later this week, and that all makes us feel good. But as we look at our ignition rate, that is the most compelling statistic in my opinion. I encourage everyone to look closely at it. In the areas where we implemented our EPS, we've had an 80% reduction in ignitions, and I attribute that to that measure. I will also say that given the historic extreme drought we experienced this year, we have fared extraordinarily well in managing the vegetation and performing those inspections.

Got it. That makes sense. And maybe just kind of picking up on your point there, given the success of these enhanced safety settings, what percentage of a high-risk circuit can you expand these to and how long might that take?

Again, we can be very targeted about this. We know where and how to address risk. This year, we did around 50%. Next year, we could do a hundred percent, but it’s not like an on-off switch. We can be very, very targeted, and we've done some work to really optimize the device settings to shrink the impact. The time to restore now is much closer to what the time to restore was before we put in the settings because we’ve shrunk the impact of each of the disturbances. Our patrols have improved significantly, and our team's response this year has been extraordinary, particularly given the conditions. Long-term, we know the ultimate solution is a hardened system that is designed and built to be resilient to wildfires, and that's why our undergrounding and all of our other mitigations are a very important path forward.

Got it. That’s helpful. And just one last one if I could here, understanding that anything other that's top priorities into Wildfire Mitigation Plan filing?

Yeah, I think it's really continuing to streamline our vegetation management and hardening plan. I do think you'll see more remote grid applications. There's a lot of circumstances where we have a long radio running through a forest that we could just eliminate and don't even underground it, just equip those people at the end of that line with distributed energy resources that are both clean and resilient to wildfires at a lower cost. We do think there are a variety of solutions that you'll see more of in our Wildfire Mitigation Plan for 2022 and beyond.

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