PG&E Corporation (NYSE:PCG) Q3 2023 Earnings Call Transcript

PG&E Corporation (NYSE:PCG) Q3 2023 Earnings Call Transcript October 26, 2023

PG&E Corporation misses on earnings expectations. Reported EPS is $0.24 EPS, expectations were $0.33.

Operator: 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.

Jonathan Arnold: 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.

Aerial view of an oil and natural gas drilling operation on a leasehold position.

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.

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.

Carolyn Burke: 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.

Patti Poppe: 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 Zogg and the Dixie fires and over $1 billion of interim rate relief approved in our 2022 Wenzy [Ph] proceeding. We have plenty to look forward to as well. Key catalysts we can point to include resolving our GRC and achieving base revenue visibility through 2026, approval of our 2023 WMP and safety certificate, resolution of our GRC Phase 2 proposal to implement SB 410.

Our 10-year undergrounding plan filing under SB 884, disposition of our cost of capital adjustment advice letter. The proposed decision on Pacific Generation and advancing our DOE loan application. That’s a lot of value to come for customers as well as investors. In addition to regulatory catalysts, we look forward to further progress towards normalizing our financial profile. With the Fire Victim trust completing their sales, restoring our credit ratings to investment grade to unlock significant financing cost savings for customers and reinstating our common dividend. We believe these catalysts favorably differentiate the PG&E investment story anchored in our simple affordable model. Our strategy remains focused and is based on the foundational belief that a financially healthy and well-run PG&E can and will play a leading role in enabling the clean, affordable and resilient energy future to which the state of California and our customers aspire.

We trust that you feel the momentum that we do. And with that, operator, please open the lines for questions.

See also 12 Biggest Dividend Cuts and Suspensions of 2023 and 12 Best Dividend Stocks For Passive Income.

Q&A Session

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

Shar Pourreza: Hey guys good morning.

Patti Poppe: Good morning, Shar.

Shar Pourreza: 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.

Patti Poppe: 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.

Shar Pourreza: 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.

Patti Poppe: 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.

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

Patti Poppe: Thanks, Shar.

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

Steven Fleishman: 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?