CenterPoint Energy, Inc. (NYSE:CNP) Q2 2024 Earnings Call Transcript

CenterPoint Energy, Inc. (NYSE:CNP) Q2 2024 Earnings Call Transcript July 30, 2024

CenterPoint Energy, Inc. beats earnings expectations. Reported EPS is $0.3551, expectations were $0.33.

Operator: Good morning and welcome to CenterPoint Energy Second Quarter 2024 Earnings Conference Call with senior management. During the company’s prepared remarks, all participants will be in a listen-only mode. There will be a question-and-answer session after management’s remarks. [Operator Instructions]. I will now turn the call over to Jackie Richert, Senior Vice President of Corporate Planning Investor Relations and Treasurer. Ms. Rickert?

Jackie Richert : Good morning and welcome to CenterPoint Energy’s second quarter 2024 earnings conference call. Jason Wells, our CEO, and Chris Foster, our CFO, will discuss the company’s second quarter results. Management will discuss certain topics that will contain projections and other forward-looking information and statements that are based on management’s beliefs, assumptions, and information currently available to management. These forward-looking statements are subject to risks and uncertainties. Actual results could differ materially based upon various factors as noted in our Form 10-Q, other SEC filings, and our earnings materials. We undertake no obligation to revise or update publicly any forward-looking statements.

We will be discussing certain non-GAAP measures on today’s call. When providing guidance, we use the non-GAAP EPS measure of diluted adjusted earnings per share on a consolidated basis, referred to as non-GAAP EPS. For information on our guidance methodology and reconciliation of the non-GAAP measures discussed on this call, please refer to today’s news release and presentation on our website. We use our website to announce material information. This call is being recorded. Information on how to access the replay can be found on our website. Now, I’d like to turn the call over to Jason.

Jason Wells : Thank you, Jackie, and good morning, everyone. Before spending most of my time discussing the impacts of and our response to Hurricane Beryl, I will very briefly touch on our results for the second quarter. I’ll then turn it over to Chris for a regulatory update and a more detailed recap of our financial results. For the second quarter, we reported GAAP and non-GAAP EPS of $0.36 per share. In addition, we are reaffirming our full year 2024 non-GAAP EPS guidance range of $1.61 to $1.63. Beyond 2024, we are also reaffirming our long-term guidance, where we expect to grow non-GAAP EPS and dividend per share growth at the mid-to-high end of our 6% to 8% range annually through 2030. Now, to turn to our primary area of focus.

Earlier this month, Hurricane Beryl impacted our entire 5,000-square-mile service territory in the greater Houston area, causing power outages for nearly 2.3 million of our customers, or approximately 80% of our Houston electric customer base. We began tracking Hurricane Beryl and preparing for a possible impact nine days before Beryl made landfall. Initial forecasts showed that our service area in greater Houston would be spared a direct impact by the worst of the hurricane. Nonetheless, we remained vigilant and planned for impact. We initially secured 3,000 mutual assistance crew members from locations safely outside of the projected path of the storm. We also coordinated with utilities across Texas and the region to ensure resource availability.

As the forecast trajectory changed, we quickly called on additional mutual assistance resources, ultimately activating and deploying over 15,000 CenterPoint mutual assistance crew members. Early in the morning on Monday, July 8, Hurricane Beryl made landfall as a powerful Category 1 hurricane with heavy rains, flooding, and up to 97-mile-hour winds that reached further inland than any storm experienced in Houston since 1983. As part of our response, we restored power to over 1 million customers within 48 hours, replaced over 3,000 distribution poles on our system, walked over 8,500 circuit miles to repair damage, and deployed mobile generators at 28 sites across the greater Houston area to various critical facilities. Impacts to our distribution lines and facilities from vegetation, such as uprooted trees and related debris carried by the very high winds, were the primary cause of customer outages.

In recent years, trees in the Houston area have been weakened due to a combination of high rainfall, prior drought conditions, as well as winter freezes. We trimmed or removed approximately 35,000 trees during our restoration process. Through discussion with one of our largest vegetation management companies, 60% of the vegetation it removed were trees that had fallen from outside of our rights-of-way. Over the last 18 months, we proactively worked to address the challenges these conditions present to our distribution system through increased vegetation management. In fact, in 2023, our Houston Electric business increased its vegetation management spend by over 30% from the prior year. We continue to execute and invest at a similar, higher level of vegetation management as we recognize the impacts of the challenging growing seasons experienced in the Houston area over the last three years, and the resulting threat they could have on our lines and infrastructure.

In addition, Hurricane Beryl’s destructive winds, in combination with already weakened trees, highlighted not only the urgency with which we need to execute on our vegetation management plan, but also the scope. As a result, we have doubled our vegetation management resources and are aggressively tackling the riskier line miles with trees nearby. We will trim or remove trees related to an incremental 2,000 miles of our system by December 31st of this year. This represents a nearly 50% increase compared to our planned work for 2024. The vegetation work we have begun is only a part of a more comprehensive plan to improve customer outcomes and directly address the customer concerns and frustrations voiced with respect to critical aspects of our emergency response.

This plan will also help us better prepare our response in key areas to future storms or hurricanes. I will walk through the three pillars of our comprehensive action plan to address our customers’ concerns. Our first pillar relates to our resiliency investments. By accelerating the adoption of advanced construction standards, retrofitting existing assets on an accelerated basis, and using predictive modeling and AI, as well as other advanced technologies, we will harden our distribution system to help withstand more extreme weather and improve the speed of restoration. This is in addition to proactive steps we took nearly two years ago when we moved to constructing at the new national standard for high wind and extreme ice loading. Second, we will build a best-in-class customer communications program.

Since the derecho that impacted Houston in May, our outage tracker has not been available for our customers. The tracker we previously used was hosted on a physical server that was not able to accommodate the demand of millions of users at one time. To keep our communities informed, we provided daily restoration updates, but we understand that for many, this was insufficient. As one component of our customer communication action plan, we are launching a new, more customer-oriented outage tracker later this week. Our new outage tracker will help provide our customers more of the information they need in a timely fashion. It will also be comparable to what our Texas Peer Utility customers experience. The new tracker is cloud-based, which will also allow us to scale to high levels of demand.

Third, we will strengthen our partnerships with government and community leaders. Effective emergency preparedness and response requires close coordination with government officials. We will hire a seasoned emergency response leader to help the company rapidly accelerate its planning capabilities and to develop close community partnerships to help ease the burden of storm events on our more vulnerable communities. We believe the work underlying these three pillars will support our efforts to build and operate a grid that meets the demands of one of the most dynamic economies in the United States here in Houston. The initial set of specific actions we are taking is laid out on slide three. We will also be taking additional actions as we continue to learn from our internal reviews and external independent review, as well as through engagement with emergency response experts, our customers, elected officials, and community stakeholders.

Our singular and overarching goal is to improve in every area of our emergency preparedness and response. Whether it is before, during, or after any future storm, we will be better prepared to support, communicate with, and serve our customers in these times of emergency. As we begin to execute this initial plan, we will work to consistently provide updates on our progress. The men and women at CenterPoint go to work every day with an unrelenting focus on delivering safe, reliable, and resilient energy to our customers, while also striving to improve their experience. We will continue to make customer-focused capital investments to achieve better outcomes for the nearly 3 million electric customers and over 4 million gas customers across our six-state footprint.

And with that, I’ll turn it over to Chris.

Chris Foster : Thanks, Jason. Before I get into my updates, I want to echo Jason’s gratitude to our customers and our communities. Our team is focused on improving our resilience and emergency response capabilities, and I will speak to our financial plan to support those efforts in my remarks today. Today, I’d like to cover three areas of focus. First, the details of our second quarter financial results and guidance. Second, I’ll provide a brief update of the progress we’re making on our regulatory calendar. Third, I’ll touch on our capital deployment status this quarter and forecasted storm costs. And finally, I’ll provide an update on our financing plan. Again, as Jason noted, today we are reaffirming our full year 2024 non-GAAP EPS guidance range of $1.61 to $1.63.

Which represents 8% growth at the midpoint from our 2023 actual results of $1.50. Beyond 2024, we are also reaffirming our guidance, where we expect to grow non-GAAP EPS at the mid to high end of the 6% to 8% range annually through 2030, as well as targeting dividend per share growth in line with earnings per share growth. Let’s now move to the financial results shown on slide four. On a GAAP EPS basis, we reported $0.36 for the second quarter of 2024. On a non-GAAP basis, we also reported $0.36 for the second quarter of 2024, compared to $0.28 in the second quarter of 2023. Diving into more detail of the earnings drivers for the quarter, growth and rate recovery contributed $0.10, which is primarily driven by the ongoing recovery from various interim mechanisms for which customer rates were updated last year, as well as the interim rates in our Minnesota gas business that went into effect on January 1 of this year.

In addition, the Houston area continues to see strong organic growth, extending the long-term trend of 1% to 2% 3average annual customer growth. This sustained growth has been beneficial for our customers and investors alike. O&M was $0.02 favorable for the quarter. This favorable variance was driven primarily by the fact that we incurred more of our expenses in the first quarter and had some of our scheduled activities diverted to attend to restoration efforts related to the major HO storm. Partially offsetting the favorable items from rate recovery in O&M were unfavorable weather and increased interest expense. Weather and usage were $0.01 unfavorable when compared to the comparable quarter of 2023, driven primarily by a milder spring in our Minnesota gas service territory.

Interest expense was $0.06 unfavorable, primarily driven by the new debt issuances since the first quarter of last year to fund customer-driven work across our electric and gas territories at a higher relative cost of debt. I now want to turn to an update on our broader regulatory calendar in progress, and I’ll cover these sequentially from the dates filed. Starting with Texas Gas, where last month, we received Railroad Commission approval of our now final settlement. As a reminder, our four Texas gas jurisdictions will now be consolidated on a go-forward basis for our ongoing rate adjustments. This new consolidation should benefit many customers through a lower impact on their bills from certain investments, and also a reduced administrative burden for other stakeholders.

Moving next to the filed Minnesota gas rate case. And as a reminder, we filed our rate case on November 1st of last year. As discussed on the last call, the interim rates for 2024 were approved in mid-December and went into effect on January 1st. The Minnesota Commission will consider interim rates for 2025 toward the end of this year, depending on how far along we are in the case. Hearings are scheduled to occur in the middle of December of this year. Ahead of those hearings, we intend to engage in settlement discussions with parties involved in the case. And as you may recall, we have settled our previous three rate cases in our Minnesota gas jurisdiction. Now, turning to the Indiana electric rate case. We currently have a non-unanimous settlement pending approval.

Hearings on this settlement will begin the first week of September with a new statutory deadline for a final order of February 3rd. We look forward to continuing to work with stakeholders to achieve what we believe to be a reasonable outcome for all parties. I’ll now touch on our largest jurisdiction, Houston Electric. Over the last month, we have been engaged with many stakeholders as part of settlement discussions in our pending rate case. Those discussions are ongoing, and we continue to provide regular updates to the ALJ in the case. In addition, as we execute on the actions we’ve laid out following Hurricane Beryl, we intend to work with stakeholders on how to amend our system resiliency plan with the PUCT. The process is fluid, but at this stage, we have abated the schedule on the underlying system resiliency plan, which all parties have agreed to.

This allows us to take the coming months to reflect stakeholder input and additional potential system resiliency concepts that emerge from our after-action review and the review of the PUCT. We currently anticipate filing a revised plan later in Q1 2025. Lastly, I want to briefly mention that next month we will file a notice of intent for our upcoming rate case for our Ohio gas business, which is approximately $1.4 billion in rate base. Next, I’ll touch on our capital investments thus far in 2024, as shown on slide 6, including the anticipated impact of storm costs and their associated recovery. In the second quarter of 2024, we invested $800 million of base work for the benefit of our customers and communities. This excludes spending related to storm restoration.

We now have a little less than 60% of our original 2024 capital expenditure target of $3.7 billion to be invested over the remainder of the year, excluding storm costs. We remain on track to meet our capital investment target, despite the interruptions of normal capital deployment from the storms we’ve experienced this year. Maintaining our target as we consider a revised version of the resiliency work is a reflection of the conservatism with which we plan each and every year. Although the cost invoicing is not final, total spending associated with the May storm events and Hurricane Beryl are currently estimated to be approximately $1.6 billion to $1.8 billion. We currently anticipate that we will securitize both the capital and non-capital portion of the $1.5 billion to $1.7 billion distribution costs to limit the impact to our customers on their bills, and will include approximately $100 million of transmission investments within the next T-cost recovery filing.

Based on the total current average residential electric bill, we estimate that these costs could result in an increase of a little more than 2%. As a reminder, the mechanism to recover storm costs in the state of Texas is very constructive and cost-effective for customers. Texas TDUs are able to securitize non-T-cost storm-related costs in excess of approximately $100 million under existing statutory authority. As a result, we anticipate filing for securitization in the fourth quarter of this year, with securitization bond proceeds expected to be received towards the end of next year. Finally, I want to touch on our balance sheet and how we’re thinking about funding the storm costs I just discussed. As of the end of the second quarter, our calculated FFO-to-debt was 13.3%.

Based on our calculation aligning with Moody’s methodology as shown on slide 7, the second quarter tends to be our lightest quarter due to the timing of incremental financing relative to interim recovery mechanisms. This quarter also had a temporary cash flow item that we expect to normalize through the next quarter. Taking a step back, as we continue to see the need to fund growth we are experiencing in Texas, we remain focused on the balance sheet. And with respect to our financing plans through the end of the year, we have evolved our approach. Recognizing the storm impacts. As we remain committed to maintaining our current credit metrics in light of these incremental costs, we intend to pull forward $250 million of equity planned for 2025 into this year, which is in addition to the $250 million issued to date.

This does not change our long-term equity guidance, rather should only be considered as an acceleration. We will also incorporate higher equity content into our upcoming debt issuances to enhance credit metrics until the anticipated securitization proceeds are received. We would also see this as pulling forward instruments we’ve been considering in our long-term plans as mentioned in recent quarterly calls. We remain confident in the continuation of our long-term execution. The last thing I want to mention is we are making good progress related to the sale of our Louisiana and Mississippi gas LDCs. We, along with the filings, including filings with the Louisiana and Mississippi public service commissions, and we look forward to working constructively with the commissions to facilitate the approval proceedings.

We still anticipate closing the sale late in the first quarter of 2025, and it is anticipated to result in after-cash tax proceeds of approximately $1 billion. As a reminder, a majority of these proceeds will be used to fund our capital investments at Houston Electric for the benefit of customers. And with that, I’ll now turn the call back over to Jason.

Jason Wells : Thank you, Chris. Regardless of the challenges we face, this management team remains firmly committed to delivering for all of our stakeholders, our customers, our communities, our regulators, our legislators, and our investors.

Jackie Richert : Thank you, Jason. With that, operator, we’re now ready for Q&A.

Q&A Session

Operator: Thank you. At this time, we will begin taking questions. [Operator Instructions]. Thank you. One moment for the first question. The first question will come from Shar Pourreza with Guggenheim Partners. Your line is open.

Shar Pourreza: Hey, guys. Good morning.

Jason Wells: Morning, Shar.

Shar Pourreza: Morning. Jason, maybe a little bit of a tough question to answer, but I guess, how do you see the commentary that we’ve all been listening to from customers, legislators, and kind of stakeholders impacting the current settlement negotiations in the Houston Electric rate case?

Jason Wells: Yeah, thanks for the question, Shar. Clearly, as I’ve said in a number of different forums, we can and will be better. These are important issues for the greater Houston region, for Texas. Ultimately, though, the answer for getting better is continued investment and resiliency of our system. I think that needs to or will be reflected in the continued negotiations that are occurring from a settlement standpoint. There’s, again, clear demand that we need to communicate better, that we need to mitigate the risk of these outages moving forward. And I think, ongoing settlement discussions are all just part of putting the company in a position to continue to be able to make that progress.

Shar Pourreza: Okay. Got it. Then, just lastly, obviously, Hurricane Beryl certainly highlighted more work needs to be done, and you had a level of resiliency spending bucketed as upside to the $44.5 billion CapEx plan. I guess, how do the recent events impact that bucket even directionally? How fast do you plan to ramp up in light of the increased urgency with the current regulatory construct that’s out there? Thanks.

Jason Wells: Yeah, I think it’s definitely an area of focus. We were investing in resiliency prior to that resiliency legislation. I think we heard loud and clear at the PUCT meeting last week that we need to continue to move forward. We’ve made commitments to move forward. Ultimately, while we’ve pulled down the system resiliency plan, and we are working with outside experts, taking feedback, we’ll obviously work with parties in the case, we plan to rapidly refile it. I think the short of it means there’s probably more support for incremental resiliency investments. I’ll give you one example. In the filing, we proposed continued sectionalization of our system, which is an important part of isolating outages, helping minimize the overall number.

We proposed a pace of about 20 years in that program. I think that’s a program that we need to revisit. I don’t think the 20-year pace is no longer a pace that folks expect of us. If anything, I think the bias will be towards accelerating incremental resiliency investment as opposed to delaying it.

Shar Pourreza: Got it. Okay. Appreciate it. I’ll pass it to someone else. Thank you, guys.

Operator: One moment for the next question. The next question comes from Steve Fleishman with Wolfe Research. Your line is open.

Steve Fleishman: Yeah. Hi. Good morning.

Jason Wells: Good morning.

Steve Fleishman: Good morning. So, just on the, I guess, first, a question on the financing plan, the comment on the equity content in the upcoming refinancing, should we assume that’s more like a junior subordinated, or could that be like a convertible? Any more color on the likely type of financing there?

Chris Foster : Morning, Steve. It is fair to say that we’re certainly looking at different versions of hybrids to pull in more equity content into the plan. And as I mentioned this morning, the other piece is just to pull forward $250 million. Again, to be clear, that doesn’t change the overall guide from 2024 to 2030 of the $1.75 billion total. It’s just a pull forward of that piece. And as you can imagine, the point there is to just be able to have that in place to comfortably position the balance sheet until we get the anticipated securitization proceeds. Currently thinking those are probably going to be end of year next year.

Steve Fleishman: Okay. And then maybe you could just give us some color on how the rating agencies are reacting to this event and spend in your updated plan. And it’s going to be a little while before we know and see the securitization, so just thoughts on kind of their willingness to be patient.

Chris Foster : Sure thing. I think it’s fair to say we’re having a conversation, Steve, obviously, about both how we’re thinking about the plan that Jason has referenced, where we’re going to aggressively move forward here in 2024 to do some critical work in the immediate sense. Longer term, we’re also talking about some initial thinking on moving forward, ideally in Q1 with a subsequent revised system resiliency plan filing. I think in this case, Texas has had a consistent construct in the state for utilities to securitize costs above the $100 million point. Certainly, that’s the case here. And so, sharing certainly that history and consistent history of the state as well in terms of its overall construct. So, fairly fluid conversations, you can imagine, just given how quickly we’re moving on a few fronts, but certainly sharing all of our different activities.

Steve Fleishman: Okay. Great. Thank you.

Chris Foster : Thanks, Steve.

Operator: Our next question comes from Jeremy Tonet with JPMorgan Securities. Your line is open.

Jeremy Tonet : Hi. Good morning.

Jason Wells: Good morning, Jeremy.

Jeremy Tonet : I wanted to pick up on the storm commentary. Thank you for the detail today. Just pulling it all together, looking at your post-hurricane action plan in the items you laid out here, how do you feel about, I guess, how Houston Electric can respond to the next storm out there? Do you think you have the pieces in place now to see a better response, even if everything’s not in place altogether? Just wondering how you guys think you stand now.

Jason Wells: Yeah, no, thanks for the question. I do feel confident. As I mentioned yesterday in the Senate hearing, it offers no relief to the customers impacted by Beryl. We were moving with pace and urgency after the derecho to move to a fully scalable outage tracker platform that would offer estimated times of restoration consistent with industry-leading practices and had begun the work to overhaul our communications. That’s why I feel confident that if a named storm threatens the Texas Gulf Coast region, we’ll be in a much better position to communicate before, during, and after that storm. I think giving our customers the information they unfortunately lack during Hurricane Beryl, but it’s that work that we’ve been doing in advance that I think helps on the communication front.

Equally, it offers no relief to the customers that experienced this pain during Beryl, but we had been working on bringing a lot of the innovative predictive modeling to target enhanced vegetation management and resiliency investments for work. That’s why I’m confident that as we execute on the incremental resiliency commitments that we’ve made to Governor Abbott and others, it will have a meaningful impact for our communities. The last month has been tough on the City of Houston. We understand the role we play, but that’s also why I have confidence looking forward.

Jeremy Tonet : Got it. Thank you for that. Just to follow up here, you mentioned that 60% of the downfall came from outside of your right-of-ways. What can you do about that going forward? Also, I guess just the assets overall, how did the hardened assets perform during the hurricane? Just want to see what value you think has been delivered with prior hardening here.

Jason Wells: Yeah. Again, it offers no relief to the customers, but we are seeing the value of resiliency investments. We saw very minimal structural damage on our transmission system substations. Strategically, it makes sense to put the first investments in the backbone of the system from a resiliency standpoint. We’ve begun some of the incremental sectionalization work and hardening of distribution circuits. That work saved over 150,000 outages in the communities that we deployed that. I think moving forward from a resiliency standpoint, it’s the acceleration of that work on the distribution grid that will have the most meaningful impact to minimizing outages going forward. The key issue, though, at the end of the day was, candidly, there was little structural damage on the system.

It was well less than even 0.5% of our poles failed. But what really caused the outages were, as you pointed out, 60% of the trees impacting our lines were outside of our right-of-way. Candidly, we don’t have any authority today to trim and manage those trees. We are doing the work to identify the trees that create those hazards. We are proactively trying to work with property owners to access that property and address those trees, which are a safety issue, obviously, for the residential homeowner, as an example. A tree can just as easily fall into their home as it could into the power line. But we don’t have authority today unless granted by the homeowner. So, looking to work with community leaders, our regulators, elected officials to make sure that we can continue to work at pace to address this vegetation that threatens our system moving forward.

Jeremy Tonet : Got it. Thank you for that.

Operator: And our next question comes from Nicholas Campanella with Barclays. Your line is open.

Nicholas Campanella: Hey, good morning. Thanks for taking my questions this morning. I appreciate all the details.

Jason Wells: Good morning, Nick.

Nicholas Campanella: Morning. Just wanted to follow-up. As we kind of contemplate pulling forward some of this equity from ’25 into ’24, and then you also talked about doing this equity content financing as well, I know you talked about some kind of one-time issues in the 12-month episode of debt. Where do you think you kind of end at the base year, just based on the current plan today?

Chris Foster : Sure. Good morning. I think if you saw this report this morning, as you can imagine, some of this is just the differing methodologies. But from this standpoint, in the S&P methodology, there’s the assumption that the securitization proceeds do come through, which moves us up to well above the downgrade threshold, up to 12.9%. At Moody’s, right, they treated slightly differently, so it takes us from that roughly 14% to 13.3% where we are this morning. I do have to emphasize, though, Nick, keep in mind that last year this was the same situation. This is a bit of the trough that occurs in Q2 before we pick back up. And we’ve got a one-time item that we believe in Q3 that you’ll be able to see come through further improving FFO to debt. Hard for me to be specific about year end, but just you can imagine where we are at this point is it’s a transitory impact year of the time period that will pass between now and the securitization proceeds.

Nicholas Campanella: Okay. Thanks for that. And then I guess you spoke about doubling some of the labor efforts around the tree trimming. Can you remind us, because you do have this 1% to 2%, I think it’s an O&M reduction forecast in the long-term plan? Does that need to be reassessed? Can you execute on that, even net of these veg management increases? How do we think about that? Does that stuff get deferred? I’ll leave it there. Thanks.

Jason Wells: Thanks for the question, Nick. I think we continue to see opportunity to drive efficiency in our O&M practices to help support that overall 1% to 2% reduction in O&M. We continue to highlight, as we have in the past, a classic example of that is the benefit of deploying the next generation of smarter meters on the gas side. So, we see plenty of opportunity to continue to be efficient, which is, I think, obviously in our customers’ interest, but also helps free up some opportunity to accelerate in other areas. As I highlighted, we increased proactively our vegetation management over 30% last year in 2023, and we still achieved that 1% to 2% reduction year over year in 2023. We will always make the investment that’s needed to drive an improvement in service, but I still feel like we’ve got a number of opportunities across the full scope of the company’s operations to achieve on a consolidated basis that 1% to 2% O&M reduction.

Nicholas Campanella: That’s helpful. Thanks so much.

Operator: And our next question comes from Durgesh Chopra with Evercore. Your line is open.

Durgesh Chopra: Hey, team. Good morning. Thank you for giving me time. I think, Chris, you mentioned 2% will increase from the securitization of the distribution spending. I have two questions related to that. First, the confidence level in $1.6 billion to $1.8 billion, I guess where I’m getting at with that is have you basically taken a deep dive of your costs? Are you still incurring costs? And the number could be significantly higher. That’s one. And second, what that 2% is over — you’re assuming, I guess, cost recovery over a time frame, over multiple years. Maybe just if you could elaborate on that, please. Thank you.

Chris Foster : Sure thing. Happy to. Good morning, Durgesh. I think there’s really two pieces there. I think the first is — I’ll hit the second one first in terms of time frame. At this stage, we would be compiling the costs. The thing to keep in mind is that the existing construct in the state does allow for the entity to combine events that occur, including multiple events over a calendar year, into one securitization. So, again, we would seek to file that and ultimately assume, in this situation, end of year 2025 time frame for recoveries there. As it relates to the overall kind of profile itself, the thing to keep in mind here is that we do already have a good feel of the asset-based costs associated with both the derecho and Hurricane Beryl.

The primary driver beyond that is most commonly the labor costs, right? The costs associated with nearly 15,000 individuals that were doing work on our system. And so, we do have a pretty good feel of how those are forecasted at this stage, which informs the disclosure this morning at the high end of $1.8 billion. So, again, it’s going to be a somewhat similar profile, just given the crews and the associated contracts are very similar as to what we saw in the situation with the derecho, and we’re well over 75% of those costs already in. So, it gives us confidence to inform the profile that you see today.

Durgesh Chopra: Excellent. Thank you. Just one quick clarification, Chris. The 2%, I think you mentioned the 2% impact on customer bills. I guess where I was going with the time frame is that assumes that $1.8 billion is collected over how many years?

Chris Foster : Sure. Traditionally, in the statutory requirement in Texas, it’s 15 years.

Durgesh Chopra: Thank you. I appreciate the time.

Chris Foster : Sure thing.

Operator: Our next question comes from David Arcaro with Morgan Stanley. Your line is open.

David Arcaro: Hey. Good morning. Thanks for taking my question.

Jason Wells: Good morning, David.

David Arcaro: Morning. I’m wondering if you might be able to comment on the legislative outlook from here. I’m curious if there are legislative initiatives that you might pursue or support, just any ideas that may be being explored by lawmakers in the state to help improve resiliency?

Jason Wells: A couple of the topics that have come up early on are consistent with my previous discussion around vegetation management. I think the question is, does the state of Texas, do we need to do something different to be able to attack these hazard trees that are outside of right-of-ways and do so in a manner that is obviously constructive with property owners? I think that’s obviously a place to look. The other thing that’s come up is sort of the unique aspect of the market here in Texas, the fact that we have a service relationship with customers but not a commercial relationship. It’s, at the end of the day, inexcusable that we don’t have customer contact information at each address since we have that service-related responsibility.

There may be something around that as well. Clearly, yesterday, there was a lot of feedback on mobile generation. Right now, we want to be constructive with the policy objectives of the state. As I mentioned in the Senate hearing, we have an order by the PUCT that we cannot allow a customer to go more than 12 hours without power in a load shed event. Those assets are necessary to comply with that order, but if policymakers want to change that direction, obviously, we will work to support the policy direction of the state. There’s a lot of different things being discussed now, and I think that they will come into greater focus as we approach the end of the year and, obviously, the start of the legislative session next year.

David Arcaro: Okay. That’s helpful. Thanks. Maybe, Chris, just wondering if you might be able to clarify, is there a target for when you would expect to get back. At the FFO/Total debt level, you would expect to get back into the target range and get above 14%? For example, at Moody’s?

Chris Foster : Sure, David. I think what you’ll see there naturally is that you’ll have the adjustment upward from S&P that will take place, and then Moody’s does so upon receipt of proceeds. Again, so you’d be looking at roughly Q4 of next year in this timeframe.

David Arcaro: Okay. Understood. Thanks so much.

Operator: And the next question comes from Julien Dumoulin Smith with Jefferies. Your line is open.

Julien Dumoulin Smith: Hey. Good morning, team. Thank you, guys, for the time. I hope you guys are hanging in there. Just maybe on the puts and takes, obviously, you talked about some of the accelerated equity here on ’24. Just can we talk a little bit about your thoughts on the positive offsets here to the pressure points, whether it’s additional OpEx in the form of these storms, to the extent to which there’s any realized interest expense or ultimately just lost sales? How do you think about the good guys and bad guys in the offset there to maintain the outlook here in the very near term?

Chris Foster : Sure thing, Julien. In the very near term, as you can imagine, there was a usage impact associated with the storm itself. We also had a situation where we were having to adjust work temporarily as it related to the literal storm response and restoration. But ultimately, as we’re looking through the remainder of the year, as you saw, we reaffirmed this morning, gives us confidence that we’ve got both two things going on. One, the ability for the mutual aid and other crews who joined our colleagues to really effectively work to restore customers quickly. But also, as I mentioned, we have been able to retain confidence in achieving the base CapEx plan as well. So net of the different factors, including interest expense, we’re confident that we’re still able to reaffirm this morning.

Julien Dumoulin Smith: All right, fair enough. And then just coming back to the mobile gen, I mean, that’s been getting a certain amount of attention here. And obviously, perhaps they were contemplated for a slightly different circumstance. How do you think about developing a more refined program here to target more of these localized distribution-related outages with vegetation management issues that you’ve encountered here? And ultimately, how does this work in, because of which you evaluate this or otherwise, into a revised timeline on the resiliency filing here? I know that there’s various permutations there as well.

Jason Wells: Yeah, I mean, I strongly believe we have the most comprehensive mobile gen program consistent with what has been asked of us by the state and its policy objectives. The legislation was passed in 2021, and there was a focus on load shed events. Those are sort of larger units tied to substations. And as I mentioned yesterday, there’s been 115 instances since that legislation started to be discussed where there were tight system conditions on our cotton. Those systems, those units may be to be utilized. We had also utilized in 2021 one of the medium-sized units for storm restoration and got a significant amount of pushback. And I think the legislature clarified that in 2023. And as soon as we got that clarification in the fall of 2023, we increased the number of small units.

And so, I’m proud that we were able to scale to 18 small units out of a total of 30. The other 12 we borrowed from our utility peers to be part of the storm response. And so, as I said yesterday, we manage a number of different risks, whether those are load shed events or storm response. We’ve got a portfolio of assets to kind of meet those needs. Now, obviously, as I said, if the policy objectives of the state change, we will change with them. But I think today we are maintaining a diversified portfolio for the diversified set of risks that we manage.

Jackie Richert: Operator, I think we’re going to have time for one more question.

Operator: Okay. And our last question will come from Anthony Crowdell with Mizuho. Your line is now open.

Anthony Crowdell : Hey, thanks for squeezing me in. I appreciate it. Just two quick ones. I’m not sure if one was answered. If I look on slide 3 and the plan and everything else, if I remember correctly, your system resiliency plan was between $2.2 billion and $2.7 billion. $2.2 billion was the base case. Then, what’s on slide 3 be accomplished as a $2.7 billion number, or that would be above the $2.7 billion number?

Chris Foster : Anthony, morning. I was thinking about it within the $2.7 billion. Keep in mind that we provide that higher end as an articulation of the ability to accelerate some work, and that’s really what you’re seeing here is a pretty aggressive acceleration here in 2024 to make sure we’re doing more work on the system.

Anthony Crowdell : Great. And then a follow-up to an earlier question, you guys identified a lot of the outages occurred due to, I think, trees that are on customer’s property. You guys didn’t really have any responsibility over it. I mean, does undergrounding become more of a solution in your service territory than maybe years past?

Jason Wells: Yeah, thanks, Anthony. It’s a great question, and I think one where there’s certainly going to be a greater push for undergrounding, and it will play probably an even more prominent role in our resiliency efforts going forward. But what I think is important as well as to kind of balance it, about 60% of our customers today receive service through underground lines. It’s a pretty significant penetration of undergrounding already in the system. But the point of weakness is those communities are often fed with overhead lines kind of at the feeder level. That’s where we saw the tree damage. And so, I think we have to find a balance between undergrounding where it makes sense and where we have overhead lines, making sure that they are hardened and more resilient so that they’re not the single point of failure, so to speak, from an outage standpoint.

So, it’s a little bit of an all of the above, but I would imagine that undergrounding takes an even greater prominence moving forward.

Anthony Crowdell : Great. Thanks for taking my questions.

Jason Wells: Thanks, Anthony.

Jackie Richert: Great. Operator, with that, that will now conclude our Q&A for the day. I appreciate everyone dialing in. I think with that, we’ll conclude the call.

End of Q&A:

Operator: This concludes CenterPoint Energy’s second quarter 2024 earnings conference call. Thank you for your participation and have a good day.