Title

Presentation

CenterPoint Energy, Inc. misses on earnings expectations. Reported EPS is $0.53 EPS, expectations were $0.55.

Operator: Good morning. And welcome to CenterPoint Energy, Inc.’s First Quarter 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. To ask a question, press 11 on your touch-tone keypad. I will now turn the call over to Jackie Richert, Senior Vice President of Corporate Planning, Investor Relations, and Treasurer. Miss Richert?

Jackie Richert: Good morning, and welcome to CenterPoint Energy, Inc.’s First Quarter 2025 Earnings Conference Call. Jason Wells, our CEO, and Chris Foster, our CFO, will discuss the company’s first quarter results. Management will discuss certain topics that contain projections and other forward-looking information and statements that are currently 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 on various factors, as noted within our Form 10-Q and other SEC filings, as well as our earnings materials. We undertake no obligation to revise or update publicly any forward-looking statements.

We reported $0.45 of earnings per share for the first quarter of 2025 on a GAAP basis. Management 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 guidance methodology and reconciliation of the non-GAAP measures used in providing guidance, please refer to our earnings 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. On today’s call, I’d like to address four key areas of focus. First, I’ll touch on our first quarter financial results. Second, I will discuss the improvements we have made in advance of the upcoming hurricane season in support of our goal to build and operate the most resilient coastal grid in the country. Third, I’ll provide a brief update on our regulatory progress through the first quarter and touch on a few recent filings at Houston Electric. And lastly, I’ll provide an update on the continued significant and diversified load growth in our Houston Electric service territory, which is driving an increase of $1 billion to our capital investment plan through 2030.

Now starting with our first quarter results. This morning, we announced non-GAAP EPS of $0.53 for the first quarter. As a quick reminder, as Chris will cover in more detail, I want to emphasize that our incremental revenue from capital recovery mechanisms will be more weighted to the second half of the year as we were unable to access those mechanisms consistent with our historical schedules last year, given our rate case activity. We anticipated this profile when we initiated our guidance, and we are reaffirming our 2025 non-GAAP EPS guidance range from $1.74 to $1.76, which equates to 8% growth at the midpoint from our delivered 2024 non-GAAP EPS of $1.62. Over the long term, we continue to expect to grow non-GAAP EPS at the mid to high end of our 6% to 8% range annually through 2030.

We also expect to grow dividend per share in line with earnings growth over the same period of time. I would like to now discuss the improvements we have made in advance of the upcoming hurricane season. As many of you recall, immediately after Hurricane we introduced our Greater Houston Resiliency Initiative to significantly accelerate resiliency investments, reduce the number of outages during extreme weather events, as well as to help restore service more quickly when those outages occur. I’m proud of the progress our crews have made. By June 1, we will double the number of grid automation devices on our system. We’ll replace 26,000 poles designed to withstand extreme winds and trim or remove over 6,000 miles of high-risk vegetation since we launched this initiative last August.

It is important to note that much of this work is being performed in parallel with our base workload plan. In fact, taking altogether, we will have completed what amounts to an extra one and a half years of work on top of our base work plan in the last nine months. I want to thank the team here at CenterPoint Energy, Inc. for acting with urgency to improve customer outcomes as we head into the 2025 hurricane season. We remain committed to working towards our goal of being the most resilient coastal grid in the country. Now turning to my third key area of focus, a brief overview of our regulatory progress, including some recent filings at Houston Electric. Before I touch on any specific regulatory filing, I want to put into perspective what our teams have accomplished over the last eighteen months.

Last year, five of our now seven service territories were subject to a rate case proceeding that represented nearly 90% of our enterprise rate base. As of today, we have received final orders in three and are now awaiting another for our Minnesota gas business, we’ve already reached an all-party settlement. After the conclusion of the last rate case for our Ohio gas business, we expect that over 80% of our enterprise rate base will not be subject to a general rate case proceeding for about another four years. This significantly derisked regulatory profile provides a solid foundation for our financial plan through the remainder of the decade. I now want to briefly touch on a few filings in our Houston Electric service territory. Chris will provide updates on filings in our other jurisdictions in his section.

I’ll start with our most recent filing related to our temporary generation units. Last week, we made a filing to remove the unamortized rate base of our large temporary generation units. As a result, average residential customers will see a reduction in their electric delivery charges, which, over time, equate to a monthly savings of up to $2. This plan was publicly supported by several key stakeholders at a recent legislative hearing. Second, I want to provide an update on our system resiliency plan filing. As you may recall, we refiled our system resiliency plan in January. The contents of that filing were informed broadly by our extensive stakeholder engagement after Hurricane Barrow. We heard loud and clear that our stakeholders wanted a more resilient grade delivered at an accelerated pace.

We believe the investments included in our updated filing are responsive to that feedback, as well as the feedback we’ve received from interveners from our initial filing. We look forward to further discussing the merits of our plan during a mutually agreed to mediation, which is scheduled for next week. Absent a settlement in this docket, the PUCT has a statutory deadline of mid-September to show its final order. Lastly, I want to touch upon our upcoming cost determination filing related to the storm cost recovery for Hurricane Barrel and other storms. Within the next two weeks, we anticipate making our cost determination filing to seek recovery of the $1.1 billion of cost incurred to restore over 2 million outages as a result of Hurricane Barrel.

In addition, this filing will also include approximately $100 million of restoration costs related to two subsequent storms. Approximately 90% of the Hurricane Barrel related costs are related to 2,000 CenterPoint Energy, Inc. frontline personnel and nearly 13,000 mutual aid workers who traveled from approximately 30 states over a nine-day period. Notably, their work led to restoration times that were in line or better than other Texas peers as well as peers outside of Texas that experienced similarly damaging storms. The securitization mechanism for Texas continues to be an important and constructive storm cost recovery tool for both customers and utilities. It mitigates the customer bill impact of system damage from severe weather while also providing liquidity to utilities to continue to efficiently fund capital investments for the benefit of customers.

We look forward to working with stakeholders towards a constructive resolution of this upcoming filing. As I mentioned, Chris will cover the details of our other regulatory filings in his section. Finally, I want to discuss the recent load growth in our Houston Electric service territory and provide some additional color on the $1 billion increase to our capital investment plan through 2030. As you may recall, on our last quarter call, we outlined what we believe to be a conservative forecast of a 10-gigawatt increase by 2031 in peak load on our Keystone electric system. We continue to see positive trends that only bolster our confidence in this forecasted load figure. Notably, since we submitted our forecast to ERCOT in January, our load interconnection queue has grown by another seven gigawatts through 2031.

This represents a nearly 20% increase in load interconnection requests in a little more than two months. This significant increase is driven by a diverse set of load growth factors, including industrial customer demand, data centers, and transportation electrification projects. At this time, we are not increasing our forecast of a peak load increase of 10 gigawatts by 2031, which, as a reminder, represents about a 50% increase in peak demand on our system over the next six years. However, these new data points provide us even stronger conviction in our submitted forecasts. This tremendous growth potential will undoubtedly require additional capital investment in the electric transmission system, which, as we alluded to on the fourth quarter call, we believe to be at least an incremental $3 billion of capital investment by the end of the decade, with likely more thereafter.

While the total forecasted capital investment and exact timing are still being refined and will be influenced by the PECT recommendation on the high voltage standard, we plan to incorporate the increased capital investment in our guidance over the course of this year, starting with today’s increase of $1 billion. This initial $1 billion increase in our capital investment guidance, which now takes our total investment plan to $48.5 billion through 2030, reflects nearly a dozen transmission projects we will be submitting to ERCOT regional planning group in the coming weeks. We will continue working with stakeholders on the final transmission voltage standard and anticipate providing additional updates to our capital investment over the next two quarters.

In addition to these electric transmission investment opportunities, we continue to see a robust set of incremental capital investment opportunities in our Houston Electric service territory as well as other jurisdictions. In Houston Electric, we see the potential capital investment opportunities as we partner with the city of Houston on its downtown revitalization program, which will require substantial investment to support both growth and modernization of our underground electric system in our downtown substations. We will also evaluate additional resiliency investments towards the latter part of the decade as we continue to aim to be the most resilient coastal grid in the United States. We also have a number of incremental capital investments outside of our Houston Electric business.

One example relates to our Texas gas business, which relies on third parties to move our owned gas throughout the Greater Houston region. We believe there’s an investment opportunity to build a localized high-pressure distribution network around the city of Houston, similar to what we’ve constructed in our Minnesota gas service territory, that can result in significant savings for our customers. Investments related to this project will likely begin next year and extend well into the next decade. We are excited to share more about all of these capital investment opportunities in the third quarter of this year when we plan to provide a new comprehensive ten-year plan. These examples of capital investment opportunities across our business further strengthen our conviction that we have one of the most tangible long-term growth plans in the industry.

We believe that the growth in Houston Electric service territory in combination with capital investment opportunities and our other businesses will continue to drive growth for years to come. Equally important, this growth will also provide a sustainable platform for our customers, whose charges will continue to benefit from the ever-growing population and economic activity. We are privileged to serve all of the communities across our four-state footprint, and we continue to focus on executing for the benefits of our customers and all of our stakeholders. And with that, I’ll hand it over to Chris.

Chris Foster: Thanks, Jason. This morning, I will plan to cover four areas of focus. First, the details of our first quarter results and how we’re thinking about the remainder of the year. Second, I’ll touch on the regulatory progress we’ve made across the various states that we have the privilege to serve. Third, I’ll discuss our progress on the execution of the 2025 capital investment plan and our positively revised capital investment plan through 2030. And finally, I’ll provide an update on where we ended the first quarter with respect to the balance sheet and credit metrics. Let’s now move to the financial results shown on slide six. On a GAAP EPS basis, we reported $0.45 for the first quarter of 2025. On a non-GAAP basis, we reported $0.53 for the first quarter of 2025, compared to $0.55 in the first quarter of 2024.

Our non-GAAP EPS results for the first quarter removed the book loss resulting from the sale of Louisiana and Mississippi Gas LDCs. As part of the sale, $217 million of goodwill was disposed. This was the reason for the book loss associated with the transaction. Now taking a closer look at the quarter, gross and rate recovery contributed $0.03 when compared to the same quarter last year. I want to take a moment to discuss why this is lower than what you’ve seen in our previous first quarter earnings walks. As a reminder, during 2024, we were prosecuting five separate rate cases, and due to this, we were unable to recover our capital investments on our normal filing rhythm of traditional interim recovery mechanisms. In some cases, such as the distribution and transmission capital trackers at Houston Electric, these filings were delayed several months from when they were traditionally filed.

In other instances, such as the GRIP filing at Texas Gas, we were unable to file for recovery of capital investments for over a year. The filings we made during the first quarter represent a catch-up of capital investment recovery and represent nearly $2.2 billion of capital investments made in 2024 and nearly $260 million of associated revenue requirement increases. Over the next few months, rates will be updated, and the associated earnings will begin to materialize. As such, you should expect a lower earnings profile in the first half of 2025 primarily due to these timing differences. Slide seven depicts our expectation for the earnings shape for the remainder of the year. As you can see, we expect a more back-weighted earnings profile than typical in our non-post rate case year.

As Jason mentioned, this shape was known at the time we initiated guidance, and we are confident in our ability to execute through the remainder of the year. Coming back to the quarter, weather and usage was a favorable $0.05 when compared to the comparable quarter of 2024, as Texas and Indiana both had more seasonably normal weather as compared to the milder weather of Q1 2024. O and M was $0.02 unfavorable when compared to the first quarter of 2024. This was primarily driven by the timing of work as we sought to accelerate our vegetation management work ahead of the official start of the 2025 hurricane season. In addition, interest expense and financing costs were $0.04 unfavorable when compared to the first quarter in 2024. These $0.04 were primarily driven by the approximately $3.4 billion of net new debt issuances since the first quarter of last year, some of which were slightly higher coupon junior subordinated notes, given our focus on the balance sheet and emphasis on credit supportive instruments.

Lastly, as you may recall, last year, we issued $500 million of common equity. $250 million of these issuances were a pull forward from 2025, as we sought to strengthen our balance sheet after storm restoration. These equity issuances resulted in an unfavorable variance of $0.02, quarter over quarter. Next, I’ll briefly touch on our regulatory progress related to the interim capital recovery trackers we filed during the quarter starting with Houston Electric. As I mentioned in my earlier remarks, we had a number of interim filings that we filed outside of our normal cadence. The distribution capital recovery tracker or DCRF was one such filing. We filed the first of our two allowed for the year in February with a requested revenue requirement increase of approximately $123 million.

This filing incorporates capital investments made between January and December of last year and was updated for revenues otherwise recovered in our Houston Electric case. We expect that customer delivery charges will be updated later in June. In addition to the distribution capital tracker filing, we also filed for the first of our two allowed transmission recovery tracker filings or TCOS. This filing included a revenue requirement increase of approximately $64 million, which was recently approved with rates anticipated to be updated in the coming weeks. And moving now to Texas Gas. In mid-February, we filed our annual capital investment recovery mechanism or GRIP, which included a revenue requirement increase of approximately $71 million. I’d like to highlight that this is another one of the interim recovery mechanisms that we were unable to file last year as we prosecuted the Texas Gas rate case.

The $71 million revenue request is larger than pre-GRIP filings, as it incorporates fifteen months of capital investments for which we are seeking recovery rather than the traditional twelve months. We anticipate customer gas delivery charges will be updated to reflect the new revenue requirement associated with this filing by early June. Next, I’ll touch on our capital plan execution through the first quarter and our positively revised capital plan through 2030 as shown here on slide eight. In the first quarter of 2025, we invested $1.3 billion of base work for the benefit of our customers and communities. In short, we are right on track to meet our 2025 capital investment target of $4.8 billion. Looking further ahead, and as Jason mentioned, today, we are increasing our capital investment plan that runs through 2030 by $1 billion from $47.5 billion to now $48.5 billion.

We intend to finance these incremental investments in line with our previously communicated rule of thumb of 50% equity and 50% debt. To be clear, however, we are not updating this year’s equity plans as we still do not intend to issue common equity. That’s because we pulled forward our 2025 equity base plan needs last year. Today’s capital investment increase is one of our first steps in a planned effort to sustainably increase our capital investment plan to support the rapid and significant growth the Greater Houston area continues to experience. Over the next two quarters, you should expect incremental updates regarding CapEx and associated financing. Later in Q3 of this year, we will be in a position to aggregate all of these updates as well as provide others to you to give you all a comprehensive update and a new ten-year plan.

Finally, I want to touch on how we’re thinking about the balance sheet and where we ended the quarter with respect to our credit metrics. As of the end of the quarter, our trailing twelve months adjusted FFO to debt ratio based on the Moody’s rating methodology was 13.9%. When removing transitory storm-related costs, this quarter, we made progress towards getting back to our target cushion range of 100 to 150 basis points with the closing of our Louisiana and Mississippi LDCs, which resulted in net cash proceeds of a little over a billion dollars. We also expect an additional $400 million of securitization proceeds related to the May 2024 derecho storm event later this summer. In addition, as Jason discussed, we plan to file for the cost determination for the roughly $1.1 billion of storm costs related to Hurricane Beryl and $100 million related to other storms within the next two weeks.

We anticipate receiving securitization bond proceeds around the end of this year. During the quarter, we also took advantage of the recent stock performance and proactively worked to derisk 2026’s financing plan. In particular, executed equity forward sales through our ATM program of approximately $145 million. With respect to 2025 common equity needs, there is no change, as we do not anticipate the need for common equity through the remainder of the year to fund our current plan. However, we’ll continue to be opportunistic in addressing 2026 equity needs. We will continue to stay laser-focused in supporting the balance sheet while also investing for the benefit of our customers and communities. We are off to a solid start in 2025, and we are right on plan to deliver our full-year results.

We are reaffirming our 2025 non-GAAP EPS guidance range of $1.74 to $1.76, which equates to 8% growth at the midpoint from our delivered 2024 non-GAAP EPS of $1.62. Over the long term, we continue to expect to grow non-GAAP EPS at the mid to high end of the 6% to 8% range annually through 2030. We look forward to the remainder of 2025 and executing for the benefit of all stakeholders. And with that, I’ll now turn the call back over to Jason.

Jason Wells: Thank you, Chris. We are excited about the opportunities in front of us through the end of the decade and beyond, and we look forward to sharing an updated ten-year plan in the third quarter of this year.

Jackie Richert: Thank you, Jason. With that, we’ll now turn it over to Q&A.

Operator: If you wish to ask a question, please press 11 on your touch-tone keypad. The company requests that when asking a question, callers pick up their telephone handsets. Thank you. Our first question is from Shar Pourreza with Guggenheim Partners.

Konstantin Lednev: Hi. Good morning, team. It’s actually Konstantin here for Shar.

Jason Wells: Thanks for taking questions. Starting off on the CapEx update,

Konstantin Lednev: as you were including the $1 billion of upside today, how should we be thinking about the cadence of updates as we get to 3Q roll forward? Do you anticipate more incremental updates in the 2030 plan, or is there a more comprehensive March update? How does the higher run rate imply for the upside roll forward to plan?

Jason Wells: Yeah. Good morning, Konstantin. It’s Jason here. Maybe two key points, and then I’ll expand. First, you know, we do see significant CapEx tailwinds across our business, in particular in Houston Electric, but also, as I alluded to in our Texas Gas business as well. Second, and to your point on timing, we have a history of updating kind of our CapEx guidance as we get incremental data points, and we’re going to continue to use that approach. So you know, this quarter, we’ve updated the CapEx guidance for the billion dollars, really reflecting the nearly dozen projects that will be filing with the ERCOT regional planning group. We have additional projects that we will file later this summer. There will be a time, you know, whether it’s the second quarter call or third quarter call, we’ll have even incremental updates with respect to electric transmission.

And then, we will also provide, as we’ve discussed, a much more comprehensive update in the third quarter, really rolling forward to that ten-year plan. But last time we initiated a ten-year plan, you know, we initiated it at $40 billion, and today, it’s at $48.5 billion. The CapEx tailwinds remain significant, and I’d expect us just to be in a periodic rhythm of updating as we get additional regulatory data points.

Konstantin Lednev: Great. Thanks for that. And we’ve seen some regulatory lag issues with peers in Texas due to the growth and the inflection in CapEx. And as you’re adding the CapEx and rolling forward, do you see any rate constructs being adequate to limit the ROE issues you just came out of the rate case? Or would you look for any improvement construct on a go-forward basis?

Jason Wells: Yeah. Let me be clear. I don’t see any challenge with regulatory lag to achieve the guidance that we’ve initiated. And I think our track record helps prove that. You know, when we initiated our original ten-year plan, we doubled CapEx at Houston Electric. We’ve since doubled it again, and we’ve also nearly doubled it yet again. Over that period of time, we’ve increased our earned returns. So I don’t see this profile of incremental CapEx providing challenges from a regulatory lag standpoint in terms of achieving our guidance. Now that being said, just because we have a historical test year, we have some regulatory lag in our business that we will constantly look at regulatory and legislative solutions to help chip away at.

We think it’s in our customer’s best interest to fund incremental CapEx from the ongoing cash that we generate in the business. And so there will be a continued focus on reducing regulatory lag for the benefit of our customers and our investors. But I just want to be 100% clear. We do not see a challenge with regulatory lag for achieving the guidance that we’ve outlined.

Konstantin Lednev: Excellent. Appreciate that. Congratulations.

Operator: Our next question comes from Nicholas Campanella with Barclays.

Nicholas Campanella: Hey, good morning. Thanks for taking my question.

Jason Wells: Good morning, Nick.

Nicholas Campanella: Hey. Good to see the momentum on the capital expenditures. Can you maybe just kind of talk about where your head is at financing these new opportunities and just recognize that you kind of trade at a more healthy multiple? So is equity kind of your preferred route here? Should we be looking towards asset sales? Just what’s kind of the pecking order? And if you are looking at asset sales, maybe kind of talk about what’s core versus not. Thanks.

Chris Foster: Sure. Good morning, Nick. I think it’s a few key factors to think about. Let me first just remind you that even with the CapEx momentum, we were clear this morning that there is no incremental 2025 equity need. So that’s kind of the place to start. Given where we are trading, we’ve also been really focused on being proactive there. Right? So you also saw us move forward with the forward equity approach to derisk a portion of 2026. Beyond that, as we look into the electric transmission opportunities that Jason referenced, those will be probably more back-weighted going forward. And so as a result, we’ll consistently look and have always in recent years, looked at the way to most efficiently finance that work going forward.

We’ve previously provided the growth-related CapEx rule of thumb of 50% debt, 50% equity to fund as we go forward. And at the same time, just given where we are, I’ll say, kind of macroeconomically, there’s certainly been increased interest in, in particular, gas LDCs just kind of broadly in the country. I think as a result, that’s increased inbound for us as well. And so you can imagine we’re going to consistently be open to the most efficient way to finance our work. And finally, think the other thing to keep in mind is now that we’re working our way through really completing a lot of these rate cases, as you look at the net benefits, there’s both the earnings-related tailwinds that Jason’s referenced before, but it is also the case that we’ve been able to improve our operating cash flow profile.

So we’re seeing, really, when you isolate just all those benefits of completing those cases, that really credit to the team to getting us to this point, we probably are looking on the order of roughly 5% operating cash flow improvement. So, hopefully, that gives you the color for kind of how we’re thinking about the plan going forward.

Nicholas Campanella: That’s super helpful. And, you know, as we kind of look towards the third quarter when we get the kind of full plan, you’ve been doing this 6% to 8% long-term earnings growth outlook. You’ve been doing closer to 8% plus. And just your kind of philosophy and how that’s changing? Can you just give us an idea if you are, I guess, reassessing the CAGR as we get into the third quarter and where that can go? Thanks.

Jason Wells: Thanks, Nick, for the question. You know, obviously, we’re going to keep you interested in wanting to attend as we update the plan later this year. But look, we’ve got an incredible foundation for our continued earnings trajectory. Right? You know, with the CapEx guidance that we’ve announced today, it’s a 10% plus rate base CAGR through the end of the decade. That’s an incredible foundation. This is capital spend that our customers are asking for. Right? Capital spend that’s driven by hardening our system, improving the resiliency, capital spend that’s associated with the incredible growth of the economy here, a growing rate base, north of 10% through the decade is a really strong foundation for our earnings guidance.

I’d say philosophically, the other thing to think about is we have a track record of delivering at or above the range that we have guided to. You know, I think the most important thing is the absolute confidence in achieving the guidance we put out there. And to the extent that we can over-deliver for all of our stakeholders. So we’ll continue to keep that philosophy in mind. As I said, a strong base, but certainly more to come as we roll out the new plan later this year.

Nicholas Campanella: Alright. Thanks a lot.

Operator: Our next question is from Durgesh Chopra with Evercore ISI.

Durgesh Chopra: Hey. Good morning, team. Solid quarter here. Congrats on that. Hey. Just wanted to start off with Chris, can you help us reconcile the CapEx? Is a billion dollars higher. The equity just increased modestly. Hundred million or so there. Just you know, it’s not your 50% equity with the CapEx increase. So what’s driving that? Why is it such a modestly, modest equity increase versus a large capital increase?

Chris Foster: Sure thing. Good morning, Durgesh. I think what you’re referencing is potentially what we had done in the last quarter as we had increased CapEx at that time. Roughly $500 million and associated with that, there actually was a $250 million equity increase to the plan. So going forward, you should think about it as the same approach, 50% debt, 50% equity as we go. And, again, it’s important to also realize the timing. Right? The sizing and timing. Timing, again, is largely driven by both the fact that we’re in the early planning stages of the electric transmission projects referenced but also that we’re going to be stepping into over time the system resiliency plan work, which really just starts to pick up in ’26 and then more heavily gets work resourced, and we’ll need more CapEx in ’27 and ’28.

Durgesh Chopra: That’s helpful, Chris. Maybe I wasn’t clear. I was just kind of comparing Q4 versus this CapEx update of a billion. And then the equity and equity-linked securities went up from $2.5 to $2.75. Maybe I’m not thinking about this the right way. I would have thought the equity increase would be much larger than just a hundred million.

Chris Foster: No. I understand. And we can follow-up with you, Durgesh, on the explicit materials. It’d be a it was a $500 million increase in an associated $250 million in equity as well.

Durgesh Chopra: Okay. Alright. Well, we’ll follow-up. Then just on the $3 billion in additional capital opportunities, I just want to be clear that’s on top of the billion today. That’s one part of the question. And second, is that $3 billion all tied to the seven sixty five kV, i.e., there’s additional opportunities on top of that $3 billion?

Jason Wells: Hey. Good morning, Durgesh. It’s Jason here. Yeah. There’s at least $3 billion of CapEx upside. I’d say that $2 billion of that relates to what I would consider to be almost regular way electric transmission spend to continue to harden and the system and support growth. I think about a billion relates to sort of the gas transmission opportunity that I discussed. I wouldn’t necessarily say those figures or amounts are impacted by the 760 kilovolt standard. The electric transmission amount could be significantly more than that to the extent that the state adopts that seven sixty five kV standard. So, again, maybe the way I’d look at it is that there’s probably at least $3 billion of incremental CapEx upside the billion that we folded in today. And it could be substantially more than that through the remainder of the decade.

Durgesh Chopra: Got it. Very clear. Thank you, guys.

Operator: Our next question is from Steve Fleishman with Wolfe Research.

Steve Fleishman: Yes. My first question was mainly related to what I think you just answered on the seems like we’re going to get this seven sixty five kV decision pretty soon. Just maybe you could just frame the options. Is it just seven sixty five or lower and just, you know, scenarios for your capital plan, if anything incremental to what you just said?

Jason Wells: Yeah. Thanks, Steve, and good morning. Yeah. We could get the policy standard on the voltage levels as early as today at the PEC meeting. I think there’s, you know, expressed a the state has expressed a desire to move to more of a seven sixty five kV standard, but hopefully, we’ll get further clarity today. I think that that policy will be important for us. We have a couple of our substations that would be impacted by that seven sixty five kV buildout. One of those pathways would connect the northern part of our system to the southern part of our system, effectively cutting right through the greater Houston area. That would be pretty complicated construction and would significantly increase the cost. And so that’s why there’s a pretty wide range of the potential cost for the electric transmission buildout.

Again, we pulled it in a billion today. I think it’s at least $2 billion. It could be substantially more than that if we move to that seven sixty five kV standard and build to that standard connecting the northern part of our region to the southern part of our region. Outside of that, you know, there are other projects as we continue to see significant renewable growth on the system. And making sure that we have kind of a stable grid is important. We are looking at high voltage DC line, which could help provide voltage support on the system as well as maybe more efficiently move those electrons around the greater Houston territory. That would also create an upward bias on the CapEx guidance. I think there’s really, at the end of the day, a significant amount of CapEx upside related to electric transmission.

And the final point I’ll make is we’ve been talking about the incremental upside through the remainder of the decade. You know, as I alluded to in the call, we’re not seeing growth slowdown in the Greater Houston region. If anything, it’s accelerating. So I think the electric transmission buildout will only accelerate as we get into the next decade. Today, we’re able to move fairly quickly with these interconnection requests because we have a little bit of incremental capacity on our electric system. You know, as we continue to connect all this new load, we are utilizing existing capacity, and it’s going to require incremental CapEx to build out that transmission capacity well into the next decade. So think about this as there’s plenty of CapEx upside, whether it’s the seven sixty five kV standard, high voltage DC lines, different paths, through the remainder of the decade.

And then as we get into the 2030s, electric transmission will continue to be a significant tailwind for the company.

Steve Fleishman: Great. Thanks. And one other question. I know your growth is pretty kind of diversified, but in the last few calls, you’ve given some data center backlog numbers. Do you have any updated data center backlog numbers?

Jason Wells: Yeah. You did a seven-gigawatt increase in our interconnection queue, that I mentioned. So, you know, on the fourth quarter call, a little over two months ago, we said that we had a 40-gigawatt interconnection queue. Now it’s 47 gigawatts. You know, six of that is related to incremental data center demand. Our data center queue is now roughly 20 gigs. I think one of the important drivers, Steve, to the diversified point of the economy that you’ve mentioned is we’re starting to grow a larger ecosystem here in the Greater Houston area. We’ve had some really high-profile high-tech manufacturing announcements with Foxconn, Apple, Nvidia, all looking at rapidly expanding their production of their server racks. Everything but effectively the chips.

And I think that that significant investment in that kind of data center ecosystem is also continuing to attract data center demand. And so it has really been an explosive level of growth for us really starting back to last summer.

Steve Fleishman: Great. Thank you.

Operator: Our next question comes from Julien Dumoulin-Smith with Jefferies.

Julien Dumoulin-Smith: Hey. Good morning, team. Thank you guys very much. Nicely done and yet again. Maybe just to get ahead a little bit of our third-quarter conversation here. When you think about the $3 billion additional opportunities, can you just clarify a little bit of the various pieces? I know you said, for instance, there was a billion dollars of gas transmission. But then in the comments, you talked about this high-pressure distribution network that seemingly could be, I think you insinuated, maybe a little bit more than that as you try to replicate what you’ve done in Minnesota. Can you elaborate a little bit on what the various pieces would be to the plus side on the three in terms of whether the seven sixty five and distribution?

And, also, clarify a little bit. I know we’ve got a five-year plan and now increasingly focused on a ten-year plan. Can you just clarify what would be in the five versus ten? It seems as if a lot of these items may be very well back-end weighted, not just within the five-year, but even back-end weighted within the ten versus the five-year plan.

Jason Wells: Hey. Good morning, Julien. There’s a lot to unpack there. I’ll take a stab at it. So in terms of the $3 billion of upside, let me kind of help walk that. So on the fourth quarter call, in Q&A, I talked about that we saw at least $3 billion of incremental electric transmission CapEx upside opportunity. This quarter, we have folded into our CapEx guidance through the remainder of the decade $1 billion of that $3 billion. So there’s $2 billion of, at a minimum, CapEx upside related to electric transmission. As I’ve mentioned in some of the other questions that we’ve received, at least $2 billion of incremental CapEx upside through the remainder of the decade, and could be significantly more than that related or driven by the voltage standard policy decision here in the state of Texas, among other things.

So, again, at least $2 billion more incremental CapEx upside related to electric transmission. I’ve also alluded to at least a billion dollars, and I’ll use this term loosely, but we’ve said gas transmission. It could be a high-pressure network. It’s effectively a ring around the Greater Houston region so that we can move our gas efficiently. Gas that we already own for our customers, from one side of our system to the other. We think that that will lower customer rates by reducing incremental transmission costs to move gas that’s already owned. In some cases, that may be transmission pipes. In some cases, that may be high-pressure distribution. At the end of the day, think about this as a large ring around the Greater Houston region similar to what we did in Minnesota that will allow us to move gas we already own.

I think that that’s right now about a billion dollars, and some of that will creep into the early 2030s. Outside of those two opportunities, I’ll highlight a couple of other CapEx drivers to get to your point. I think that there is CapEx upside, particularly as we look at 2029-2030 related to system resiliency. If you recall, we were the first in the state to file under the new system resiliency plan standard last April. We pulled that filing down after Hurricane Barrel and we refiled a plan that reflected a higher level of spend to more quickly harden our system from the 2026 to 2028 time period. What we have not done is updated our plan to harden our system in 2029-2030 and beyond, consistent with this goal of building and operating the most resilient coastal grid in the country.

So I think that there is incremental CapEx on the back part of this decade and extending into the next related to system hardening. I think up in Indiana, you know, we continue to see electric transmission upside potential electric associated with some of the MISO transmission projects that were announced last year. And we continue to see data center activity occurring up in Indiana, a development standpoint that may provide incremental generation and transmission investment opportunity up there. Outside of those, you know, we continue to see significant growth in the Texas market that results in higher generation interconnection requests. Continued growth in terms of connecting new residential developments. So the short of it is there are significant CapEx drivers, upside opportunities relative to the plan we’ve outlined.

I have been trying most of this time to provide a sense of when we’re talking about at least $3 billion of CapEx upside, that’s through the remainder of this decade. We also then want to highlight the fact that we see some of these drivers extending well into the next, and we will provide more, we will obviously quantify what those long-term tailwinds will be as we roll forward the next ten-year plan.

Operator: Our next question is from Jeremy Tonet with JPMorgan Securities.

Jeremy Tonet: Hi. Good morning.

Chris Foster: Good morning.

Jeremy Tonet: Sounds like a lot of good stuff ahead of you here, but just want to come to a couple of questions that we’re receiving more today. I guess, you know, tariff concerns and recession risk. It seems like Texas is in a very good position, you know, regarding economic activity. But just wondering if you could give us your thoughts across your footprint, you know, if we do go into recession. How you think about that, and any other color on tariff impacts in general? Would be helpful. Thanks.

Jason Wells: Yeah. Thanks for the question, Jeremy. Obviously, it’s an incredibly dynamic environment, you know, changing by the day. So, you know, I’ll keep my comments more directional at this point. And what I would say is, you know, from a tariff cost exposure standpoint, I think we have, on a relative basis, very low risk. We source most of our material and equipment domestically. The little bit that we source internationally, we have already begun to take steps to convert that to domestic supply. So from a tariff cost standpoint, I don’t see that incremental cost pressure as significant across our portfolio. You know, from a recession standpoint, I’ll start with the Greater Houston region. You know, it has really over the last three decades, really diversified the economy here as, you know, even though we’re known for the oil and gas capital of the world, energy now represents only about a third of the economy.

And when we look back over the last two decades, because of the diversification, the economy has held up well under different recessionary pressure over the last two decades. If anything, I see potential tailwinds from the tariff activity. We, as I alluded to in our prepared remarks and Q&A, we have seen an increase in interconnection requests. Some of that is driven by firms interested in onshore manufacturing capacity, and I think some of that is, you know, some of the notable announcements that I also referenced, whether it’s, you know, NVIDIA and Foxconn and Apple, all talking about centralizing some of their high-tech manufacturing here in the Greater Houston region. So we may see it as a tailwind here. You know, I would say as we look around our portfolio, I also think that we’re also relatively well situated from potential recessionary concerns.

You know, the focus on reshoring manufacturing capacity bodes well for our Indiana electric business. There continues to be, you know, very supportive growth on the gas side in and around our entire Indiana gas footprint. And we haven’t seen any evidence of slowdown in Minnesota. So the net of it is I think we’re well insulated from cost pressure just given our domestic supply. And, I think I see the recessionary pressures as really lower risk.

Chris Foster: I think maybe, Jeremy, one other thing I’d add just to keep in mind because I think a lot of folks are now talking about should there be the potential for a recessionary period. How does, you know, what does federal policy look like in reaction specifically as it relates to tax policy? I think there, we’re also well positioned. That’s really for a couple of reasons. First, as you know, we’re primarily a wires company, so we don’t really have the generation-related risk that can go with that. Two, from a transferability standpoint, we really do have minimal exposure on that front because we are a cash taxpayer today, and so we have a practically immaterial amount of potential impact there, and that’s really in the next few years, not just in front of us right now. So just want to be clear. We’re really well positioned on that front as well.

Jeremy Tonet: Got it. That’s helpful. Thank you.

Operator: Our next question is from David Arcaro with Morgan Stanley.

David Arcaro: Hey, thanks. Good morning.

Jason Wells: Hey. Good morning, David.

David Arcaro: Let’s see. Digging in maybe just a little bit into the low growth outlook, you know, there’s been some skepticism that we’ve heard around just how much load will actually crystallize in Texas? I mean, the numbers are huge. So I was just wondering if you could give some color maybe around what gives you confidence in the load growth forecast. Maybe any breakdown you might be able to share on, like, what’s under construction in terms of gigawatts, what’s planned in the near term, next few years? Just any further color on that to increase confidence there?

Jason Wells: David. Appreciate the question. And as we try to initiate sort of this updated view of load growth, a fourth-quarter call. We wanted to emphasize we took what we thought was a very conservative approach. You know, at that time, we outlined a 40-gigawatt interconnection request, and you know, as you mentioned, there is a question about how much of that will materialize. We took a point of view that we think at least 10 gigawatts of that will materialize by 2031 or 25%. Since that call, our load interconnection request is now up to 47 gigawatts. And we haven’t moved to that 10. So I think, you know, I think it’s a pretty conservative approach when you look at that on the broader sort of ERCOT basis. You know, I think ERCOT applied a haircut of about a third to the total submissions, which represented about a 50% increase in peak demand.

You know, we took at the time, a 75% haircut and still had a 50% increase in peak demand as a forecast. You know, at that time. So I think while we’re starting from a conservative standpoint, let me just sort of break down a couple of these categories just to show how conservative they were. You know, at the time, we had about a gigawatt and a half of data center demand in the 10 gigawatts. Or about 11 in the 40. And of the gigawatt and a half that we had incorporated at that time, we’re already working on connecting about a gigawatt. So you can tell that that is a relatively conservative assumption around that. We talked about the fact that hydrogen was another driver for us. That was two of the 10 gigawatts we assumed. And customers were already breaking ground on projects for about a gigawatt and a half of that.

So that was the profile that we have used to be very conservative around these requests. We’re tracking everything. Our teams are working hard to deliver the growth across the full set of interconnection requests. At this time, we think that that 10 gigawatt or nearly 50% increase in peak demand by 2031 is a conservative and realistic assumption.

David Arcaro: Got it. Thanks. Yeah. That’s helpful context. The numbers, even when you haircut them so much, they still are very large. So, yeah, that’s helpful just for some additional color there. One other just quick follow-up on the transmission outlook and the seven sixty five consideration. I guess we’ll get a viewpoint on whether seven sixty five might be the way the state goes today. Is that going to be directly applicable to you, in terms of potentially weaving it in and updating that, you know, the billion dollars CapEx number, or could there still be an evaluation in the future for the state to consider? Well, do we really want to apply 7765 across the state? Could it be a blend of, you know, $3.45 and $7.65 at the end of the day?

Jason Wells: Yeah. I think that’s the question, and it’s why we’ve been conservative in terms of kind of folding in estimates of what that cost will be. You know, currently speaking, the $7.65 network that’s been proposed by ERCOT includes our system. That’s why we’ve been alluding to there is potential CapEx upside beyond what we’ve been discussing. To the extent the state wants to move forward with that approach. Now to your point, they may adopt a seven sixty five kV standard for a portion of the ERCOT market, for all of ERCOT, they may say that each of the utilities needs to bring their own perspective of what makes sense to serve their load and their needs. And so it is a fairly dynamic situation. Currently, a couple of our substations are included as part of the statewide proposal.

The way the transmission bill works here in the state of Texas is, you know, wherever the transmission system ends, whoever owns that substation has the right of first refusal to build. So today, if the policy that has been floated is passed, we would be beginning to work that seven sixty five kV standard for a portion of our system. But we’ve been conservative because it may be that may be reduced. You know, they may change their approach. And so obviously, more to come. We’ve just been trying to provide transparency around the range of potential just given how significant the incremental CapEx is.

David Arcaro: Yeah. Absolutely. That’ll make sense. Great. Thanks so much.

Jackie Richert: Operator, again, we’re at the bottom of the hour now. If you don’t mind, we have time for one more quick question. Thank you. Our last question is from Andrew Russell with Scotiabank.

Andrew Russell: Hey. Good morning, everyone. Just a quick one to elaborate on the load forecast. A lot of detail there. I’ll make it quick. You said the interconnection queue has grown by seven gigawatts. Can you get more details in terms of what types of customers those are? The breakout on slide 12 seems pretty similar to the prior version.

Jason Wells: Yep. You know, of the seven, it’s nearly six gigawatts of that is data center demand, and another gig is roughly half of that is related to manufacturing. And another half a gigawatt of that is related to industrial demand. So, again, we’re continuing to see a diversified set of load growth drivers.

Andrew Russell: Okay. Great. Then just very briefly on the FFO to debt. Good progress. You’re just a hair under the targeted range. And based on all the cash inflows and commentary on financing, the incremental CapEx, seems like you have a high degree of confidence you’ll be north of 14% by year-end. You just give any commentary on conversations you’ve been having with the rating agencies and hopefully getting off of the negative watches?

Chris Foster: Sure thing, Andrew. You’re right. We’re pleased about the progress we’ve already made kind of going into this quarter. You should assume Q2, just to look ahead, is going to be relatively light because of the general profile we have in a given year. But, really, the important part will be, and for the rating agencies as well, the securitization, both the May storms related or derecho events and the hurricane barrel related ones. We are ahead of plan related to and also have a settlement related to the May storms event. So that is absolutely on track. And we do are very focused on year-end completing the hurricane barrel related recovery process and approval and effectuating the securitization. So those are the key drivers for really stepping into next year that comfort that we’ve got around the consistent cushion of a hundred to 150 points that we reference.

With the rating agencies in particular, obviously, I can’t speak for them individually, but I would say, I think their focus has been on a few areas. One, just seeing the strength of the regulatory construct in Texas there, I think we’ve been able to show progress on both our interim capital recovery mechanisms thus far, the Houston Electric rate case, and the May storm’s event progress as I’ve referenced. I think in my sense is in order for them to be able to move off of the negative outlook, it will require some progress here on the hurricane barrel related recovery request. And as we indicated, we will be filing that here shortly. So it will have a period of review of roughly five months for the prudency-related review, and we do think that will be the key period for insight for the market broadly, including the rating agencies.

Andrew Russell: Great. Thanks so much.

Jackie Richert: Thanks, Andrew.

Operator: Operator, with that final call or question, that’ll conclude our call for the day. Thank you.

Operator: This concludes CenterPoint Energy, Inc.’s first quarter 2025 earnings conference call. Thank you for your participation.