Q3 2024 CenterPoint Energy Inc Earnings Call

Christopher Foster

Thanks, Jason. Before I get to my updates, I want to echo Jason’s gratitude for not only our CenterPoint coworkers, but all utility and contractor employees that aided in the restoration efforts during this very active hurricane season.
It was truly remarkable to witness the dedication to a safe response and the speed of the restoration efforts that took place after two devastating hurricanes hit the Southeast within two weeks of each other. I want to thank the roughly one-third of our internal CenterPoint line crews that made the journey to other sector peers to help get the lights back on after those hurricanes.
For the quarter, I’d like to cover four areas of focus. First, the details of our third quarter financial results, including our reaffirmation of 2024 guidance. Second, the initiation of 2025 non-GAAP EPS. 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 plans, including an update to our plans to increase our equity guidance to fund our incremental $2.5 billion, which will be included in our system resiliency plan totaling at least $5 billion in cumulative resiliency investments from 2026 through 2028.
Let’s now move to the financial results shown on slide 7. On a GAAP EPS basis, we reported $0.30 for the third quarter of 2024. On a non-GAAP basis, we reported $0.31 for the third quarter of 2024 compared to $0.40 in the third quarter of 2023. Our non-GAAP EPS results for the third quarter removed the costs associated with the sale of Louisiana and Mississippi Gas LDCs.
The reduced earnings quarter-over-quarter was primarily driven by increased and accelerated O&M that was completed as part of Phase I of the GHRI. When compared to the comparable quarter of 2023, O&M was $0.11 unfavorable.
This $0.11 not only represents the $70 million of vegetation management for which we will not seek recovery, but also the work we pulled forward from the fourth quarter to increase readiness for future potential inclement weather that could impact the Houston Electric system.
In addition to the headwinds from O&M, weather and usage contributed an additional $0.06 of unfavorability quarter-over-quarter, $0.02 of this unfavorable variance was driven by reduced usage caused by outages from Hurricane Beryl along with a considerably milder summer in the Houston Electric service territory as compared to 2023.
We continue to recover on our customer-driven investments, which contributed $0.09 of favorability this quarter when compared to the comparable quarter of 2023. This was 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% average annual customer growth. As Jason referenced, this dynamic aids in keeping future increases in our customer electric delivery charges roughly in line with the forecasted rate of inflation over the next 10 years.
Interest expense and financing costs contributed $0.01 of favorability when compared to the comparable quarter in 2023, due to moderating interest rates and the favorable variance from the redemption of the Series A preferred stock in September of last year.
Despite the headwinds we faced this quarter, we continue to reaffirm our full year 2024 non-GAAP EPS guidance range of $1.61 to $1.63. Our confidence in reiterating our full year 2024 guidance today is driven by the O&M work on the system that we accelerated into the third quarter.
Our updated work plans are reflected in the $0.11 of unfavorability I mentioned as the work otherwise would have been spread across the third and fourth quarters. This is a departure from last year where we highlighted some higher O&M costs in the fourth quarter, reflecting work, including incremental vegetation management.
In addition to reaffirming full year 2024 non-GAAP EPS guidance, today, we are also initiating our 2025 non-GAAP EPS guidance target range of $1.74 to $1.76 per share. The midpoint of this range represents annual growth of 8% from the midpoint of our 2024 non-GAAP EPS guidance target range of $1.61 to $1.63.
Our 2025 figures are a byproduct of the significant investments we’ve made across our various jurisdictions over the last couple of years. As you may recall, we accelerated investments in the Houston Electric service territory last year, and we continued a strong investment profile across our jurisdictions this year. These investments have resulted in a rate base CAGR of more than 11% over the last two years.
The strong foundation of organic growth with the new capital investments, combined with rates we are anticipating through our interim rate mechanisms and rate case outcomes give us the conviction in our 2025 non-GAAP earnings guidance initiated today.
Next, I’ll touch on our capital investments execution as of the quarter in 2024, as shown on slide 8. In the third quarter of 2024, we invested $900 million of base work for the benefit of our customers and communities. This excludes spending related to storm restoration.
Year-to-date, we have invested approximately $2.6 billion, which represents over 70% of our original 2024 capital expenditure target of $3.7 billion. We remain on target to meet our base capital plan investment despite the interruptions of normal capital deployment from the storms we’ve experienced this year.
I’d also like to provide a quick update on where we stand with storm costs related to the major (inaudible) event and Hurricane Beryl. With the majority of costs accounted for, we are now able to refine our estimate to the low end of the previously disclosed $1.6 billion to $1.8 billion range as we now estimate costs for both storms to total $1.6 billion.
We intend to make our filing for cost determination in connection with the securitization for the May storm costs in the coming weeks and storm registration costs associated with Hurricane Beryl in the first half of next year.
I’ll now turn to our capital investment targets for 2025 and beyond. For 2025, we are targeting to invest $4.9 billion across various jurisdictions for the benefit of our customers and communities. Looking to the remaining five years of our original 10 year capital investment plan that runs through 2030, we are now targeting to deploy approximately $26 billion of capital, of which $21 billion is anticipated to be in the state of Texas.
This brings our 10 year total capital investment plan up to $47 billion. This $47 billion is a $2.5 billion increase from our previously stated $44.5 billion. Our incremental investment is expected to all be deployed in our Houston Electric service territory and will be reflected in our upcoming system resiliency plan that we have committed to filing by January 31, 2025.
We anticipate these investments will enhance the customer experience, but we remain cognizant of the impact of our investments on customer bills. However, based on the total current average Houston Electric residential bill, we estimate that our investments, combined with the estimated impacts of the 2b securitized storms, should result in customer bill increases roughly in line with the forecasted long-term rate of inflation over the next 10 years.
As a reminder, our Houston Electric residential customer delivery charges were the same in 2014 as when we started 2024. This build trajectory is a result of our continued focus on efficiency and our O&M activities in addition to the consistent customer growth we’ve seen in the Houston area for the last three decades.
Finally, I want to touch on our balance sheet and how we’re thinking about funding our increased capital plan. As of the end of the third quarter, our calculated FFO to debt was 13.8% when adjusting for the storm costs on a pro forma basis, based on our calculation aligning with Moody’s methodology as shown here on slide 9. We’ve demonstrated our continued focus on preserving our balance sheet strength while executing our capital plans despite incremental storm cost pressures this year.
Our efforts included the acceleration of $250 million of common equity into this year and the issuance of equity credit from hybrid debt securities. We plan to maintain that same philosophy as we work to efficiently fund investments and preserve credit health, both in the near term and beyond as we continue to focus on our long-term target of maintaining a cushion of 100 to 150 basis points above our downgrade threshold.
We also have substantial cash inflows as part of our plan, starting in 2025. Looking over roughly the next 12 to 18 months, we anticipate approximately $3 billion of gross cash proceeds from the divestiture of Louisiana and Mississippi Gas LDCs and storm related securitization issuances. And with regard to those anticipated securitization issuances, as a reminder, the state of Texas has seen 11 utility securitization transactions since 2008.
So there’s a strong history under this existing construct underpinning our conviction. We expect these combined proceeds will be a part of our strengthening story as we execute on additional customer driven investments.
As we look to the long-term financing plans through 2030, I also want to provide an update today on our equity guidance. With respect to the incremental $2.5 billion of resiliency investments, we expect to follow our previously provided guidance of funding incremental investments with 50% equity and 50% debt.
As such, you should expect that we will raise an incremental $1.25 billion of equity in addition to the $1.25 billion issuance through 2030 we previously guided to. This takes the total equity plan guidance to approximately $2.5 billion through the remainder of the decade.
You should expect that the equity issuances associated with these incremental expenses will likely come towards the latter part of our remaining five year plan. In the near term, and as I mentioned previously, the approximately $3 billion of cash inflows should allow us flexibility and mitigate the need for common equity in 2025.
Although we do not foresee the need for common equity issuances through 2025, we plan to continue to be opportunistic in strengthening the balance sheet through credit enhancing instruments like those we issued earlier this year. We will, of course, focus on the most efficient ways to raise that equity, be it through common equity issuances, incremental equity content such as hybrids or recycling proceeds.
As we look across the states that we are fortunate to serve, we remain confident in the continuation of our long term plan with a consistent focus on improving customer outcomes, delivering affordable service and building towards the most resilient coastal grid in the United States.
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 and legislators and our investors.

Jackie Richert

Thank you, Jason. Operator, we’re now ready to turn to Q&A.

Operator

(Operator instructions)
Shar Pourreza, Guggenheim.

Shar Pourreza

Hey guys, good morning.

Jason Wells

Hey, good morning, Shar.

Shar Pourreza

Morning, Jason. So just on ’24, looks like it’s in good shape. As we’re sort of thinking about ’25 guidance, there’s like kind of a lot of moving pieces there, including sort of the GRC withdrawal requests, tracker filings, potentially maybe higher O&M.
I guess, where is the level of confidence here? And what happens if the GRC withdrawal request isn’t approved, which I guess we’ll know in a couple of weeks? There’s just a lot of moving pieces and some key events. It would be great to maybe if you can bridge it a little bit further for us. Thanks.

Jason Wells

Thanks, Shar, for the question. Obviously, we have a high degree of confidence in terms of initiating ’25 here. There are a few points that I want to highlight that support that confidence.
The first is we’ve invested significantly for our customers over the last two years and have a rate base CAGR over the last two years of about 11%. That creates a solid foundation for the 8% guide on earnings growth.
Second thing that I’d probably highlight is, as you know, we will have new base rates in three of our jurisdictions in ’25, Texas Gas, Indiana Electric and Minnesota Gas. I think what’s notable about Minnesota Gas is, as you recall over the past, we have filed rate cases every other year in Minnesota, and that profile created a dynamic where in every odd year, we had zero increase in revenues in Minnesota.
When we filed the multiyear rate case last year, we filed with a request to increase revenues here in ’25. And so that smooths the profile for both earnings, but also for rate increases for our customers. And so I think that’s a pretty notable change.
And then third, you touched on this. We believe we have access to all the recovery mechanisms for our capital spend with the exception of Ohio where we will be in the middle of that rate case.
And so I think those are the drivers that give us confidence for the ’25 earnings guidance. You mentioned the withdrawal of the Texas rate case. And as you recall, we had filed a modest revenue increase in that case about $60 million.
And what we have historically said is that we expected that to be a rate case that resolve itself with flat, potentially maybe a small decrease in revenues. And so I don’t think the timing of the Houston Electric rate case is a real driver for ’25, given those other factors I mentioned.

Shar Pourreza

Okay. That’s perfect. Thanks. And then just lastly, on equity, obviously, it’s increased by another $1.25 billion to $2.5 billion through 2030. I mean, obviously, you talked a little bit about the shape of that equity being more back end loaded. But can you prefund the needs? Is there an opportunity there to remove the overhang? And are asset sales still an opportunity with the LDCs or capital markets aren’t there for that? Thanks.

Jason Wells

Yes, thanks again for the question, Shar. What I would say is we’ve established, I think, a pretty strong track record of efficiently raising the equity that we need with a series of transactions in the past. You can count on us doing the same here. We will efficiently fund this equity. I don’t necessarily think it comes in the form of prefunding, but we will look at the most optimal way to finance these needs.
And as Chris mentioned, I think we’re in a pretty strong position with having $3 billion of cash inflows over, call it, the next 12 to 18 months. That really gives us quite a bit of flexibility here as we think about the best possible way to efficiently raise the equity.

Shar Pourreza

Okay. That is perfect. Thanks guys. Appreciate it. See you in a couple weeks.

Jason Wells

Yes, thanks.

Operator

Steve Fleishman, Wolfe Research.

Steve Fleishman

Yeah, hi, good morning. Yes. So first, just the detail on the Texas low growth and the 30% growth in peak through 2030. Is that kind of include all the updates that you owe to, I think, (inaudible) for early next year for kind of low growth plans? Is that the kind of range that we should be expecting?

Jason Wells

No. There’s the potential for incremental load growth in that update with (inaudible) . That process with (inaudible) is really trying to capture kind of all speculative load in the 30% figure that I highlighted was a subset of that speculative load where we have a much higher degree of confidence.
And so as we look at and work with a number of companies in this region, as an example, hydrogen related activity could be multiples of what’s included in that number as one example. So we will be working to categorize kind of all of what I’ll call, speculative load activity, and then providing various degrees of confidence for each of those categories. And I think the headline number should be higher, but we feel a high degree of confidence in at least 30% through 2030.

Steve Fleishman

Okay. And then just maybe you could just give us an update on, maybe a little more color on where things stand with the rating agencies and what they’re keying off of from here? Is it just the metrics? Or is there other things that they are watching and care about? Thanks.

Christopher Foster

Sure, Steve. Good morning. I think it’s really both pieces. To start with the numbers, you saw us come out this morning with, we’re consistently measuring as Moody’s in a 13% downgrade threshold there. We came out with the adjusted number today of 13.8%. We’re confident that as we continue to go forward, what we’re really going to see change there over the next year is the combination of the Louisiana, Mississippi Gas LDC proceeds as well as the securitization related proceeds.
So it’s certainly the case the rating agencies are watching closely, those securitization filings as well with the ultimate goal of really just seeing the really strong Texas Regulatory construct work, right? That’s why you saw us today really highlight two things.
First, again, the securitization process with a long history here in Texas of approvals of 11 different securitizations. And the second is the opportunity without the rate case in front of us to pursue the traditional capital trackers, which we do intend to do.

Steve Fleishman

Okay, great. Thanks, appreciate it.

Jason Wells

Thanks, Steve.

Operator

Durgesh Chopra, Evercore.

Durgesh Chopra

Hey, good morning team. Thanks for giving me time. Hey, Chris, just to kind of follow up on the credit metrics discussion. Maybe just, can you help us maybe a little bit more detail on the timing of the securitization proceeds in 2025?
And then just directionally speaking, where do you on a Moody’s basis, where are you expecting 2024 metrics to be and then 2025? I’m thinking if they dip towards the end of the year and then pick back up in 2025 as you receive those proceeds, but just more color there. Thank you, Chris.

Christopher Foster

Sure, Durgesh. Happy to do it. Let me just remind everybody, again, the highest order of the focus of the company for the long term is the focus on a cushion of 100 to 150 basis points as we go. But let me unpack the securitization pieces for you in particular.
First, you should assume that we filed two different securitization requests. The first will be for the associated May storm (inaudible) storm costs. We’ll file that soon. But as a result, I think you should generally assume a roughly Q3 resolution and associated proceeds of 2025.
Second, we’ll file the Hurricane Beryl related costs. We’re generally targeting roughly Q2 of next year once we get all those costs in to file for those Beryl associated requests. Cumulatively, what we did this morning is we updated towards the low end of the cost themselves.
Previously, our guide was $1.6 billion to $1.8 billion. We updated today, given the greater certainty we have now at $1.6 billion. So ultimately, Durgesh, I’d say the first piece, roughly Q3 ’25, second component of Hurricane Beryl related costs, either late Q4 or early Q1 2026.

Durgesh Chopra

Thanks Chris. And then just, so I guess, by the end of next year, are you sort of in that 14 to 15, I mean you’re very close to it as of the end of 3Q. I’m just thinking about CapEx picking up next year and new securitization proceeds. Where do you shake out in that 14 to 15? Are you going to be solidly in that range next year? Or is that more of a ’26 event?

Christopher Foster

Yes. I think it’s ultimately, once we get the securitization proceeds, and Durgesh, we’ll be stepping back into that substantial cushion, right? So you’d ultimately probably be looking at Q1 ’26, once we’ve got all that done.
Keep in mind that we’ve also emphasized this morning, the consistent focus we’ve got on the balance sheet. You saw us pull forward even the 2025 equity being front footed at that point. So you’re just going to consistently see the focus here from the team.

Durgesh Chopra

Understood. Really appreciate the detailed color. Thank you.

Operator

Jeremy Tonet, JPMorgan Securities.

Jeremy Tonet

Hi, good morning.

Jason Wells

Good morning, Jeremy.

Jeremy Tonet

Just want to start off, I guess, looking at the state as a whole, how things stand in Texas. How have stakeholder conversations trended there since completing your GHRI Phase I work versus the initial aftermath of the storm?

Jason Wells

Thanks, Jeremy, for the question. I think things continue to improve. I mean we’ve conducted obviously extensive outreach, elected officials, customers, our communities, community leaders. And what we’ve heard, it consistently is that everybody wants a more resilient system.
We want to improve communications. I think they saw improved communications as we prepare for Francine. And I think they have appreciated the progress that we made in August and that we’re carrying forward with the resiliency investments in the second phase of GHRI.
As I highlighted on the call, I think the area where we can make a single biggest sort of improvement in a short period of time is on this concept of segmentation and automation and the plan that we’ve got here in the second phase when it’s all implemented. We’ll save our customers about $125 million outage minutes annually and I think that’s the direction that our stakeholders want to see us go ahead.
And so obviously, there’s more to be done. It is a focus of ours to continue to re-earn trust. We know that we’ve got to continue to lean into those conversations, both with elected officials as well as our communities. But I think we’re heading in a direction that everybody wants. That’s again, a more resilient, reliable grid and much better communication.

Jeremy Tonet

Got it. That’s helpful there. Thanks. And just moving to 2024 guide real quick here. Despite the $0.11 O&M drag this quarter, reaffirming 2024 whole. This suggests, I guess, a lot of offsets in 4Q. Just wondering if you could walk us through that a bit more, what is contemplated there as far as the offsets? And then I guess, how does this position for 2025?

Christopher Foster

Sure, good morning. I think there’s a few pieces to keep in mind there, which informally the confidence in maintaining our guidance. I think the first piece, again, is just the consistency of the trackers that we’ve got. The last couple of quarters there have seen a benefit of roughly $0.09 to $0.10 quarter-over-quarter related to those trackers specifically. And so we’re going to expect that trend to continue really across our jurisdictions relative to the fourth quarter of last year.
The second piece, and I hit this one in my prepared remarks, specifically, but again, just to reiterate, we did a lot of incremental work on the system in Q3, certainly highlighting the critical vegetation management work during the spring we undertook during August of this year. And a lot of that work was incremental to the year. But keep in mind, some of it was an acceleration for Q4. So I’d expect that to result in about a $0.01 benefit to Q4 as well.
And on top of that, recall last year that we pulled forward work into the fourth quarter. And so that work was about $0.03 from 2024 to 2023. And so that again should benefit us here as we look at Q4 2024 when we do the quarter-over-quarter look. All in all, confident here for the year.

Jeremy Tonet

Okay, great, helpful. Thank you.

Jason Wells

Thanks, Jeremy.

Operator

David Arcaro, Morgan Stanley.

David Arcaro

Hey, thank you. Good morning. Wondering if you could give an update on kind of where you stand with the proposal that you put forth regarding the temporary gen recovery or what the next move is with that proposal?

Jason Wells

Yeah, just as a quick reminder. I think the real focus of the state’s attention on the temporary generation portfolio, it’s really on the large units. And when we look at the amount of investment in those large units, there’s a little less than $100 million of profit or equity earnings has not yet been recognized on those units.
And the proposal that we made in August was basically to forgo the equivalent, a little bit more than the equivalent of that remaining profit. We put forward a proposal where we would forego about $110 million of profit.
Clearly, I think stakeholders saw that as a good step forward. I think there’s still discussion around the use of these units. And as we’ve indicated on many occasions, we are working with everybody in the state to find solution that works, a solution that works for our customers in times of load shed. We still have an obligation to rotate our once every 12 hours in a load shed event.
And given our industrial load profile, critical facilities like the Texas Medical Center. We believe that we need those large units to comply with that order. But if the state wants us to, they want to change that requirement or want us to look at these units differently, we’re happy to work with the state in that regard. And so there’s no prescribed timing. We attempt to address the concerns on the profit, the remaining profit on the large units and we’ll work with the state to find a final resolution.

David Arcaro

Okay. Got it. Appreciate the update there. And then maybe on the transmission outlook in the state, there are a couple of big programs out there. We’ve got the Permian plan, potential for 765 KV investments. Wondering if you could talk about how you could be involved there? When might we see some of the potential projects or upside opportunities start to crystallize for your plan? .

Jason Wells

I think more directly the opportunities around the 765 KV project, there are a couple of our substations that would tie into that project. And as you know, the standard here in Texas is right of first refusal for the lines that connect into our substations. And so we see the opportunity for significant investment in the 765 KV lines that are outside or not incorporated in the $47 billion CapEx plan that we’ve highlighted here. So that’s potential upside.
I think there’s less potential upside with the Permian Basin directly. That’s really focused kind of outside of our service territory. What I would say indirectly, though, and back to my response earlier, (inaudible) will update the speculative load study in early ’25.
At that point, they will incorporate an estimate of speculative load in the Greater Eastern region. Given the explosive growth that we talked about, I have to believe that there are going to be more transmission lines that are needed to serve that increasing load as a reminder.
On any given day, we’re importing about 60% of electricity needed to serve our customers. And as that electricity demand grows, there will be more need for incremental transmission lines and substations. And so we see electric transmission as being sort of a long term tailwind for our CapEx plan. And I’d like to really start to kind of see that come into greater focus probably in ’25 around this speculative load update.

David Arcaro

Okay, great. That’s helpful. Thanks so much.

Jackie Richert

Operator. I think we have time for one more if there’s another in the queue.

Operator

Julian Dumoulin-Smith, Jefferies.

Julian Dumoulin-Smith

Hey, good morning team. Thank you guys very much. It’s nice to chat with you guys again. If I can follow up on a few different things, just a little bit pick here from the call thus far. With respect to mobile generation, I mean, just to understand the contract terms and the permutations here.
How do you think about any strategic avenues here to the extent to which it ultimately the state, whether the legislative session or otherwise ultimately effectively pushes you into a decision to effectively divest, if you will in the broadest terms? How do you think about what is possible within the construct that you have here? Especially for a state that’s short.

Jason Wells

I think that’s the key to it, your last comment, right? There’s been very little net generate, dispatchable generation build. Clearly, there’s been a lot of generation build when we think about intermittent renewables. But on a net basis, in terms of new build less retirements, the state has really seen very little in the way of dispatchable build.
And so I think the focus for the state is really trying to, in particular, these days, find a path for the winter peak. We saw that benefit of the battery storage deployment here this past summer. I think those battery storage investments are really helping kind of the summer peak where we’re talking about hours. They’re not necessarily as helpful in the winter peak where we’re potentially short for days.
And so I think what we’re looking for is a solution that could help address dispatchable needs here in the state. That could mean subleasing our equipment to others, so that it doesn’t leave the state but is an available resource at the same level. Otherwise, obviously, we will work with our elected officials if they have a different point of view.
And so I don’t think there’s a definitive path forward, but I think everybody is trying to find a solution that protects customers in the event of load shed, but also does so sort of optimally from a cost standpoint and we’re happy to find that balance with everyone.

Julian Dumoulin-Smith

Excellent. And just a quick [nitpick] on the last response. Just a transmission update from (inaudible) here. Obviously, (inaudible) released their own load forecast here recently. You talked about this 8 gigawatt number on the call momentarily ago. How does that inbound, again, I get this is a fluid situation, reconciled against (inaudible) demand?
And effectively, are you suggesting as a further sort of net uptick in (inaudible) demand and, or that updated load forecast that came up with doesn’t necessarily yet reflect their transmission expectations? I’m just trying to understand, I think you’re suggesting that there’s an uptick in both the demand as well as their transmission planning to reflect the 8 gigawatts that you just alluded to on data center specifically potentially?

Jason Wells

Yes, Julian, I think that’s the short of it. It’s an uptick both on demand and transmission. The updated numbers still don’t reflect the potential development here in the Greater Eastern region. That update, as I mentioned, really is coming kind of in early ’25. What we have seen this summer is like a fundamental shift in data center activity, up until early summer, we had about a gigawatt of demand in the queue, and now it’s over 8 gigawatts as of the time of this call.
And I think that really reflects the fact that as we talk to developers and hyperscalers, latency becomes less of an issue as it move more development to AI-driven data centers. Texas remains very attractive in terms of being able to build new transmission lines, new generation.
Our interconnection timelines compare very favorably in a state that can move quickly with large infrastructure investments. And so I think that’s why we’ve seen it dramatically change this summer. All of that, to your point will get incorporated into (inaudible) low forecast early next year.
And just given the point that I’ve recently highlighted, we continue to highlight that 60% of our electricity is important on any given day, that’s likely going to mean more transmission here for the Greater Eastern region.

Julian Dumoulin-Smith

Right. So even accelerating in the last quarter despite (inaudible) update even the last couple of months here, it seems like there’s an upward bias there. Thank you for the time and clarifying that.

Jason Wells

Thanks, Julian.

Jackie Richert

Thanks Julian. And with that operator, I think that will conclude our Q&A for the day. Thanks everyone for participating in this quarterly call.

Operator

This concludes Centerpoint Energy third-quarter 2024 earnings conference call. Thank you for your participation. You may now disconnect.