Operator: Good morning and welcome to CenterPoint Energy’s Fourth Quarter and Full Year 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. Richert?

Jackie Richert: Good morning and welcome to CenterPoint’s fourth quarter 2024 earnings conference call. Jason Wells, our CEO, and Chris Foster, our CFO will discuss the company’s fourth quarter and full year 2024 results. Management will discuss certain topics that will 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 in our Form 10-K, other SEC filings and our earnings materials. We undertake no obligation to revise or update publicly any forward-looking statements.

We reported $1.58 and $0.38 for the full year and fourth quarter of 2024 respectively, 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 our 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. I would like to begin by extending my sincere appreciation to all of our frontline personnel that work through the unprecedented winter weather we experienced across our various service territories. We experienced sub-zero temperatures in Minnesota, freezing rain in Indiana and record-breaking snowfall in the Houston area. Through it all, our team worked to keep the lights on and the gas flowing for our customers. On today’s call, I’d like to address four key areas of focus. First, I’ll touch on the fourth quarter and full year 2024 financial results. Second, I’ll provide a broader regulatory update, including highlights of our recently filed system resiliency plan for Houston Electric and touch on the significant progress we’ve made in our various rate cases.

Third, I’ll share an overview of the transaction we have proposed to ERCOT that we believe benefits all stakeholders. And lastly, I want to highlight the impressive growth drivers across the Houston area and how that growth informed the substantiated load filing we recently submitted to ERCOT. Now starting with our fourth quarter and full year financial results. This morning, we announced non-GAAP EPS of $0.40 for the fourth quarter and $1.62 for the full year. Chris will provide additional details of these strong results in his section. The $1.62 per share translates to 8% growth over our 2023 actual results. This is now the fourth consecutive year of meeting or exceeding our annual non-GAAP EPS guidance. It is also important to note that we have rebased our long-term growth targets off these higher earnings levels each year as we seek to deliver value for our investors each and every year.

Consistent with this approach, 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 6% to 8% range annually through 2030. We also expect to grow dividends per share in line with earnings growth over the same period of time. Now turning to my second key area, and update on our broader regulatory efforts, starting with our recently refiled system resiliency plan at Houston Electric. In line with our commitments, we refiled our system resiliency plan at the end of January. This filing proposes a total spend of $5.75 billion from 2026 through 2028 to improve system resiliency.

$5.5 billion of this spend is related to capital expenditures. Chris will discuss the associated capital expenditure increase from our previous plan in his section, but I want to briefly touch on the system improvements we are focused on in this filing. Our plan outlines 39 specific resiliency measures that are designed to strengthen tens of thousands of miles of our transmission and distribution system. The investments included in our filing represent the largest single investment in grid resiliency in our company’s history, as we work to improve the customer experience for those that live and work in higher-risk areas. As a result of our planned work through 2028, we expect that our transmission system will be fully hardened with no remaining wood structures and that nearly all substations will be elevated above the 500-year floodplain.

I am proud to say that with our accelerated pace in less than a year since Hurricane Beryl, we will have more than doubled the number of circuits that have automation on our system, and we won’t stop there. With our system resiliency plan in another three years, we will triple the number of automated devices since Hurricane Beryl. We estimate that our actions over the next several years will save customers more than one billion outage minutes in extreme weather events. In addition to contributing to an improved customer experience, beginning in 2029, these investments are anticipated to result in an estimated $50 million of reduced storm-related costs per year which naturally support lower electric delivery charges over the long term. As I’ve mentioned before, this is not the beginning of our journey to a more resilient system but an acceleration of what we started a few years ago when we targeted hardening and modernizing the electric transmission backbone as well as some of our substations prone to flood risk.

We believe that these investments, combined with the other actions outlined in our Greater Houston resiliency initiative, set us on a clear path to become the most resilient coastal grid in the country. Next, I want to focus on the continued regulatory progress at Houston Electric. As many of you recently saw, we reached a settlement in our 2024 rate case. We believe that the proposed settlement is constructive for both our customers and our investors. The proposed settlement, if approved, includes an annual revenue requirement decrease of $47 million, which translates to a reduction of approximately $1 per month in the average electric delivery charge for our residential customers. It also includes an increase to both our return on equity and equity ratio.

These improvements strengthen our competitiveness in the capital markets that we regularly access to efficiently fund capital investments for the benefit of our customers. This unique outcome of lower customer bills with improvements of both the cost of capital and capital structure comes despite the fact that we’ve increased our vegetation management spend by 45% over the last few years. It also exemplifies our ability to improve customer outcomes while also efficiently executing O&M reductions throughout the business. We’d like to thank all of our stakeholders for working together to submit to the PUCT what we believe is a constructive settlement for all parties. Beyond the rate case, we’ve also made progress on our traditional interim mechanisms and storm cost recovery filings at Houston Electric.

Chris will provide further details regarding these items in his section. Now turning to Indiana Electric. A few weeks ago, we received a final order in our Indiana Electric rate case. The final order was approved in line with the settlement filed in May of last year, which included a total annual revenue requirement increase of approximately $80 million and a 9.8% return on equity. We believe this is a fair and balanced outcome as we have continued to invest for the benefit of our customers, while also being conscious of the impact of our capital investments on the customer bill. Our move away from older generation facilities has enabled us to eliminate nearly $40 million of O&M directly benefiting our customer bills. We also previously securitized the remaining book value of one of our aging facilities forgoing profits related to this plant for the benefit of our customers.

Moving forward, we will continue to be mindful of our customer bills and the reliability needs and work with stakeholders to achieve balanced outcomes for all parties. Moving to our Minnesota Gas rate case. During the fourth quarter, we reached an all-party settlement in our Minnesota Gas rate case. The settlement includes a total revenue requirement increase of nearly $104 million for 2024 and 2025, which reflects over 75% of our proposed revenue increase of approximately $136 million. Interim rates for the 2024 increase went into effect in January of last year, and interim rates for 2025 went into effect last month. These rates closely mirror the increased revenue requirement included in the proposed settlement that is now pending a final order for the Minnesota Public Utilities Commission.

The commission has a statutory deadline of July 1 to issue its final order in this case. We also want to thank all stakeholders for working together to achieve what we believe is a strong outcome for all parties. Finally, I want to briefly touch on our rate case for Ohio Gas. At the end of October, we filed our Ohio gas rate case application, which included a revenue requirement increase of $99.5 million. Over the last several years, we’ve had one of the lowest customer bills in the state. Our request reflects an investment recovery rate that will put us more in line with our Ohio peers. In addition, this larger revenue requirement increased will allow us to more efficiently fund and continue to prioritize pipeline modernization investments that we believe contribute to the overall safety and efficiency of the system.

Before closing out my remarks on our regulatory progress, I want to put into context what has been a very busy and constructive regulatory cycle. Over the last 18 months, our teams have been busy as they have filed five rate cases. Of the five, we have received final orders in two and are awaiting approval of settlements for our Houston Electric and Minnesota Gas businesses. Together, these four rate cases represent over 80% of our enterprise rate base. Should these cases be improved in line with their current proposed settlements, we will have been able to improve our consolidated return on equity and equity ratio, which naturally increases the earnings power of the company. I want to thank all of our teams for their hard work and dedication for working with stakeholders to achieve such strong outcomes for both our customers and our investors.

Now I’d like to provide an update on our proposed temporary generation transaction. Through engagement with a diverse set of stakeholders, it is clear that there is no longer a desire for transmission and distribution utilities in the state to invest in large temporary generation facilities to mitigate the impact of large load shed events. In response to this, we have worked with the same set of stakeholders to develop what we believe is a truly unique Texas solution that benefits Houston Electric customers, other ERCOT customers and CenterPoint investors. I will briefly walk through the contours of this transaction, and Chris will provide additional details related to the financial impacts. Our proposal to transfer the use of our units to a Texas Pier utility will provide a temporary bridging solution for summer peak reliability needs in the San Antonio area.

We will make these units available for this purpose for up to two years, starting this spring. After that, we intend to market the 15 large units to third parties at what we expect to be prevailing higher market rates. Given current market demand, we believe that the revenues earned from marketing these units after the period that they are in San Antonio will exceed the foregone revenues during the period these units are donated to ERCOT at no cost. We truly believe this Texas solution is a win for all stakeholders. As part of this solution, we will make an unprecedented contribution of value for the benefit of the ERCOT grid. Houston Electric customers will be made whole on charges related to the large temporary units. And finally, our shareholders will receive the benefit of their investment when we take into consideration the anticipated profit from marketing after the period these units operate in the San Antonio area.

We appreciate all stakeholders for providing their feedback and working collaboratively to identify this unique solution that ultimately benefits everyone. Now switching gears. I want to highlight the strong organic growth we continue to see, especially in our Texas service territories. While my earlier commentary focused on capital investments related to resiliency enhancements on our system, I want to emphasize that we continue to experience significant electric demand growth across Texas and particularly the Greater Houston area. We are proud to partner with both existing and potential new customers to support their energy needs as our region continues to experience rapid economic development. It is these discussions that have informed our estimated electric load forecast for the Houston region that we recently submitted to ERCOT.

I want to briefly touch on what we included in our submission and equally important, what we excluded. Last year’s ERCOT load report was largely focused on Texas electric needs outside of the Greater Houston region. We are excited to have now submitted our expected load increase for the greater Houston region this year. Like our peers, we’ve experienced an unprecedented level of interest in connecting to our grid. In fact, we have received approximately 40 gigawatts in load interconnection requests. Those load requests are incremental to our current peak of about 21 gigawatts. While we’re actively pursuing this full set of load interconnection requests, we believe our submission is a more realistic reflection of the load growth that will materialize by 2031.

Currently, we are forecasting a nearly 50% increase in peak demand from 21 gigawatts today to nearly 31 gigawatts by the end of 2031. To put that in perspective, the 10 gigawatt increase we are forecasting over the next seven years is more than the increase that Greater Houston region has experienced over the last 25 years. Our rigorous approach to forecasting load demand gives us confidence in our projections. Our outlook also benefits from the fact this growth is not driven by a single industry or theme. Houston has clearly earned its reputation as the energy capital of the world, but our types of economic expansion go well beyond this core sector. It may come as a surprise to some that today, energy constitutes only a little more than one third of the area’s economy.

When looking at Houston’s low drivers, we see three economic activities as the catalyst for significant long-term load growth. First, Houston is a major logistics hub for the United States. Boasting the largest port by waterborne tonnage, Houston is a gateway for goods coming from and going all over the world. We forecasted opportunities for port electrification, fleet electrification and other associated projects will drive approximately 20% of the 10 gigawatt increase through 2031. Second, Houston is home to the largest medical complex in the world, and it is only growing. It continues to expand not only its offerings for patients who come from all over the globe for treatment, but continues to pioneer medical innovation and medical manufacturing.

We forecasted its continued expansion as well as other commercial activities, including data centers, will drive 30% of our anticipated load growth by 2031. Third, Houston is and will continue to be at the center for energy refining and energy exports. As the global energy mix continues to evolve, Houston will play a central role in the development and exportation of that energy. This significant growth will certainly require continued and increased investments in electric infrastructure, especially with respect to the transmission system. As a reminder, Houston makes up just over 2% of the geographic area of Texas, but is approximately a quarter of ERCOT’s peak load. On any given day, we import as much as 60% of the electricity consumed in the Houston area.

Prior to formalizing our capital investment plans related to this immense growth, we need the feedback and final decisions from the Texas Public Utility Commission regarding the 765 kV or 345 kV standard for transmission build-outs. We anticipate further clarity on this topic by May of this year. Regardless of the direction the PUCT takes, the continued growth of the Houston area is undoubtedly a long-term tailwind and is one that is truly unique to CenterPoint. The diverse underlying fundamentals driving Houston growth gives us continued confidence in our belief that we have one of the most tangible long-term growth plans in the industry. This growth will continue to drive investment opportunities for years to come. but also provide a sustainable platform for our customers whose charges will continue to benefit from the ever-growing population.

We are privileged to serve such a growing and vibrant area and look forward to continuing to partner with customers, communities and other stakeholders to further enable this truly remarkable growth. And with that, I’ll hand it over to Chris.

Chris Foster: Thanks, Jason. Before I get into my updates, I want to echo Jason’s gratitude for not only our CenterPoint coworkers, but also the external frontline crews who aided in the restoration in Indiana and kept energy flowing for our customers throughout our various service territories. This morning, I will plan to cover four areas of focus: first, the details of our fourth quarter and full year financial results; second, I’ll touch on our capital deployment execution for the year as well as our upwardly revised capital plan that now reflects our recently filed system resiliency plan and an update on our other capital investment trackers. Third, I’ll go into further detail on our temporary generation proposal and the associated financial impacts; and finally, I’ll provide an update on where we completed the year with respect to our balance sheet.

Let’s now move to the financial results shown on Slide 8. On a GAAP EPS basis, we reported $0.38 for the fourth quarter of 2024. On a non-GAAP basis, we reported $0.40 for the fourth quarter of 2024 compared to $0.32 in the fourth quarter of 2023. Our non-GAAP EPS results for the fourth quarter remove the impacts associated with the sale of Louisiana and Mississippi Gas LDCs. In the fourth quarter, these impacts included an $8 million deferred tax remeasurement reflecting a slightly lower effective state income tax rate post sale. Now taking a closer look at the quarter, growth in rate recovery contributed $0.05 when compared to the same quarter last year, which was driven by the ongoing recovery from interim mechanisms for which customer rates were updated in addition to approved interim rates related to our Minnesota Gas rate case.

In addition, O&M contributed $0.05 of favorability when compared to the comparable quarter of 2023. This favorability was primarily driven by the approximately $0.03 of work that was pulled forward in Q4 of last year that we did not replicate this quarter. In addition to O&M and rate recovery, weather and usage contributed an additional $0.02 favorability quarter-over-quarter. Interest expense and financing costs were $0.03 unfavorable when compared to the comparable quarter in 2023. These $0.03 were primarily driven by the $3 billion of net new debt issuances quarter-over-quarter. And despite the headwinds we faced this year, we were still able to deliver for our investors our full year 2024 and non-GAAP EPS target of $1.62. I want to take a step back to discuss how we’re thinking about O&M.

Over the last few years, we’ve been able to reduce our O&M by nearly 2% annually. We are now committed to continuing to do more vegetation management work at Houston Electric, where we are now proposing to transition from our current five-year vegetation management cycle to a three-year cycle. This positions us well given the long seasonal growth periods and has us leading statewide in Texas and among the few in our industry that seek this level of proactive vegetation management. This more aggressive cadence will naturally reset our O&M levels in the near term. However, we will be laser-focused on continuing to take costs out of the business elsewhere and continuing to target 1% to 2% O&M reductions from these higher levels, ultimately benefiting customer charges.

For example, as Jason pointed out earlier, starting in 2029, we anticipate saving roughly $50 million of storm costs annually from the investments outlined in our recently filed system resiliency plan. This overall level of execution gives us confidence in reiterating today our full year 2025 non-GAAP EPS guidance target range of $1.74 to $1.76. The midpoint of this range represents annual growth of 8% from our actual 2024 non-GAAP EPS of $1.62 as we seek to deliver value for our shareholders each and every year. Next, I’ll touch on our capital investment execution for 2024, as shown here on Slide 9. In the fourth quarter of 2024, we invested $1.2 billion of base work for the benefit of our customers and communities. For the full year, we invested $3.8 billion, exceeding our 2024 capital expenditure target of $3.7 billion, and this is despite multiple diversions from performing base work due to storm restoration.

As Jason touched on, our recently filed system resiliency plan includes capital investments of $5.5 billion. This updated plan results in a $500 million increase to the $47 billion capital investment plan that runs through 2030. As such, we are updating our capital investment target to $47.5 billion through the end of the decade, and we will fund our incremental capital investments consistent with our prior guidance. As such, you should assume we will fund in line with the enterprises approximate consolidated capital structure of 50% equity and 50% debt. Separately, we are back now in our more traditional rhythm of seeking ongoing capital plan recoveries using existing mechanisms. At the same time, we continue to make progress on storm recoveries.

Related to those recoveries, we are focused on progressing through the securitization process here in Texas and are currently ahead of plan. That is because we have now reached a settlement in principle on our major ratio event cost. As part of the proposed settlement, we will recover 98% of the cost attributable to the storm. This is a great outcome and one that further illustrates the constructive business and regulatory environment in which we operate here in Texas. We’re also still on track to make our cost recovery filing related to Hurricane Beryl in the second quarter. In addition, we continue to advance on our capital recovery mechanisms at Houston Electric. During the fourth quarter, we filed both our transmission and distribution trackers.

In our transmission tracker or TCOS, we requested a revenue increase of approximately $63 million, which was approved and rates were updated to reflect this increase in mid-January. Our distribution tracker or DCRF, was filed at the beginning of December and reflected a requested revenue increase of approximately $100 million. We recently withdrew this filing because we’re updating it with the revised figures to reflect the capital investments included in the rate case filing. We will also incorporate incremental capital investments through the end of December 2024 in our revised filing that we anticipate filing by the end of the first quarter. I’d now like to discuss the expected financial impacts for customers and investors associated with our temporary generation transaction that Jason referenced.

First, I want to take a step back and walk through how we’re thinking about our investment relating to the lease of our large temporary emergency generation units. There are essentially three periods, with the lease running through June of 2029. First, the period where the units were available to our CenterPoint customers to mitigate potential large load shed events. Second, the period the units will serve our fellow Texans. And third, the period where we will seek to market all 15 large temporary generation units to third parties at prevailing market rates. When crafting our proposal, our focus, first and foremost, was on our customers. We intend to be responsive to stakeholders that have expressed a desire for us to offset collections from regulatory recoveries of roughly $475 million.

That’s approximately the amount we’d seek to offset for our customers. Let me summarize how we would go about doing that. There are three components of customer benefit at a high level. First, in the spring of this year, we are proposing to make all of our 15 large temporary emergency generation units available to serve the San Antonio area to support reliability needs identified by ERCOT ahead of the summer load peak. We will make an unprecedented contribution for the benefit of Texans of approximately $180 million of value for an up to two-year period. That’s the time in which we would propose the large temporary generation unit will serve ERCOT customers, resulting in us not seeking future recovery of this balance for Houston Electric customers as they will cease to be a regulated investment.

Second, our Houston Electric customers will receive the benefit of the Houston Electric rate case settlement. When approved, saving customers around $250 million over a roughly five-year period. And third, as we highlighted in the third quarter, we performed significant incremental work related to both the May storms and Hurricane Beryl recovery, and we will not seek recovery for roughly $110 million of these costs. We anticipate that during the time the units are serving as a statewide system benefit, cash flow will be slightly lower as collections from customers will be reduced to account for the foregone recovery related to the future use of these units. At the end of that time, the third period will begin, where we seek to market all 15 large temporary generation units to third parties at prevailing market rates.

The market has and continues to move favorably for mobile power units such as these, where we have seen market rates that are roughly double our original lease rate. As I briefly touched on, once these units move to the San Antonio area, we will not earn a regulated return with respect to our investment in them. Given the unregulated nature of this investment going forward, we will remove the impacts, both favorable and unfavorable from our non-GAAP earnings numbers. Although we project the earnings and cash flow profile, have the potential to equal or better the prior regulated investment profile. This is now largely a timing item. And the asymmetric earnings profile of this investment is not consistent with our core regulated business. I will reiterate Jason’s sentiments with respect to this Texas-centric solution.

We believe this transaction is a tremendous outcome for all stakeholders. 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 year, our adjusted FFO-to-debt ratio based on the Moody’s rating methodology was 13.6% when removing storm-related costs. This is slightly below our target range of 14% to 15%. But as a reminder, it is transitory in nature as we anticipate receiving approximately $1 billion in cash proceeds next month from the closing of our Louisiana and Mississippi LDC sale. We also expect an additional $500 million of securitization proceeds by the end of June, and we continue to expect to file for securitization of the $1.1 billion of storm costs related to Hurricane Beryl within the next few months, with proceeds anticipated coming by the end of the year.

We will continue to stay laser-focused in supporting balance sheet health, while also investing for the benefit of our customers and communities. With now four consecutive years, meeting or exceeding expectations, we continue to reaffirm our non-GAAP EPS target of 8% this year and the mid- to high end of 6% to 8% thereafter through 2030. And with that, I’ll now turn the call back over to Jason.

Jason Wells: Thank you, Chris. In summary, I’m proud of our team for persevering through 2024, which marks our fourth year of meeting or exceeding our financial guidance. This performance places us in the top decile within our utility peer group. In addition, we have a strong foundation in place for 2025 and beyond, a foundation that includes a comprehensive plan to deliver the most resilient coastal grid for our customers. Incremental CapEx announced today of $500 million driving 10% rate base growth through the end of the decade, which is one of the highest in the sector, constructively settling four rate cases representing over 80% of enterprise rate base, giving us clear line of sight for the next four years. And the privilege to serve one of the fastest-growing regions in our country with an expected peak load increase of approximately 50% in the Houston area through 2031, powered by a diverse set of economic drivers.

This load growth undoubtedly provides incremental CapEx tailwinds to an already industry-leading plan. We look forward to sharing more comprehensive details about the long-term investment opportunities later this year.

Jackie Richert: Thank you, Jason. Operator, we’re now ready to take Q&A.

Operator: Thank you. At this time, we will begin taking questions. [Operator Instructions] Our first question comes from Steve Fleishman with Wolfe Research. Your line is open.

Steve Fleishman: Yes, hi, good morning. Thanks. Can you hear me?

Jason Wells: Yes.

Steve Fleishman: So just, I guess, you kind of talked to this at the end, Jason, but just on the growth forecast that you gave, is there any way to kind of compare what you gave to what you — to what ERCOT might have used last year for this? And then also, how to think about how much of this growth kind of in your capital plan or what’s still like upside, including the transmission decision that you mentioned coming up?

Jason Wells: Yes. Happy to shed a little color on that. As it relates to the ERCOT submission, as we’ve discussed over the course of last year, that was largely related to West Texas really a focus on the Permian originally. So last year, I think we submitted roughly — it had to be less than a gigawatt of interconnection demand. We basically had — we weren’t a participant in last year’s study effectively. So this will be the first time that the growth in the Houston area is really going to be reflected in our costs substantiated load filing moving forward. So it will be a 10 gigawatt increase to what they were projecting last year. We’ve also talked about, I would have to imagine that some of that load last year that was submitted, it was submitted under a standard that was designated as a speculative load.

ERCOT is trying to tighten the planning parameters and have moved to more of a substantiated load, essentially a higher level of confidence in that load materializing. And so there may be a little bit of downward pressure on the total ERCOT market. But undoubtedly, we will add about 10 gigawatts of new demand to what otherwise existed last year. So hopefully, that provides the context around the ERCOT emission. As it relates to CapEx, as I mentioned, this is an incredible tailwind for the company. It’s still a little early to size it. It really is going to come down to the decision on voltage, whether we pursue a 765 kV standard or 345 kV standard. What I would say though, because we are a load pocket here in Houston, in any given day, we’re importing 60% of our energy needs.

This will undoubtedly drive at least another $3 billion in electric transmission CapEx that’s not in the plan. I would really be surprised if it’s not higher than that. But ultimately, we need a policy direction on the voltage standard to refine that estimate. And so we’ll be providing more of an update as we get through the course of the year.

Steve Fleishman: Okay. That’s very helpful. And then on the — any update on kind of rating agency views? I know you gave the metrics just when — are they going to — are they mainly going to be focused on the recovery from Beryl to kind of see stabilizing of the ratings?

Chris Foster: Steve, I think it’s probably three factors. First is just the constructive nature of the Texas regulatory environment, which I think we’ve been able to already showcase our interim capital recovery mechanisms as a key area of progress there. Two, it’s the Houston Electric rate case, again, for the certainty that, that provides. I think that, as you’ve seen there, we have an all-party settlement and ideally, hoping for action there at the PUCT, either March 13 or 27 here would be ideal in their next public meetings. Third is certainly the securitizations of the prior storm costs. What I would point out there is we are actually ahead of plan and have been sharing that with the rating agencies, meaning the $500 million associated with the May storm impacts, we have now achieved a settlement in principle which puts us ahead of plan in terms of being able to execute towards the end of this quarter — excuse me, towards the end of the second quarter, the actual securitization.

Finally, I do think it’s going to be important for them to see progress. the prudency review step associated with the Hurricane Beryl-related costs, and we’ll get that filing filed at the PUCT here in the next few months. So ultimately, I think those are the three factors that they’re watching, and I think we’re already able to show progress on certainly two of the three, if not three of the three.

Steve Fleishman: Great, thanks. Very helpful.

Operator: Thank you. Our next question comes from Shahriar Pourreza with Guggenheim Partners. Your line is open.

Shahriar Pourreza: Hey guys, good morning. Just to follow up on Steve’s question. Jason, have you committed to an Analyst Day, any sense of timing there? And are you going to know enough around the 50% load growth upside that you guys kind of highlighted for Houston to embed that in the capital plan for the Analyst Day?

Jason Wells: Yes, it’s a great question, Shar. And yes, we are committed to update and rolling forward what will be a new 10-year plan for capital investment this year. We do want to make sure that we incorporate this policy decision or direction that Texas will make in terms of the voltage standard. We anticipate that by May this year. And so our update to the market will likely follow that so that we can incorporate a better estimate of the transmission CapEx increase associated with serving this really just tremendous load growth here. So we haven’t set a date, but we’re committed to providing an update to the market here this year. I would also say that while we’re talking a lot about the electric transmission opportunities here in Texas, which are significant, as I mentioned, they are not our only set of CapEx tailwinds.

We continue to see, I think, really constructive opportunities for our customers around some localized transmission here in the Greater Houston area on the gas side of the business, and we’re going to be pursuing some electric transmission opportunities up in Indiana. And so I think the tailwinds from a CapEx standpoint are significant, and we look forward to sharing them a little later this year when they come into better focus.

Shahriar Pourreza: Okay. Perfect. And then just in terms of financing needs. I know you guys — obviously, there’s a slight change in language around the ATM use versus equity content. Can you just elaborate on the range of options and timing of equity funding? And is kind of asset optimization still in avenue, given the impetus we’re seeing in your core Houston jurisdiction? Thanks guys.

Chris Foster: Sure. I think if you look just at the immediate year itself, we have indicated we’ve taken care of the equity needs for 2025 for the plan. As you go beyond that, we have consistently said and they’re staying there that we’d be utilizing the ATM to take care of our modest equity needs going forward. And as we mentioned, today, you should assume we continue to fund the business, the enterprise at 50% debt, 50% equity. And I’ll just say again, we consistently evaluate the most efficient way to fund this growth CapEx going forward. I mean really just like the Louisiana, Mississippi Gas LDC sales that we referenced will actually be closing this quarter. So I think you’ve seen here the team demonstrate that ability to look at multiple different options, everything from utilizing the base ATM to the hybrid structures and engineer subordinated notes that we utilized as well as the potential for transactions when they are the most efficient way to produce — to pursue this financing.

Jason Wells: So this will also be a big part of the update that we have later in this year. We’re committed to funding any of the equity needs efficiently as we have demonstrated, and we’re also committed to preserving the balance sheet creating a healthy cushion before — between that downgrade threshold and where we are running the business. And so that will be part of this comprehensive update that we’ll provide later this year.

Shahriar Pourreza: Yes. And I appreciate it. And then you guys have been fairly successful in the asset optimization side, which is why I asked the question. Thanks, guys. Appreciate it.

Operator: Thank you. Our next question comes from James Thalacker with BMO Capital Markets. Your line is open.

James Thalacker: Good morning. Can you guys hear me? I just want to touch quickly on your cost control program and target to keep the O&M at like a 1% to 2% decline across your plan, given the increase in resiliency spending including the higher vegetation management spending. Could you talk a little bit about the discrete levers you are looking at or identified to allow you to kind of deliver on the O&M reduction program as you go forward?

Chris Foster: Sure. James, I think if you look at what we talked about this morning, we will have a substantial increase, which is needed for our system for a much more aggressive vegetation management standard. But really nothing has changed in terms of our focus on taking out 1% to 2% per year. We have delivered that clearly over the last three years and actually just shy of 2% per year. Going forward, there’s probably a couple of areas I would touch on. I know we mentioned in our prepared remarks the ability to actually reduce O&M as a direct result of the capital that we’ll be putting on the system for the system resiliency plan. And the basic way to think about that is we’ll have fewer truck rolls because we’ll have automated devices on our grid, which allow for self-healing, right?

In those instances where otherwise, you would have to roll a truck for our frontline team members to take care of a fuse on the system or otherwise be reenergized. A second area of focus for us will be on really legacy systems and standardization across the footprint that we have. We have the ability in certain instances to sync up our IT systems and network systems as well as at standards that are utilized that are slightly different in the different states that we serve. And we’re utilizing the lean operating system here together to really focus on ensuring that we’ve got strong standardization that we’ve got, in some instances, vendor rationalization and other steps we can take to reduce costs year-over-year. And then the third, I would say, is really just our focus on empowering those closer to the word, ultimately, James.

That allows us to really allow for year-over-year improvements on everything from empowering our coworkers to be able to evaluate existing standards take out those costs and just make the process as simpler to get the work done. So when you look across those three areas, we have a high level of confidence. We’ll continue that track record of 1% to 2% out per year over the plan.

James Thalacker: That’s great. We appreciate the color, Chris, and congratulations on a great quarter.

Chris Foster: Thank you.

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

Jeremy Tonet: Hi, good morning. Just want to come back to the mobile gen a little bit more. Thank you for all the details on how that would look on the financial side, I was just wondering if you might be able to expand a bit more, I guess, on how conversations have evolved with regulators, with other stakeholders in the state. Just wondering kind of state of affairs as you can share.

Jason Wells: Yes, Jeremy, I appreciate the question. We continue to have dialogue with all stakeholders. And I think folks recognize the value here. ERCOT has signaled a real need in the San Antonio region if otherwise wasn’t addressed, it could impact the entire ERCOT market. We want to be a constructive partner and have said that from day one. I think our commitment to donate these units effectively at zero cost to help, the ERCOT market reflects that. And I think people, stakeholders as we’ve had these conversations recognize that, that is a pretty significant gesture on behalf of the company. We also have heard loud and clear the demands to make our customers whole for the period where our customers benefited from this equipment.

And I think we’ve worked hard to find a great solution there that Chris outlined. And so I’m optimistic that we are moving to a path where collectively, this is a win-win for all stakeholders. I think the next time this will be addressed is at the special meeting for ERCOT on February 25. ERCOT really wants these units in place before the summer season. So I’d expect this to get resolved here over the coming month or so, so that we can get these units in place by this spring.

Jeremy Tonet: Got it. That’s helpful there. And then going to the legislative session in Texas, a little bit more. Any proposals that are out there that are on your radar right now and really kind of thinking about the proposed SB 6 regarding large load and transmission charges. Just wondering if passage happens here, how this could impact CenterPoint in your mind?

Jason Wells: Yes. Thanks for the question. It’s — the Texas legislature is really now just starting to kick off and pace is going to really increase from here. A lot of the work to date has been to many assignments and kind of policy orientation. What I would say, Jeremy, is we were pretty active in the ’21, ’23 legislative sessions. We’ll probably be less active in this one. obviously working to support constructive legislation that continues to help drive resiliency of our system as well as help support this incredible growth that Texas economy is experiencing. With respect to Senate Bill 6, look, I really look at that as making sure that large loads pay their fair share is sort of a cost allocation focus. Those large loads in encompass a lot of our largest customers here in the Greater Houston region given our strong industrial base.

And so we’re going to work constructively with obviously our legislators, regulators, customers to find what is a fair cost allocation for everyone. I think it’s early days in that regard, but we’re working with all parties to find as I said, a constructive outcome.

Jeremy Tonet: Got it. We’ll stay tuned there. And just a real quick last one, if I could. Any guardrails you could put on the transmission opportunity depending on ERCOT’s 765 decision?

Jason Wells: Jeremy, guard rails in terms of where do I think they’re going to land or how much in terms of incremental CapEx, just tell me kind of what the direction of…

Jeremy Tonet: CapEx, sorry.

Jason Wells: Yes. Look, I think the 765 kV standard will result. And obviously, more capacity on the system, but at a higher cost, right? And so when I threw out that we think it will be at least $3 billion, if not more, I think that’s reflective of more of a 345 kV standard. Also, there’s still some work to be done on the specific routes. But I think the number — we will push well north of that under a 765 kV standard at or above that level under a 345 kV.

Jeremy Tonet: Got it. Thank you for that.

Operator: Thank you. Our next question comes from Durgesh Chopra with Evercore ISI. Your line is open.

Durgesh Chopra: Hey, team. Good morning. I just had one question on 2025 guidance. Maybe just, Chris, can you — for our models, can you help us bridge in 2024, what was included for temporary generation? And in 2025, what are you excluding, that’s what the release says, I don’t think the language has changed. But just want to make sure that we have the right pieces, I assume there will be some write-downs and you’re excluding that. But just what is in ’24? And then what is in ’25 and going forward? Thank you.

Chris Foster: Sure. Happy to paint it for you, Durgesh. In short, what was in the prior recoveries you can see and tie back directly to what we filed for recovery of and the TEEF filing for sure, it’s temporary emergency electric facilities, right? So we had filed for that. You can already see there you would have logically the lease base cost, the associated rate base and the equity and debt return. As it relates to going forward, once these units in the spring are provided to the San Antonio area, we’d essentially be removing what remains from rate base. We would also, from an earnings standpoint, be excluding, as I referenced this morning from non-GAAP, any of the related future benefit as well as the interim period, or roughly two years while they’re in San Antonio would be excluding that detriment, including we would start in 2025.

Jason Wells: If I could add, Durgesh, here, just as a point of reference, the temporary generation equipment was being amortized over a short period of time. And so the equity earnings is rapidly decreasing each year. So as we’re now several years into this, it’s less of a material driver or was originally going to be a material drag as Chris said, we’re going to take this, obviously, at a rate base but it’s a manageable level of equity earnings on the regulated side to overcome. You had mentioned a write-down. I don’t anticipate a write-down. The value of this equipment has effectively doubled in the market. And that’s why we feel like we can be constructive here in the state by donating this equipment to help our cost for two years and then more than make up that difference on the back end when we can market this equipment to third parties.

As Chris said, we don’t — when we send these units to San Antonio, we’re effectively creating an unregulated subsidiary that does not reflect the ongoing earnings power of the company. So we intend to exclude the loss during the period there in San Antonio. We won’t have any revenue, but we’ll still have the lease expense. We will also similarly exclude the gains then, and those gains will well exceed the cost when we market at the end. We just don’t think it’s a reflective of the ongoing earnings power of the company. Net over time, we expect to fully recover that investment just begin because, as I mentioned, the market has moved so fundamentally on the value of those units.

Durgesh Chopra: That’s helpful. Okay. So, there’s no underlying change in the value of the assets. It’s just the earnings contribution is going to be regulated versus nonregulated. And your kind of splitting that out of your core earnings, right? Is that a fair way to put it?

Jason Wells: That’s a fair way to put it. What would have remained as regulated earnings is very manageable because it’s been — this equipment has been — being amortized so quickly. So we will no longer have any more regulated earnings on it after the spring of this year. And then as we look out, then it will effectively be an unregulated portion of our business for a short period of time, and we will exclude that from our non-GAAP earnings because it’s just not reflective of the underlying earnings power of the business.

Durgesh Chopra: Okay, very clear. Thanks so much. I appreciate the time.

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

David Arcaro: Hey, thanks so much. Good morning. I was wondering on the load growth outlook that you’ve laid out, could you frame the status of the projects and the customer requests in that 61 gigawatt load growth level. It’s such a huge potential pipeline there through 2031. Is that something that year-by-year, we might see even more of these projects come in? Are they very early stage and very — or lower probability?

Jason Wells: I think you summarized it well there at the end in terms of lower probability, maybe the way to think about it is we’ve had requests totaling roughly 40 gigawatts to connect to our system. Some of those are exploratory in nature, so lower likelihood of occurring. Some of those are early stage and may materialize later. And so, what we wanted to frame here was the potential growth is really incredible. It’s double our peak that we currently see today. We just are trying to take a more realistic point of view of what’s likely between now and 2031, and that’s what we think the 10 gigawatts. I think over time, to your point, we will see some of that incremental, I’ll call it, than 30 gigawatts. Some of it may come in.

There will also be new projects that come to knock on our door. And so there will constantly be a churn. We think the 10 gigawatts that we folded into the substantiated is the most realistic point of view today, and we’re going to be annually updating this number moving forward. It’s just a reflection of the fact that there is, again, a significant desire to connect to the grid here in Texas, well, nearly double what our current peak is. And it’s just what’s realistic over the next few years is probably something closer to 10 gigawatts.

David Arcaro: Okay. Great. Yes, absolutely. That’s helpful. And then I was just also curious, are you able to provide an update on within that outlook, how much of a data center pipeline that you’re seeing, any refresh numbers versus the 8-gigawatts that I think you talked about before?

Jason Wells: Yes. We continue to see an increase in demand from data center activity. It’s now north of 11 gigawatts here just in the greater Houston area. Again, I would put that 11 gigawatts as part of the 40. So some of those conversations are exploratory in nature, some of those conversations are data centers that are pursuing interconnection requests throughout Texas and other states. So, I wouldn’t anticipate that all 11 gigawatts materializes. But suffice it to say, the level of activity continues to accelerate from where we were just a year ago. I’d also say we continue to see data center activity up in Indiana, which has been a little bit less of a focus just given the substantiated load process that we recently filed under here in Texas.

But up in Indiana, it remains a central market for a number of hyperscalers. We have a vertically-integrated business up there with the ability to quickly convert our simple cycle, gas C2 to a combined cycle really giving kind of incremental capacity in that region. And so, we continue to see data center demand up there. I’d be surprised if we’re not talking about landing in some portion of our business. significant hyperscaler opportunity at some point. But we’re — we, like many of our peers are in the middle of these conversations as we speak.

David Arcaro: Awesome. Thanks for all that color. I’ll keep an eye out for that.

Jackie Richert: Operator, given we are getting close to the end of the hour, we’ll take one more.

Operator: Thank you. Our last question comes from Julien Dumoulin-Smith with Jefferies. Your line is open.

Julien Dumoulin-Smith: Hey, good morning, team. Thank you, guys, very much. Appreciate the time. Maybe just to come back to maybe a little cleanup on a couple of things that were mentioned here. First, just with respect to mobile generation. I just wanted to make it very crystal clear about this. With respect to what’s assumed from a cash perspective, not from an earnings perspective, you’re effectively assuming full recovery of the — whatever expenses are incurred here with any pro forma counterparty. And then related, if you can speak to it. Obviously, you mentioned the Feb 25 ERCOT special meeting, to the extent to which that were or were not to prevail, can you speak a little bit to the market depth. Certainly, we’re seeing this mobile generation subject mushroom in other circumstances, if you can speak to kind of backup plans as well on the margins.

Jason Wells: Yes. With respect to the first issue on cash flows, there will be some variation between years, but kind of net over the life. I see this is actually a cash flow tailwind for the company. As I said, the market on this equipment has doubled. We had originally prepaid this lease, and so we have the opportunity to market under significantly higher rates roughly two years from now when this equipment is done. So, if anything, I think of it as a potential cash flow tailwind for the company. As it relates to the special meeting. Look, I think this is a great solution for everybody. ERCOT has said that they have a need in that San Antonio market. We are happy to step up and provide that equipment at no cost. I think that’s an incredible offer a really constructive outcome for immediate solution.

If for whatever reason, though, ERCOT decides to take a different direction, we have heard loud and clear that this equipment will come out of our regulated operations. And we will turn and begin to market this equipment to third parties as an alternative. And so I don’t look at that necessarily as a downside, if anything, gives us the opportunity to turn to a market that I said is incredibly quite favorable for this equipment. As you know, there’s only a handful of manufacturers of this type of equipment, and there’s really no new significant capacity coming online for the next several years. And so we think the value will hold up over this period of time.

Julien Dumoulin-Smith: Yes. No, absolutely. And then lastly, a quick cleanup item. With respect to the store recoveries, you’re obviously making a filing for the subsequent storm here in 2Q as you alluded to. Any reason to think that there is a meaningfully different outcome than what you saw here with the first storm arrangement. Any specific nuances that we should be watching on that front, just to set expectations?

Chris Foster: Sure, Julien. I think it’s — the short answer is no. I think we will be planning, as you said, to file Q2. This will be for roughly $1.1 billion for Hurricane Beryl response. The why behind my answer is that, ultimately, a lot of the costs themselves were driven by the incredible mutual aid and other crews that help our teammates restore power timely, right? And so that’s the major driver, both the materials and the labor associated with getting the light back off for our customers. And so, from that standpoint, we think from both a timing and resolution standpoint, we should be on plan.

Julien Dumoulin-Smith: Wonderful. Excellent. All right, guys. Congrats on everything. See you soon. Stay warm.

Jason Wells: Thanks, Julien.

Chris Foster: Thank you.

Jackie Richert: Thanks, Julien, and thanks, operator. With that, that will conclude our call for today. Appreciate everyone dialing in and look forward to speaking with everyone soon.

Operator: Thank you. This concludes CenterPoint Energy’s Fourth Quarter and Full Year Earnings Conference Call. Thank you for your participation. You may now disconnect.

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CENTERPOINT ENERGY INC

Q4 2024

Earnings Transcript

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