By CenterPoint Energy (ticker: CNP), a prominent utility company, held its Third Quarter 2024 Earnings Conference Call recently, where CEO Jason Wells and CFO Chris Foster provided insights into the company’s financial health and strategic initiatives.
Despite a decrease in non-GAAP EPS from $0.40 to $0.31 year-over-year, the company reaffirmed its 2024 non-GAAP EPS guidance range of $1.61 to $1.63, signaling an 8% growth from 2023. CenterPoint Energy is also laying the groundwork for future growth, with a focus on grid resiliency, regulatory updates, and significant organic growth in Texas, particularly in the Greater Houston area.
Key Takeaways
CenterPoint Energy reported a non-GAAP EPS of $0.31 for Q3 2024, with a reaffirmed 2024 guidance range of $1.61 to $1.63.
The company initiated its 2025 non-GAAP EPS guidance at $1.74 to $1.76 per share, reflecting 8% growth from 2024.
Significant organic growth is expected in Texas, with a projected 30% increase in peak load by 2030.
The Greater Houston Resiliency Initiative (GHRI) has made substantial progress in enhancing grid resilience.
Regulatory efforts include withdrawing the Houston Electric rate case and pursuing recovery of storm costs.
CenterPoint plans to invest $4.9 billion in 2025, contributing to a 10-year capital plan of $47 billion, with $21 billion allocated to Texas.
The balance sheet remains strong, with $3 billion in anticipated cash inflows from divestitures and securitizations.
Company Outlook
CenterPoint Energy remains committed to its long-term growth targets of 6% to 8% annually through 2030.
The company plans to file a general rate case application in Ohio to align investment recovery rates with peers.
Investments of $4.9 billion are planned for 2025, focusing on pipeline modernization and safety enhancements.
Bearish Highlights
Q3 non-GAAP EPS decreased year-over-year, mainly due to increased O&M costs.
The company is managing $1.6 billion in storm-related costs, with future filings for cost determination planned.
Bullish Highlights
CenterPoint Energy is experiencing strong organic growth, especially in the Greater Houston area.
The company’s financial position is expected to strengthen in 2025 and beyond, with securitization proceeds.
Positive stakeholder feedback in Texas supports the company’s focus on resilience and communication.
Misses
There was a decline in non-GAAP EPS in the third quarter compared to the previous year.
Q&A Highlights
The company discussed the impact of increased demand from data centers on future transmission and CapEx plans.
CenterPoint is exploring options like subleasing to maintain resource availability for winter peak capacity.
Updates on ERCOT’s load forecast and planning are expected in early 2025.
In conclusion, CenterPoint Energy’s earnings call revealed a company that is navigating current challenges while strategically preparing for future growth. The company’s emphasis on grid resilience, regulatory foresight, and robust investment plans positions it to meet the increasing energy demands of Texas and beyond. With a strong balance sheet and a clear vision for the future, CenterPoint Energy is poised to continue its trajectory of growth in the years to come.
InvestingPro Insights
CenterPoint Energy’s recent earnings call aligns with several key metrics and insights from InvestingPro. The company’s reaffirmed guidance and focus on long-term growth are reflected in its financial data. According to InvestingPro, CenterPoint Energy has a market capitalization of $19.33 billion, indicating its significant presence in the utility sector.
One of the InvestingPro Tips highlights that CenterPoint Energy “has maintained dividend payments for 54 consecutive years.” This impressive track record of consistent dividends aligns with the company’s commitment to shareholder value, as discussed in the earnings call. The current dividend yield stands at 2.87%, with a notable dividend growth of 10.53% over the last twelve months.
Another relevant InvestingPro Tip states that the company is “trading at a low P/E ratio relative to near-term earnings growth.” This is supported by the P/E ratio of 18.3 and a PEG ratio of 0.46, suggesting that the stock may be undervalued considering its growth prospects. This could be particularly interesting for investors given CenterPoint’s projected 8% EPS growth for 2025 and its long-term growth targets of 6% to 8% annually through 2030.
The company’s focus on grid resiliency and significant investments in Texas is reflected in its strong financial position. InvestingPro Data shows that CenterPoint Energy’s revenue for the last twelve months was $8,567 million, with an EBITDA of $3,215 million and an EBITDA growth of 16.91%. These figures support the company’s ability to fund its ambitious $47 billion 10-year capital plan.
It’s worth noting that InvestingPro offers additional insights, with 7 more tips available for CenterPoint Energy, providing a more comprehensive analysis for investors interested in delving deeper into the company’s prospects.
Full transcript – Centerpoint Energy (NYSE:CNP) Q3 2024:
Operator: Good morning, and welcome to CenterPoint Energy Third Quarter 2024 Earnings Conference Call with Senior Management. [Operator Instructions] I will now turn the call over to Jackie Richert, Senior Vice President of Corporate Planning, Investor Relations and Treasurer. Ms. Richert, please go ahead.
Jackie Richert: Good morning, and welcome to CenterPoint Energy’s third quarter 2024 earnings conference call. Jason Wells, our CEO; and Chris Foster, our CFO, will discuss the company’s third quarter results. Management will discuss certain topics that will contain projections and other forward-looking information and statements that are based on management’s beliefs, assumptions and information currently available to management. These forward-looking statements are subject to risks and uncertainties. Actual results could differ materially based upon various factors as noted in our Form 10-Q, other SEC filings and our earnings materials. We undertake no obligation to revise or update publicly any forward-looking statements. We will be discussing certain non-GAAP measures on today’s call. When providing guidance, we use the non-GAAP EPS measure of diluted adjusted earnings per share on a consolidated basis referred to as non-GAAP EPS. For information on our guidance methodology and reconciliation of the non-GAAP measures discussed on this call, please refer to today’s news release and presentation on our website. We use our website to announce material information. This call is being recorded. Information on how to access the replay can be found on our website. Now I’d like to turn the call over to Jason.
Jason Wells: Thank you, Jackie, and good morning, everyone. I’d like to begin by extending our deepest sympathies to our families and communities impacted by the devastation caused by Hurricane Helene and Hurricane Milton. The destruction caused by this year’s hurricane season is undoubtedly tragic. However, it is times like these that truly bring out the best in our industry. A few weeks ago, we saw the utility community come together to send more than 50,000 utility workers from at least 43 states, the District of Columbia and Canada to support hurricane restoration efforts across the Southeast. From CenterPoint, we contributed to the effort by sending personnel representing nearly 1/3 of our electric frontline workforce to assist in the restoration efforts for Helene and Milton. As many of you know, the Greater Houston area benefited greatly from the same mutual assistance framework during Hurricane Beryl, where we called upon 13,000 workers from approximately 30 states to help restore power to more than 2 million customers. I want to thank all of our frontline teams as well as others throughout the industry that answered the call to help get the lights back on for the millions of people impacted by the destructive hurricanes we’ve experienced this season. On today’s call, I’d like to address five key areas of focus. First, I’ll briefly touch on the third quarter financial results. Second, I’ll discuss the progress we’ve made and future goals with respect to our Greater Houston Resiliency Initiative or GHRI. Third, I’ll provide an update on our various regulatory efforts. Fourth, I’ll highlight the organic growth we continue to experience, particularly in the Houston Electric Service Territory. Lastly, I’ll conclude with the initiation of our earnings guidance for 2025. Today, we reported non-GAAP EPS of $0.31 per share for the quarter. In addition, we are reaffirming our full year 2024 non-GAAP EPS guidance range of $1.61 to $1.63 per share. This represents 8% growth at the midpoint from our 2023 results. Chris will provide additional details on our financial results in his section. Now I’d like to provide an update on our ongoing execution of our electric operational plan, the Greater Houston Resiliency Initiative, which we launched in early August. As you may have seen, we have already made significant strides towards strengthening the resiliency and reliability of our grid in the first phase of GHRI as well as enhancing our communications with our customers. These actions have been informed by learnings from internal and external reviews, engagement with stakeholders and benchmarking with high-performing sector peers. During the third quarter, we took immediate action and accelerated our plans to deliver an unprecedented level of work. This includes removing higher-risk vegetation across 2,000 line miles, replacing over 1,100 poles with new poles capable of withstanding extreme wind and installing over 300 automated reliability devices to help reduce the number and duration of customer outages. We accomplished all of this work before the end of August and ahead of schedule. With respect to improving our communications, we launched our new and updated outage tracker on August 1. This tool is designed to enhance the customer experience during times of service disruptions. Additionally, we’ve stated our commitment to hire senior emergency preparedness and response and communications leaders to bolster our leadership team. I’m pleased to share we have hired leaders for both of these positions that bring a wealth of industry experience and will accelerate our efforts to improve our preparedness and response in our customer experience during emergency events. We believe our more proactive communications approach is already positively impacting the customer experience through more timely information. These are great first steps, and I’m proud of the progress thus far. But we have heard the call to action, and we are committed to doing even more in the second and third phases of GHRI for the benefit of our customers and our communities. These next two phases will focus not only on reducing the number of outages, but also reducing the outage time customers’ experience through investments designed to create a self-healing grid. I want to underscore, however, that GHRI does not represent the beginning of our enhanced resiliency investments. This is merely a continuation and acceleration of the work we started well ahead of this year’s events. Over the last few years, we have focused our resiliency investments in our electric transmission system, which is the backbone of our grid. Our transmission resiliency work included upgrading our transmission structures to better withstand extreme winds, elevating our substations to mitigate flood risk and converting our older 69 kV transmission lines to a more robust 138 kV standard. This work has already produced tangible results. During the derecho in May and Hurricane Beryl in July, our hardened transmission system withstood the extreme winds and sustained relatively little structural damage. In fact, while other Texas utility customers sustained prolonged outages due to damage on their transmission system from Hurricane Beryl, we did not experience any customer outages due to our transmission system. As we now turn our attention to accelerating investments in the distribution system in the next two phases of GHRI, we believe we are well positioned to make rapid improvement. Currently, a little over 46% of our Houston Electric distribution system is underground, which on a proportional basis, is more than twice the industry average. Our opportunity is to harden above ground feeders to those communities through smaller, more targeted investments that should yield impactful results for approximately 60% of the customers that are served by underground service. This feeder blitz is expected to have the additional benefit of substantially reducing the total outage numbers and accelerating restoration for other customers as resources can focus on the remaining circuits earlier in the restoration process. Another area we believe we can make meaningful improvements on our distribution system is with respect to increased circuit segmentation and automation. Equipment such as intelligent grid switching devices and trip savers help create a self-healing grid by isolating outages to fewer customers, rerouting power around impacted areas and automatically restoring power without manual intervention where there is no structural damage. Presently, approximately 30% of Houston Electric’s overhead circuits have at least one automation device. As part of Phase 2 of GHRI, we anticipate installing 4,500 trip savers and 350 intelligent grid switching devices before the next hurricane season which will allow us to nearly double the number of distribution circuits with automation devices in the Greater Houston area. Our investments in work during this phase are anticipated to save our Houston area customers over 125 million outage minutes annually. Over the next five years, we plan to not only deploy even more devices, but also optimize their capabilities by employing AI-based modeling. We plan to share additional details regarding our future resiliency investments on our fourth quarter call, which will take place after we have filed our system resiliency plan. As a reminder, our revised system resiliency plan will include approximately $5 billion in resiliency investments from 2026 through 2028, an increase of approximately $2.5 billion over our previously withdrawn system resiliency plan. Chris will go into more detail in his section, but I want to highlight that even with the inclusion of these incremental resiliency investments, we anticipate Houston Electric’s customer delivery charge increases will track in line with the long-term rate of inflation over the next 10 years. Turning to an update of our broader regulatory efforts, starting with Houston Electric. As many of you likely saw on August 1, we filed our notice to withdraw our Houston Electric rate case filing. This withdrawal allows us to continue to focus our attention on near-term plan execution and long-term system resiliency plan development as we are laser-focused on year-over-year improvements. If the withdrawal is approved, we have stated that we will file a new Houston Electric rate case no later than June 30, 2025, based on a 2024 calendar test year. Outside of the rate case filing, we intend to continue to seek recovery of capital investments made for the benefit of our customers. In the fourth quarter this year, we anticipate filing to start recovery of both our recent transmission and distribution investments through our TCOS and DCRF capital trackers. The efficient recovery of these investments is crucial to our ability to efficiently fund future investments. This is why we remain focused on reducing regulatory lag across all of our jurisdictions. Our latest earnings monitoring report highlights the regulatory lag we continue to experience at Houston Electric. For 2023, our weather-normalized earned return on equity was nearly 150 basis points lower than are allowed. In addition to filing for a recovery of our investments, we will also make the initial filing for the recovery of approximately $450 million in storm costs related to the May derecho. Now turning to the Indiana Electric rate case. A little over a month ago, we filed our proposed order with respect to our nonunanimous settlement proposal. The Indiana Utility Regulatory Commission has a statutory deadline to issue its final order by February 3, 2025. We want to thank all stakeholders for their contributions to the case as we seek to reach a fair outcome for all parties. Moving next to the filed Minnesota Gas rate case. As some of you may have seen, intervenor testimony was filed a few weeks ago. Since then, we have had constructive settlement talks with stakeholders and intend to continue in the settlement negotiations leading up to our rebuttal testimony deadline of November 12. As you may recall, we have settled our previous three rate cases in our Minnesota Gas jurisdiction. Absent a settlement, the Minnesota Commission may consider interim rates for 2025 toward the end of this year. Finally, I want to touch on our upcoming rate case application for Ohio Gas. In August, our Ohio Gas business filed its Notice of Intent with the Public Utility Commission of Ohio regarding our upcoming general rate case application, which we intend to file tomorrow. Over the last several years, we have had one of the lowest customer gas bills in the state. Our upcoming ask reflects an investment recovery rate that will put us more in line with our Ohio peers. In addition, this larger revenue requirement increase will allow us to more efficiently fund the continued pipeline modernization investments, which we believe contributes to the overall safety and efficiency of the system. Now I want to highlight the strong organic growth we continue to see, especially in our Texas service territories. While much of my earlier commentary focused on our investments in resiliency and reliability, I want to emphasize that we continue to experience significant growth across Texas and in particular, the Greater Houston region. Over the last few decades, the Greater Houston region has grown at one of the fastest rates in the nation. We see that growth not only continuing but accelerating through the remainder of this decade and beyond. In fact, we believe our peak load of approximately 22 gigawatts in 2024 could increase by more than 30% by 2030. This potential growth is driven by continued population growth, acceleration of electrification and increases in data center activity. Houston continues to be an attractive city to live and work. Over the last five years, housing starts have increased over 9% per year on average, which is more than 3x the national average. We see this growth continuing as businesses and people like continue to migrate to the Houston area. Our industrial load growth drivers are both large and diverse. Our substantial potential future load growth is underpinned by industrial electrification and energy exports, including hydrogen. Houston remains an ideal location for hydrogen developers as it already boasts the largest hydrogen infrastructure in the world in addition to proximity to the largest port by waterborne tonnage in the United States. Although we still are in the early stages of hydrogen development, we are working with approximately 3.5 gigawatts of projects that are well into the advanced engineering phase. Outside our more traditional load drivers of energy and energy exports, we see growing potential incremental load from other sectors. Notably, over this summer, we have seen a fundamental shift in data center development. In fact, our interconnection queue for data centers now sits at over 8 gigawatts. While we recognize that not all of this will be developed, it is yet another tailwind in what we continue to believe is one of the most tangible long-term growth stories in the industry. It is with this growth in our customer-driven capital investments that we’ve made over the last couple of years that gives us conviction to initiate our 2025 non-GAAP earnings guidance target range of $1.74 to $1.76 per share. The midpoint of this range represents 8% growth from the midpoint of our 2024 guidance range of $1.61 to $1.63. Beyond 2025, we are also reaffirming our longer-term guidance where we expect to grow non-GAAP EPS at the mid- to high end of our 6% to 8% range annually through 2030 as well as targeting dividend per share growth in line with earnings per share growth over that same period of time. For our customers, this strong Houston area growth gives us confidence that we will keep increases in electric delivery charges, roughly in line with the forecasted rate of inflation over the next 10 years. We recognize the privilege and responsibility of being an energy delivery provider for our customers. We will be laser-focused on both enabling growth and advancing system resiliency for the benefit of our customers through the work that we’ve outlined in GHRI as well as the investments we will propose in our new system resiliency filing. We look forward to continuing to work with our customers, regulators and others to make improvements for the benefit of all of our stakeholders. And with that, I’ll turn it over to Chris.
Chris 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 1/3 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 1 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 is primarily driven by the ongoing recovery from various interim mechanisms for which customer rates were updated last year as well as the interim rates in our Minnesota Gas business that went into effect on January 1 of this year. In addition, the Houston area continues to see strong organic growth, extending the long-term trend of 1% to 2% 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 May derecho 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 to-be 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 (NYSE:MCO) 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 5-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] Thank you. And one moment for our first question. And the first question will come from Shar Pourreza with Guggenheim. Your line is now open.
Shar Pourreza: Hi, guys, good morning.
Jason Wells: Hi, good morning, Shar.
Shar Pourreza: Good morning, Jason. So just on ’24 looks like it’s in good shape as we’re sort of thinking about ’25 guidance. There’s 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’s 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 in some key events. It’d be great to maybe if you can bridge it a little bit further for us? Thanks.
Jason Wells: Yes, 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. And 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 this 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 resolved 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, so $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 our 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: And the next question comes from Steve Fleishman with Wolfe Research. Your line is now open.
Steve Fleishman: Yes. Hi. Good morning.
Jason Wells: Good morning, Steve.
Steve Fleishman: So hi, so first, just the detail on the Texas load growth, and the 30% growth in peak through 2030. Is that kind of include all the updates that you owe to I think ERCOT for early next year for kind of load 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 ERCOT. That process with ERCOT, 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?
Chris 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 against Moody’s and the 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, 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.
Chris Foster: Thank you.
Operator: And our next question comes from Durgesh Chopra with Evercore. Your line is open.
Durgesh Chopra: Hi, good morning, team. Thanks for giving me time. Hi, 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 you’re 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.
Chris Foster: Sure Durgesh. Happy to do it. Let me just remind everybody again, the highest order, 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 or derecho related storm costs. We’ll file that soon. 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 toward the low end of the cost themselves. Previously our guide was $1.6 to billion $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 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 these 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?
Chris 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, kind of 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 that detail, color. Thank you.
Operator: Our next question comes from Jeremy Tonet with JPMorgan Securities. Your line is open.
Jeremy Tonet: Hi, good morning.
Jason Wells: Good morning, Jeremy.
Jeremy Tonet: 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: Yes, no thanks Jeremy for the question. I think things continue to improve. I mean, we’ve concocted obviously extensive outreach, elected officials, customers, our communities, community leaders. And what we’ve heard inconsistently is that, everybody wants a more resilient system. They want improved 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 the 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, will save our customers about 125 million outage minutes annually. And I think that’s the direction that our stakeholders want to see us go in. 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?
Chris Foster: Sure. Good morning. I think there’s a few pieces to keep in mind there, which informally the confidence of maintaining our guide. I think the first piece again, is just the consistency of the trackers that we’ve got. The last couple 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 I’ll again just reiterate, we did a lot of incremental work on the system in Q3, certainly highlighting the critical vegetation management work during the sprint, 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 from Q4, so I’d expect that to result in about $0.01 benefit to Q4 as well. And on top of that recall last year that we had 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 you do the quarter-over-quarter look all-in-all confident here for the year.
Jeremy Tonet: Okay. Great, helpful. Thank you.
Chris Foster: Thank you.
Operator: And our next question comes from David Arcaro with Morgan Stanley. Your line is now open.
David Arcaro: Hi. Thank you. Good morning.
Jason Wells: Good morning, David.
David Arcaro: 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, with that proposal?
Jason Wells: Yes, just as a quick reminder. I think the real focus of the state’s attention on the temporary generation portfolio, is 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 that 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, but 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 a solution that works, a solution that works for our customers in times of load shed. We still have an obligation to rotate power 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, state wants to change that requirement or wants us to look at these units differently, we’re happy to work with the state in that regard. So there’s no prescribed timing. We attempted to address the concerns on the profit, the remaining profit on the large units, and we’ll work with the state to find 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, ERCOT will update the speculative load study in early ’25. At that point, they will incorporate an estimate of speculative load in the Greater Houston 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% 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 along, 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: All right. Our last question will come from Julien Dumoulin-Smith with Jefferies. Your line is now open.
Julien Dumoulin-Smith: Hi, 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?
Jason Wells: Yes, thanks.
Julien Dumoulin-Smith: 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 the 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.
Julien Dumoulin-Smith: Excellent. And just a quick nitpick on the last response. Just a transmission update from ERCOT here. Obviously, ERCOT 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 ERCOT’s demand? And effectively, are you suggesting as a further sort of net uptick in ERCOT’s 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, Julien, 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 Houston 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 1 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 ERCOT’s 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 Houston region.
Julien Dumoulin-Smith: Right. So even accelerating in the last quarter despite ERCOT’s update even the last couple of months here, it seems like there’s an upward bias there?
Jason Wells: Yes, yes.
Julien Dumoulin-Smith: Awesome. Excellent guys. Thank you for the time and clarifying that.
Jason Wells: Thanks, Julien.
Jackie Richert: Thanks, Julien. And with that, operator, I think that will conclude our Q&A for today. 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.
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