CenterPoint Energy, Inc. Q2 2026 Earnings Call

Good morning, welcome to CenterPoint Energy's second quarter 2026 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 remarks. To ask a question, please press star one one on your touchtone keypad. I will now turn the call over to Ben Vallejo, Vice President of Investor Relations and Corporate Planning. Please go ahead. Good morning, welcome to CenterPoint's Q2 2026 earnings conference call.

Jason Wells, our Chair and CEO, Chris Foster, our CFO, will discuss the company's second quarter 2026 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 on 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 statement other than as required under applicable securities laws. We reported $0.37 per diluted share for the second quarter of 2026 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. I'd like to turn it over to Jason.

Thank you, Ben, good morning, everyone. On today's call, I'd like to address four key areas of focus for the quarter. First, I'll briefly walk through our strong second quarter financial results as we remain on track to deliver our full year non-GAAP earnings guidance. Second, I will provide an update on the significant progress we have made through ERCOT's new Batch Zero process, including the submission of more than 17 gigawatts of large load projects. 14 gigawatts of these submissions are expected to be eligible for Batch Zero and would represent an increase of more than 65% from Houston Electric's current system peak of 21 gigawatts. Third, I will discuss today's announced $1.2 billion increase to our capital investment plan, driven by both the anticipated modest system upgrades expected to connect large load customers in Texas and continued progress related to the Downtown Houston Revitalization project.

We expect to deploy this incremental capital over the next five years without the need for additional equity financing. Finally, I will provide an update to our continued progress with prospective large load customers in our Indiana Electric service territory, which would represent transformational growth for the region and support long-term customer affordability. I'll start with our strong second quarter financial results. This morning, we reported non-GAAP EPS of $0.40 for the second quarter of 2026. We are reiterating our full year 2026 non-GAAP EPS guidance range of $1.89-$1.91, which at the midpoint represents 8% growth over actual 2025 delivered results as we seek to deliver compounded growth for our investors each and every year.

Over the long term, we continue to expect to grow non-GAAP EPS at the mid to high end of our 7%-9% annual guidance range through 2028 and 7%-9% annually thereafter through 2035. Now I'd like to provide an update on the progress we've made through ERCOT's new Batch Zero process. Before I go into the details of our submissions, I want to acknowledge the substantial interest from prospective large load customers in the greater Houston area and the incredible efforts they have made throughout this process to demonstrate and maintain eligibility for Batch Zero. The investment commitments made by these customers enabled 17 gigawatts of project submissions. This not only reflects the strength of electric demand growth in our region, but also gives us even greater confidence in the acceleration and durability of the growth we are already seeing over the longer term.

We look forward to working closely with our customers as this process continues to do our part in bringing growth to the region for the benefit of our customers, communities, and shareholders for years to come. Turning to the 14 gigawatts of projects that remain eligible for Batch Zero. Approximately 10 gigawatts of these projects have both required studies approved and are eligible for base load designation. The remaining 4 gigawatts of submissions are positioned to qualify as studied load because they have one of the two required studies already approved by ERCOT. The 4 gigawatts of studied load will further be evaluated by ERCOT and included in the load allocation process expected to conclude in April of next year.

In the aggregate, the 14 gigawatts of projects eligible for Batch Zero would represent over a 65% increase in our system's peak demand and further reinforce our confidence in achieving the accelerated 50% load growth by year-end 2029. Based on projected load ramps sought by customers, we expect nearly all of these projects to be energized by the end of 2030, extending our industry-leading growth trajectory well into the next decade. We are confident the combined 14 gigawatts of base load and studied load are well-positioned to move forward in the Batch Zero process given the level of customer commitments already secured. Among other customer commitments, these projects are supported by a signed Facilities Extension Agreement with long-term end user commitments. Approximately $900 million of customer cash commitments and security already received, and clear line of sight to the materials, execution capability, and system capacity to serve.

The remaining 3 gigawatts of Batch Zero submissions represent additional customer demand that is pending ERCOT approval of the required studies. We will continue working closely with our customers and ERCOT to advance these projects to support our customers' desired energization timelines. With that said, the next phase related to the 10 gigawatts of base load-eligible projects is already underway. We have already begun work on the targeted system upgrades required to serve these customers, and we expect to continue this work over the next 4 years. We will also continue to work with customers on projects that remain eligible for studied load to finalize the plans related to needed system upgrades. Investments for both these base load and studied load projects are reflected in today's announced capital investment plan increase, which I'll discuss in more detail in just a moment. Importantly, this growth also supports customer affordability.

With this increased demand from large load customers, we are now estimating that collectively, residential and commercial electric customers will save over $5 billion over the next decade through the addition of 14 gigawatts of eligible base load and studied load projects. Outside of the incredible transmission-level demand from large load customers, our Houston Electric distribution system continues to experience significant increases in localized demand. Consistent with the pace of growth we have seen this year, we are anticipating an additional 2 gigawatts of distribution-level demand over the next several years, driven by reshoring of advanced manufacturing and continued population growth in the greater Houston area. This growth will have additional affordability benefits for our customers. Moving now to the $1.2 billion increase in our 10-year capital investment plan.

Today, we are increasing our capital investment plan by $800 million to support targeted system upgrades associated with the 14 gigawatts of expected Batch Zero eligible projects. As previously highlighted, our Houston Electric system's approximately 10 gigawatts of existing hosting capacity gives us a distinct advantage in connecting significant new load quickly and efficiently with modest incremental investment. This differentiated system profile enables us to connect these projects at less than $60 million per gigawatt, allowing us to deliver long-term growth in a disciplined and affordable manner. Beyond today's capital increase related to system upgrades for expected Batch Zero eligible projects, we continue to evaluate the broader transmission investments necessary to support future demand growth through our ongoing internal transmission planning process. We expect to provide an update on these opportunities later this year.

In addition to the $800 million capital increase associated with system upgrades, we have also identified approximately $700 million of additional investment opportunities that would be required to serve demand of approximately 3 gigawatts that are not base load or studied load eligible. This incremental capital is outside of the planned transmission investments we are evaluating as part of our comprehensive transmission study. As those projects remain subject to future batch processes, we maintain our conservative approach to incorporating incremental investments into our 10-year investment plan and are not folding them in at this time. In addition to the investments associated with large load customers, we have made significant progress related to our work on the Downtown Houston Revitalization Project. With the input of various stakeholder groups, we have made final site selections for the two required substation relocations.

With those plans now solidified, we have refined our initial investment estimates. As a result, we are increasing our capital investment plan by another $400 million. With today's combined $1.2 billion capital investment increase, we now expect a Houston Electric rate base CAGR of over 18% over the next three years. Chris will cover this in his section. Importantly, today's announced capital investment increase does not result in any increased equity needs. Even after incorporating today's increase, we still maintain visibility to at least $10 billion of additional capital investment opportunities through 2035. Consistent with our disciplined approach, we will continue to add future investments to the plan as projects become more clearly defined and as we gain confidence in our ability to execute them for the benefit of our customers and communities.

Lastly, I want to touch on the transformational potential large load customer opportunities in our Indiana Electric service territory. We continue to make progress advancing large load opportunities in our Indiana Electric service territory, one of which would represent the single largest load we serve in that region. As a result of commitments from the customer, we have already begun work to serve this load. Outside of the project identified, we are engaged with multiple counterparties for additional large load projects in that area. As a reminder, the related investments required to serve these large loads would be incremental and outside of our current base plan. As we continue to advance these projects, we are focused on supporting the growth of the community we are privileged to serve and improving affordability for our customers for years to come.

In closing, we continue to believe that we have one of the most tangible and executable long-term growth plans in the industry. We remain confident in our ability to execute our updated $66.7 billion capital investment plan through 2035 while maintaining visibility to at least $10 billion of additional upside capital investment opportunities. We are also well-positioned to enable continued growth across the jurisdictions we have the privilege to serve, strengthening the economies of our service territories and improving affordability for our customers while maintaining our focus on delivering safer and reliable service. With that, I'll turn it over to Chris to cover the financials in more detail.

Thanks, Jason. This morning, I will cover four areas of focus. First, I will walk through the details of our strong second quarter financial results and how they position us well for the rest of the year. Second, I will touch on our regulatory progress through the first half of the year as we continue to execute on the timely recovery of our customer-driven capital investments. Third, I will provide additional details on our positively revised $66.7 billion 10-year capital plan, which, as Jason highlighted, will not require additional equity financing. Finally, I will give an update on our de-risked financing plan, balance sheet health, and credit metrics. Now, starting with our strong financial results on Slide five. On a GAAP EPS basis, we reported $0.37 for the second quarter of 2026. On a non-GAAP EPS basis, we reported $0.40 for the quarter.

Our non-GAAP EPS excludes expenses related to our LDC divestiture activity, including the tax expense associated with the gain on sale of our Ohio Gas LDC, which is required to be recognized over the full year of 2026, and restructuring costs in connection with our Louisiana and Mississippi divestitures, given the recent expiration of our related transition service agreement. In addition, we continue to exclude the impacts of removing our temporary generation units from base rates as they are no longer part of our regulated utility business. As a reminder, we will be marketing these units for either a sublease or sale and will also exclude the associated income resulting from these transactions. Taking a closer look at the drivers of our second quarter earnings.

Growth in rate recovery contributed $0.10 of favorability when compared to the same quarter last year, driven by a full quarter of impact of updated rates reflecting rate case implementation and the interim filing mechanisms that went into effect in the first quarter, as well as the partial quarter benefit from updated rates reflecting filings made earlier this year that became effective in June. Additionally, O&M was $0.02 favorable for the quarter as we continue to drive efficiencies in our accelerated peer-leading vegetation management program we started last year. Weather and usage were $0.01 unfavorable when compared to the comparable quarter last year, driven by milder weather across our Texas and Indiana service territories. Higher interest expense was $0.01 unfavorable, reflecting new issuances, slightly offset by lower commercial paper balances.

These results reinforce our confidence in delivering our full-year 2026 non-GAAP EPS guidance range of $1.89 to $1.91. The accelerated growth that Jason highlighted and the work we've done to de-risk our financing needs are additional tailwinds that further position us well to deliver as we move through the year. Over the long term, we continue to expect to grow non-GAAP EPS at the mid to high end of our 7%-9% long-term annual guidance range through 2028, and 7%-9% annually thereafter through 2035. Now, turning to a broader regulatory update. As a reminder, we recover approximately 85% of our investments through capital trackers. We continue to make progress recovering capital on customer-driven investments across our service territories. In our Houston Electric business, we recently filed our second capital tracker for distribution investments, or DCRF, requesting a $73 million increase in revenue requirement.

We expect customer delivery charges to be updated in November of this year. In addition, we also expect to file the second capital tracker related to transmission investments, or TCOS, next month. Additionally, during the quarter, we filed a settlement agreement related to our temporary generation filing that will allow us to reduce customer electric delivery charges by nearly 3% from a rate that is already more than 5% less than the next lowest Texas peer electric utility. Turning now to Texas Gas. We received approval of our annual capital investment recovery filing, or GRIP, that requested a revenue requirement increase of approximately $62 million. New rates went into effect in June.

Outside of our Texas businesses, we are preparing to file forward-looking rate cases for Minnesota Gas and a combined filing for North and South Indiana Gas by the end of this year, which together represent less than 20% of the earnings power of the company. Turning to our capital plan. We continued to execute against our planned 2026 investments, as shown on Slide 6. We invested $1.5 billion in the second quarter and have now completed approximately 40% of our planned capital spend through the first half of the year, consistent with the typical seasonal timing of our investments. We expect larger projects to be placed in service in the second half of the year and remain on track to execute $6.8 billion of planned capital investment this year for the benefit of our customers and communities.

In addition, as Jason highlighted, we are updating our 10-year capital plan from $65.5 billion-$66.7 billion, reflecting a $1.2 billion increase driven by large load system upgrades and the progress made related to the Downtown Houston Revitalization project. We expect to fund these incremental investments without issuing additional equity, supported by the existing funding capacity as a result of the clarification in the Corporate Alternative Minimum Tax rules earlier this year. As such, our planned equity remains unchanged. This lower equity profile is also supported in the near term by a recent transaction related to our Ohio Gas LDC. There, we remain on schedule to close the sale on October 1st of this year after receiving regulatory approval last month. Looking further out, we anticipate additional potential financing tailwinds from the marketing of our temporary generation units before the end of Q1 next year when the units return.

The transacting of these units could provide additional flexibility to fund incremental capital investments without increasing our equity financing guide. Lastly, as a reminder, we expect meaningfully higher cash flow from new demand charges of approximately $6 million per gigawatt per month as we energize the anticipated 14 gigawatts of new load over the next five years. Outside of today's update and potential future financing tailwinds, we will continue to target funding incremental capital investments consistent with our consolidated capital structure of approximately 47% equity and 53% debt. Lastly, I want to touch on our credit metrics and balance sheet. As of the end of the second quarter, our adjusted FFO to debt ratio, based on Moody's rating methodology, was 13.4%.

This represents a nearly 100 basis point improvement from Q1, and we anticipate continued expansion of the cushion represented here, in part due to a tax refund related to the previously paid Corporate Alternative Minimum Tax, a portion of which we anticipate to receive in the third quarter of this year. This alone could add roughly 30 basis points of improvement to our metrics. In summary, we are confident in our ability to execute this year and beyond, given anticipated future financing tailwinds and continued visibility to customer-driven growth opportunities. We are reiterating our 2026 non-GAAP earnings guidance targeting at least the midpoint of $1.89-$1.91. At the midpoint, this would represent an 8% increase over 2025 delivered results. Looking ahead, we expect to grow non-GAAP EPS at the mid to high end of our 7%-9% range from 2026 through 2028.

Over the long term, we expect to grow non-GAAP EPS at 7%-9% annually through 2035. With that, I will now turn the call over to Jason.

Thank you, Chris. In closing, we have made meaningful progress advancing the significant growth opportunities across our service territories. The progress we are making in Houston underscores the strength of our service territory and our ability to serve large load customers quickly and affordably. At the same time, the opportunities we are pursuing in Indiana represent a step change in growth, which will meaningfully drive economic development and improve customer affordability. This growth, combined with our consistent execution and proactive efforts to de-risk our regulatory profile and financing plan, increases our conviction that we have one of the most compelling affordability profiles and one of the most tangible and executable long-term growth plans in the industry.

Thanks, Jason. Operator, I'd like to turn it over for Q&A.

Thank you. At this time, we will begin taking questions. If you wish to ask a question, please press star one one on your touchtone keypad. The company requests that when you are asking a question, callers pick up their telephone handsets. Thank you. One moment for our first question. Our first question coming from the line of Shahriar Pourreza with Wells Fargo Securities. Your line is now open.

Hey, guys. Good morning. Morning, Shar.

Morning, Jason. Jason, just on the transmission study, as we're thinking about sort of the size and cash benefits, on the CapEx side, historically, you guys have referenced $8 million per mile, while I think the market range is anywhere from $5 million-$20 million, depending on routing and land. On the cash benefit side, you've talked about $6 million per gigawatt per month. Are these still kind of relevant in any sense of timing here? Thanks. Yeah. Thanks, Shar, for the question.

From a CapEx standpoint, yeah, that's generally the range we're seeing, sort of that $5 million-$20 million. Our plan assumes $8. We'll likely have a better view of the actual cost per mile in the first quarter of next year as we complete more of our route-related work. It potentially could be a tailwind as we enter next year. That's the summary on the CapEx side. From a cash flow standpoint, yes, we continue to see about $6 million a month per gigawatt in terms of cash flow from demand charges from these related customers. As you can see from the growth that we announced today, that really is growth that's significantly accelerating over 2027, 2028, and 2029. A very significant cash tailwind in those coming years.

Got it. Okay. Obviously, previously, you guys framed the CAMT benefit as kind of unlocking about $1 billion of incremental CapEx with no additional equity, and this morning you added about $1.2 billion to plan, deployable within 5 years with sort of no change on that equity guide. That's kind of the key message. Batch Zero transmission studies, et cetera, could be kind of fairly material. I guess, how should we be thinking about this funding needs or the cash benefits from these investments enough to offset those funding needs as well? Thanks. Look, we're going to always seek to most efficiently fund our CapEx growth.

I think we've got a history and track record of doing so. We're not going to lean on our balance sheet. We want to maintain a healthy cushion from an FFO to debt standpoint. We're going to continue to think creatively. I think some of the cash flow tailwinds that Chris mentioned, the opportunity to remarket the temporary generating units, the cash flows from the incremental demand charges from the Batch Zero growth are all great tailwinds as we look at incremental CapEx on the transmission side to replace this import capacity, to create more intra-regional transmission capacity, and certainly to help make stability-related investments on the transmission level.

That comprehensive transmission plan that we are updating really has a number of different elements that we can lean on to efficiently fund that growth without, as I said, unnecessarily leaning on the balance sheet.

Got it. Further asset optimization, is that part of the lever or not anymore?

We'll always look to create value for our stakeholders. If that requires asset recycling, we may consider that. As you recall, though, with the Ohio transaction that we announced, we've staged that sale with a seller note, and have sold equity forward, really eliminating any equity needs for the near future. I think we're in a good position not having to lean on asset recycling in the short term, but we'll always look to most efficiently fund our growth long term.

Got it. Perfect. Fantastic, guys. See you soon. Thank you.

Our next question coming from the line of Nicholas Campanella with Barclays. Your line is now open.

Hey, good morning. Thanks for all the updates today.

Good morning, Nick. Morning. You've kind of talked about this data center opportunity in Indiana on the last call.

Could you just give us an update on where you stand on that? If you need to invest in incremental generation for that, does that get included in this no equity comment? How should we think about that? Thank you. Yeah, I continue to remain very optimistic around the work that we're doing up in Indiana.

We're continuing to make, I think, very meaningful progress. A couple of things to point out up in Indiana. As the team has done some more work around our system, we've found the ability to unlock incremental capacity, sort of short and medium term, that gives us more optionality up there with respect to helping serve large loads. As I alluded to in my prepared remarks, we already are well underway from an engineering, ordering long lead time materials, securing our spot in the MISO queue for these connections. Really making meaningful progress, making sure that we have near-term capacity to support those opportunities. With respect to incremental generation costs, that's outside of the CapEx update today.

We will, as I said to Ashar, look to most efficiently fund any incremental CapEx increase going forward. That said, as we look at transmission-related opportunities, generation in Indiana, there's likely some equity that will be needed to support that level of incremental CapEx growth for those different CapEx drivers.

Maybe sticking with Indiana, there's been the affordability report that was issued, and I think there's going to be a conference on August 7th. Just anything that you're expecting from that broadly, what you expect that to address? Obviously, you're just maintaining the current filing path for the state on both the gas and the electric side, just to confirm? Thanks. Sure, Nick. It is true for the last part of your question that we'll maintain the current timeframe for the consolidated gas cases by the end of this calendar year.

The current timing for our electric case would be the first quarter of 2028. As you look at the technical conference that's coming up on August 7th, I think it's our current understanding you're likely to see a series of different topics referenced there really to bring about future meetings where they'll discuss those topics in more detail. For us, just stepping back, I think the key thing to remember is that our focus is on encouraging and enabling economic development for the area.

It's by far the best way to allow for ongoing affordability for our customers from the new loads that are attracted that spread the costs, help enhance the property tax base, and that really helps the community grow for the long term. We've also taken, as you know, a number of steps really in the last few years that have been affordability-focused for our customers. The first was the $50 million of O&M related to the retirement of our coal facilities up there. The second was the returns that we essentially passed back to our customers related to the securitization of the coal plant. Finally, we've had a commitment here that's very focused on keeping our electric rates stable through 2027.

Guess it's my way of saying we'll be able to contribute additional thinking for incremental ideas associated with the affordability technical conference and looking forward to the conversation.

Thanks for those thoughts. Thank you.

Our next question in queue coming from the line of Julien Dumoulin-Smith with Jefferies. Your line is now open.

Hey, good morning, Jason and team. Thank you guys very much. Appreciate the opportunity. Good morning.

Perhaps just keep it on going in the same direction that the prior questioners were. Can we kick off a little bit on the timing of the transmission update? You made allusion that later, I think you said specifically this year, you'd come back with some updates. How do you think about that against the backdrop of greater legislative scrutiny, in particular of transmission here, and how that might kick out plans into potentially 2027? If you can try to square up what we're seeing from a political perspective on both data centers and transmission of late against your commentary about coming back to update transmission. If you have any comments about the substance of anything going on in Texas vis-a-vis timing of the large loads, I'd be curious as well.

Good morning, Julien. We are excited with the growth that we announced today. As we've talked about previously and reaffirmed on this call, we intend to provide a more comprehensive transmission study update the second half of this year. Look, I think it's incredibly important to do so. We've seen more growth than was anticipated originally out of Batch Zero. We see no indication that growth is slowing here in Texas. On that point, what I want to emphasize is, outside of the Batch Zero large loads, we are seeing an uptick in interconnection requests at the distribution level. As you know, if the load request is less than 75 megawatts, it doesn't necessarily need to go through Batch Zero.

As a result, what we're seeing already year to date is 500 megawatts of distribution-related requests just below that threshold, really to help enable advanced manufacturing, more distributed inference-related data centers, energy-related, logistics-related industries. We don't see growth slowing down. To come back to the point that's being raised around a larger debate around 765 kV, I don't think that the conversation really is should Texas slow down. I think the conversation is how do we most effectively work with communities to enable this ongoing growth in a constructive manner? Obviously, we'll take a lead with state leadership in that regard. I think the state is still aligned around continued growing. We see tailwinds accelerating, not decelerating. We represent about two and a half % of the geography of Texas, 25% of the electric demand today.

That's only growing, we need more import capacity. Again, we will happily support the direction the state heads and the way to most efficiently support that continued economic growth. We'll put our updated transmission study out in the second half of this year and engage to follow the direction of the state on how to enable that. As I think as it relates to this overall large loads in Texas, look, our focus is on enabling our customers, here in the Greater Houston region. We feel like we are in a unique position having had 10 gigawatts of existing capacity on our transmission system. We could move quickly. I think that was a differentiator.

During this ERCOT Batch process, we could, with modest incremental capital investments, unlock another 4 gigawatts, which is the 14 gigs that we think will be eligible for Batch Zero that we've identified today. Look, as I said, it's not slowing down. Back to the original question, that's why we need to continue to rebuild transmission capacity to support the next round of growth.

Awesome, guys. Thank you. Just a quick clarification in terms of financing and financing latitude. You particularly provide the sensitivity about what large loads can do in terms of incremental revenues. Can you just clarify how much of that latitude is reflected in this updated plan here? Just how much of it are you, quote, "using" and reflecting in the outlook, inasmuch as that's a pretty meaningful quantum of incremental revenues to come from large loads, especially as the large loads themselves accelerate. Obviously, I think to be very clear, that comes in tandem with the mobile Gen cash flow uptick that is not reflected in the outlook still as well, right? There's several different buckets that are not reflected.

Sure, Julien. That's correct. Maybe there's probably a third category I would add too, the short answer is we have not yet folded in the benefit from the demand charges from these large customer loads. It's also true that we've not yet folded in benefit from resolving the potential transaction related to the temporary generation units. We've indicated there we'll certainly have insight ahead of the end of Q1 timeframe when those units do come back. The third one I would just emphasize, again, this is more near term, it's the likely prior historical recovery of the additional Corporate Alternative Minimum Tax amount that would likely come through in 2027. Those are the three components all representing tailwinds to the plan.

Yes, precisely. All of the incremental large loads, not reflected. We'll see when you provide that comprehensive update. Thank you guys very much. All the best. Thank you.

Thank you. Our next question coming from the line of Steve Fleishman with Wolfe Research. Your line is now open.

Yeah. Hi, good morning. Morning, Steve.

Just on the Indiana customer, will there be ability to get more visibility on that by the end of this year, both in terms of investment opportunity and also the potential savings for customers?

Yeah, Steve, we'd certainly like to give a more definitive update before the end of this calendar year. We continue to work and make progress. We'd love to be in a position before the end of the calendar year to give that update. Obviously, these things just take a little bit of time. As we've talked about, we are already working on advancing the actual work for the interconnections and we hope to provide a more comprehensive, definitive announcement before the end of the year. As we've already announced, we believe that at least the initial level of demand in Indiana could support about $250 million of residential customer savings over the next 15 years. As we look to work with multiple parties, hopefully we can continue to expand on that and give even more customer benefit down the road.

Continuing to work it, hopefully we'll have this finalized before the end of the calendar year.

Okay. Maybe in Texas, just to make sure I've got the growth right, the 65% that you talk about of growth, is that just from the large load and that does not include the growth coming from distribution-level customers?

That's right, Steve. This is just batch zero, and does not include what we would see from distribution-level customers. As I've indicated, we're actually seeing an uptick in distribution-level demand, so growth will be well north of this. We just wanted to provide the batch zero update given the process is concluding here this summer.

Okay, great. Thank you. Thanks, Steve.

Thank you. Our next question coming from the line of Jeremy Tonet with JPMorgan. Your line is now open.

Hi, good morning. Morning, Jeremy.

Just wanted to come back. I think you had talked about earlier, in Texas, $5 billion of customer savings for the 14 gigawatts Batch Zero, I think there. I was just curious, I guess, if you could expand on that a little bit more. What does that look like for annual monthly savings? Just wondering, I guess, how this influences the tone of conversations with stakeholders.

Sure, Jeremy, I can help unpack that for you. If you look at just the rule of thumb on this, it's 14 gigawatts as we've referenced in base load and studied load. From that, again, the key thing to keep in mind here and why it's important from an affordability standpoint is that these large load customers would basically absorb the cost of the system, That would reduce cost for our residential and small commercial customers. If you just do the math on it, roughly 14 gigawatts is around $800 million of revenue requirement. You multiply that by the number of industrial and commercial customers we've got, so 65%, takes you to that just over $500 million a year times 10 years gets you to the $5 billion of savings statewide for our customers.

Hopefully that helps give you the color there and why it is not only impactful from a customer bill standpoint, it is also the localized benefit that can occur in some of these communities as it relates to property tax benefits and other benefits as well.

Got it. Thank you for that. Then maybe same question towards Indiana. I think you referenced beyond the initial large load customer, the potential for more in the future here, and just wondering, I guess, if economic development and affordability are top of mind in Indiana and, given this large potential here, that could hit on both. Just wondering how that impacts stakeholder conversations across the state.

Yeah. I think in both states, both Indiana and Texas, there is alignment at state leadership level through the local level that continued economic development is the path to the strongest customer affordability profile that we can provide. There is no better case study than what we are seeing here in Texas with the growth in Houston, effectively keeping rates essentially flat for over a decade. Indiana has not seen the level of growth that Texas has, state leadership understands the opportunities that sit in front of us, and we are all working both at the state, local, and utility level to deliver economic growth for our customers and our communities. It is clearly the path that keeps rates more affordable for our customers over the long term. I think it is well understood, as I said, in both states.

Should sufficient demand materialize in Indiana as such, I guess how would that influence your thoughts on the potential for a GenCo, and whether that would be worthwhile and beneficial to all stakeholders?

As we said in the past around the GenCo structure, I think it's a very innovative structure. It wasn't necessarily needed for us if we're talking about serving 1.5 gigs or less. We have that incremental capacity in our system without significant generation investment on our side. As we work with multiple customers in that region and demand may exceed that one and a half gigawatts I think the GenCo structure could be something that we pursue.

Our focus right now is landing the large load customers and again, if it exceeds that one and a half gigawatts, we may pursue a GenCo structure down the road.

Got it. Understood. Helpful. Thank you very much.

Thank you. Our next question coming from the line of Richard Sunderland with Truist Securities. Yelena Malfin. Hey, good morning, and thank you for the time today.

I'll stick with the Indiana side for now. Could you parse a little bit more around that short and medium-term capacity unlock reference in the script? Would that all be for the benefit of the first customer, or is that accelerating discussions with a potential second customer opportunity? I guess I'm curious how that element specifically is impacting conversations overall.

More the latter in terms of unlocking multiple conversations with customers that would generally follow a similar timeline in terms of interconnections. It's capacity that exists. We want to serve and land large loads to help support economic development. If it's one customer, and one customer is interested in that capacity, that is great. If it's multiple customers, that is also great. Our focus is in ensuring that capacity is utilized. Right now it has unlocked multiple customer conversations, but we're just looking to do the right thing for the community and land those large loads.

That's helpful color there. Turning back to Texas, there were some discussions throughout around kind of the 765 kV efforts, and I think you said working with communities to enable this growth is what you see as a focus. How do you see that backdrop and that overlay impacting your routing work right now and the potential outcome of that routing update on 1Q? Are you thinking about the routing work in any different fashion? Any other thoughts there would be helpful. Thank you. Yeah, absolutely. We're thinking about the routing in a different way.

We've been on the front end of engaging communities in a different manner. Webinars to pre-soak the idea of these projects, working with elected officials on the basis for these, the potential routes, narrowing the number of routes that we'll propose to limit the impact to landowners to obviously the town halls and workshops that we have. We really want to work constructively in these communities, demonstrating the value, the local benefits of the construction and ongoing property tax work. We want to work with the landowners to find optimal routes that create the least amount of disruption. We have taken a very community-centric approach as we've started to embark on the routing work that will be finalized, as I said, sometime in the first quarter next year.

Great. Thanks for all that.

Thank you. Our next question coming from the line of Sophie Karp with KeyBank. Yelena Malfin. Hi, good morning, and thank you for taking my question.

To go back to Indiana, I guess, are you thinking that you will be able to show customer benefits in some tangible way when you have your first customer there signed up? Will that come later as an offset to future capital needs as you begin to add to your rate base there to service those customers?

Good morning, Sophie, and thanks for the question. No, we'll begin to be able to show immediate customer benefits because we have existing capacity on our system today.

that once we interconnect a large load, will start to be absorbed by that new large load customer as opposed to by our existing.

customers. It doesn't require significant incremental investment down the road to unlock that customer savings.

It's immediate as we get the large load online.

Right. Will that flow as bill credits or just as a reduced bill, I guess? I'm just trying to understand how visible will that be for ratepayers.

It's more the latter. It offsets.

Got you. Got it. Okay. Just on the timeline of Batch Zero process and the interconnection of all these projects, what do you anticipate in terms of the timeline? I guess I don't want to put the words in your mouth. In terms of how long until shovels go into the ground from this? There can be so many administrative and permitting delays, I'm just kind of curious to see what the anticipated timeline is from paper here into shovels in the ground.

We've got work well underway. As we've indicated here on one of our slides, we're anticipating connecting three gigawatts in 2027. That work is underway from construction, as you said, shovels in the ground out in the field. As it relates to the work on 2028, we're well down the road in the engineering. We've secured long lead time material. That work will begin here shortly. In terms of what we're looking for, on August seventh, we should have confirmation of the gigawatts that are in base load. I think that will start in earnest the field construction work, really beginning site preparation, civil work, et cetera. There will be some of the Batch Zero studied load projects that will likely want to understand the amount of energy they're allocated, which won't be finalized until April 2027.

Some of those projects, as a result, may be delayed from a construction standpoint. At this point, just given this compressed timeline of the majority of this coming online before the end of the decade, we are starting engineering. We have secured long lead time materials, we're ready to begin construction when the customer gives us notification to advance.

All right. Thank you so much. Appreciate the comment. Thank you.

Thank you. Last question will come from the line of Anthony Crowdell with Mizuho Group. Your line is now open.

Hey, good morning, team. Just a follow-up to Sophie's question, then another question. Just on the Batch Zero process, for the customers that don't get selected, maybe they applied, they thought they were going to get selected, they, for whatever reason, didn't qualify. Is there an appeal process for them, and does that have the potential to maybe slow anything down?

Yeah. Thanks, Anthony, for the question. As we've indicated here, we have three gigawatts of very viable projects that would like to move forward. Submitted their studies. Unfortunately, those studies were not approved by ERCOT. That's why we haven't classified them as either base load or studied load. We continue to advocate on behalf of those customers. Those customers continue to advocate. The good faith exemption that ERCOT announced is not necessarily oriented towards addressing those customers who have not had a study approved by ERCOT. This is very meaningful growth for our communities, and we will continue to work with ERCOT, our customers, to advocate to find a path to energization. It's just at this point, it's unclear what that path exactly looks like.

Great. I know Chris gets upset when he doesn't get a question. Just, Chris, the credit cushion's getting larger, but the Moody's outlook remains negative. Just curious on your conversation with the agency of any timing or timeframe of maybe when they give an update or just any latest conversation with the agency.

Well, thank you, Anthony, for the question. Short of it is, you're right. When we came through Q1, we had mentioned that we were going to be relatively light on FFO debt. We've spent time with Moody's on that. We've been through really all the key issues that they wanted to see progress on. I really do think it's meaningful that we delivered almost 100 basis points of improvement quarter-over-quarter here, and that cushion's only going to grow. Again, keep in mind, I referenced, and we've spent time with Moody's on this. We referenced roughly 30 basis points of improvement that's coming here in Q3 alone that wasn't previously in plan, related to that Corporate Alternative Minimum Tax amount. In short, confident we'll be able to make progress. I can't certainly give specific timing for Moody's, but here relatively soon.

Thank you. I am showing no further questions at this time. Ladies and gentlemen, this concludes CenterPoint Energy's second quarter 2026 earnings conference call. Thank you for your participation, and you may now disconnect.