Earnings Call Transcript - CNP Q1 2026

Operator, Operator

Good morning, and welcome to CenterPoint Energy's First Quarter 2026 Earnings Conference Call with Senior Management. Operator provided instructions regarding the conference call procedures and how participants may queue for questions. I will now turn the call over to Ben Vallejo, Vice President of Investor Relations and Corporate Planning. Please go ahead.

Ben Vallejo, Vice President, Investor Relations and Corporate Planning

Good morning, and welcome to CenterPoint's Q1 2026 Earnings Conference Call. Jason Wells, our Chair and CEO; and Chris Foster, our CFO, will discuss the company's first 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 statements other than as required under applicable securities laws. We reported $0.48 per diluted share for the first 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 a reconciliation of the non-GAAP measures used in providing guidance, please refer to our earnings news release and presentation on our website. We use our website to announce material information. This call is being recorded. Information on how to access the replay can be found on our website. Now I'd like to turn it over to Jason.

Jason Wells, Chair and CEO

Thank you, Ben, and good morning, everyone. On today's call, I'd like to address four key areas of focus for the quarter. First, I'll walk through our strong first quarter financial results. Second, I'll provide an update on our load outlook for Houston Electric, including yet another significant increase in our firmly committed load forecast to 12.2 gigawatts of new industrial load. Third, I will cover how our continued and accelerating growth in the greater Houston area provides incremental capital investment opportunities and further supports customer affordability. And lastly, I'll touch on our growing optimism for transformational load growth opportunities for our Indiana electric service territory, which would similarly provide for incremental capital investment and support customer affordability. I will start with our strong first quarter financial results. This morning, we reported non-GAAP EPS of $0.56 for the first quarter of 2026. Chris will walk through the details of these results, but I want to highlight that our execution through the first quarter positions us well for the remainder of the year. With that said, we are reiterating our full year 2026 non-GAAP EPS guidance of $1.89 to $1.91, which, at the midpoint, would represent 8% growth over actual 2025 delivered results. As a reminder, we rebase our long-term earnings guidance from each year's actual results. This approach provides our investors with the direct benefit from the compounding effect of the earnings we have consistently delivered. In addition, this approach helps contribute to the durability of our earnings profile, underscoring our commitment to delivering value through disciplined execution and sustained growth 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% to 9% annual guidance range through 2028 and 7% to 9% annually thereafter through 2035. I would now like to provide an update on the accelerating growth our Houston Electric business continues to experience and our strong execution, which enables us to take advantage of the growth in the near term. As we shared on the fourth quarter call, we have meaningfully accelerated our load growth outlook, bringing forward our forecast for a 50% increase in peak demand by a full two years. Our conviction in that accelerated timeline was grounded in 7.5 gigawatts, a firmly committed load that we expected to be energized by 2029, including 2.5 gigawatts that was already under construction as of our last update. Since then, we have made significant progress in executing against our prior forecast, while adding additional customers. As a result, we now have clear line of sight to 12.2 gigawatts of firmly committed load. With the team's disciplined execution, we have already secured ERCOT approval for 3.2 gigawatts of this load. 2.5 gigawatts was approved since our last earnings call alone and within less than 80 days of filing for approval. We expect to submit the remaining 9 gigawatts of projects to ERCOT for approval within the next few weeks. Importantly, this firmly committed load is highly diversified, spanning more than a dozen unique customers across nearly 20 distinct projects. We believe these projects are manageable in size with 90% representing 0.5 gigawatt of demand or less. That, along with our utilization of existing capacity and our customer selection of project sites near substations, allows for quick and efficient interconnections. Our focused execution over the last few months has also provided us with a clear path to energization. Notably, we are positioned to energize approximately 8 gigawatts of this firmly committed load by 2029, which is 80% of our 10 gigawatt increase we originally forecasted to be energized by the end of 2031. This diversified growth and economic development has another key benefit to the Greater Houston area, which helps us keep electricity delivery charges affordable. The Greater Houston area is no longer an emerging destination to site new data centers. It is now firmly established as a location of choice for some of the world's largest hyperscalers and developers. However, this is only one facet of Houston's multidimensional growth. The region's growth is being propelled by significant investments in life sciences, energy, energy exports and advanced manufacturing. With this growth comes new jobs and an influx of new residents, which has fueled a 2% annual residential growth the area has experienced for the last few decades. The expansion of the economy and increase in population have significant affordability benefits for our customers. Notably, we expect that utilizing 10 gigawatts of existing system capacity will provide approximately $4 billion in aggregate savings for Texas residential and commercial customers over the next 10 years, supporting affordability and creating headroom for future customer-driven investments. This affordability profile is one that very few areas in the country can offer as our charges are 11% below the national average and the lowest in ERCOT. Looking ahead, we believe this growth will continue for years to come, requiring the further expansion of our system to support growth beyond the near term. We are making steady progress on a refreshed load study that will inform our transmission planning process, and we expect to complete the study later this year. In Indiana, we are increasingly confident in our ability to secure potentially transformational opportunities to support local economic growth and address affordability. We continue to make considerable progress in our conversations with a large load customer on a project that would represent our single largest load in our Southern Indiana service territory with substantial upside for additional growth. Beyond the significant economic development benefits this opportunity would bring to the local community, it represents a powerful lever to enhance affordability for our customers. We estimate that this initial incremental load could enable $250 million in savings to our residential customers over 15 years, meaningfully reducing customer bills with the opportunity for even greater savings as potential upside for growth materializes. In closing, we continue to believe we have one of the most tangible and executable long-term growth plans in the industry. We are uniquely positioned to move at the speed of business to execute on near-term customer-driven opportunities while also delivering our service affordably. We are laser-focused on making longer-term investments to enhance growth across all of our service territories while also improving customer outcomes. With that, I'll turn it over to Chris to cover the financials in more detail.

Christopher Foster, Chief Financial Officer

Thanks, Jason. This morning, I will cover four areas of focus. First, the details of our strong first quarter financial results and how they position us for the rest of the year. Second, I'll provide a brief regulatory update and our progress with respect to timely recovery of our capital investments through the filing of our interim capital trackers. Third, I will touch on our planned capital deployment in 2026, which is right on track as we target to invest $6.8 billion this year for the benefit of our customers and communities. And finally, I will provide an update on our derisked financing plan, balance sheet health and credit metrics. Now starting with our strong financial results on Slide 6. On a GAAP EPS basis, we reported $0.48 for the first quarter of 2026. On a non-GAAP EPS basis, we reported $0.56 for the quarter. Our non-GAAP EPS excludes the impacts from the tax gain and other expenses related to the sale of our Ohio LDC, which is on track to close in the fourth quarter of this year. 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 expect to start marketing these units for either a sublease or sale later this year in anticipation of getting those units back no later than spring of next year. Taking a closer look at the drivers of our first quarter earnings. Growth in rate recovery contributed $0.11 when compared to the same quarter last year, driven by a full quarter impact of updated rates, reflecting the interim filing mechanisms that went into effect late last year. Weather and usage were $0.02 unfavorable when compared to the comparable quarter last year, driven by milder weather across our Texas and Indiana service territories. Additionally, higher interest expense was $0.04 unfavorable, reflecting new issuances, slightly offset by lower commercial paper balances and favorable pricing on the convertible debt we issued during the quarter. O&M was flat for the quarter as we continue to accelerate our peer-leading vegetation management program to enhance the customer experience and improve customer outcomes during severe weather events. Lastly, the absence of earnings from our Louisiana and Mississippi businesses post divestiture resulted in $0.05 of unfavorability when compared to the first quarter of 2025. The divested rate base has already been replaced by the acceleration of investments in our Texas businesses. These results reinforce our confidence in delivering on 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 derisk our financing needs and more efficiently execute are additional tailwinds that further position us well to deliver and could continue to provide upside 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% to 9% long-term annual guidance range through 2028 and 7% to 9% annually thereafter through 2035. Now turning to a broader regulatory update. As a reminder, we continue to recover approximately 85% of our investments through capital trackers, several of which we filed this quarter. I'll start with Houston Electric. In February, we submitted the first of our two permitted filings of our Distribution Capital Recovery Factor, or DCRF, and our Transmission Cost of Service tracker or TCOS. The DCRF filing requested a revenue requirement increase of approximately $108 million, capturing incremental distribution investments over the last six months. I'm pleased to share that we entered into a settlement agreement earlier this month and requested new rates to be effective in June, ahead of our planned timing. The TCOS filing requested a revenue requirement increase of approximately $36 million, incorporating transmission investments made between July and December of last year. During this quarter, the filing was approved and new rates went into effect just last week. Turning now to Texas Gas. In February, we also filed our annual capital investment recovery mechanism, or GRIP, requesting a revenue requirement increase of approximately $62 million, capturing capital investments made through 2025. Pending approval, we expect these investments to be reflected in customer rates in June. Lastly, as a reminder, we plan to file rate case applications for our gas businesses in Minnesota and Indiana later this year, which in the aggregate represent less than 20% of the earnings power of our consolidated base. Next, I will touch on our continued execution against our planned capital investments for 2026 as shown on Slide 7. We invested $1.2 billion in the first quarter for the benefit of our customers and communities. The quantum of capital deployed in the first quarter is consistent with the seasonal timing of our capital plan as we expect larger construction and resiliency projects to ramp throughout the year. In short, we remain firmly on track to execute the $6.8 billion of planned work this year as we continue to make investments to strengthen our system, improve customer outcomes and build the most resilient coastal grid and safest gas systems in the nation. Beyond our base 10-year $65.5 billion plan, we will continue to fold in the over $10 billion of incremental capital investment opportunities as we gain better clarity on project costs currently embedded in our plan, as well as line of sight to new projects required to meet the unprecedented load growth across our service territories. In addition, we'll potentially discover more capital investment opportunities as we refresh our transmission planning later this year, which we are targeting to complete in the second half of this year. These additional investments will continue to provide upside to our over $65 billion base plan through 2035, further increasing the earnings power of the company. Lastly, I want to touch on our credit metrics and balance sheet. As of the end of the first quarter, our adjusted FFO to debt ratio based on Moody's rating methodology was 12.5%. This metric reflects temporary timing pressure from opportunistically pulling forward planned debt issuances in the quarter to take advantage of attractive market conditions. As that capital is deployed and financing normalizes, we expect this impact to reverse over the course of the year. And as a reminder, we expect to end the year at the high end of our targeted cushion in light of the corporate AMT revised guidance. Importantly, we have filed for a refund of some of the previously paid cash taxes and expect to receive a refund later this year. We expect to incorporate the impacts of this favorable guidance into our financing plan later this year. Overall, from a financing standpoint, we have completed nearly 70% of our planned 2026 financing needs, significantly derisking this year's financing plan. I also want to highlight that the $650 million convertible debt issuances we executed in February have allowed us to reduce near-term exposure to floating interest rates. I would like to highlight that our commercial paper balance at the parent at the end of the first quarter was 0 compared to our normal average balance of approximately $1 billion. In summary, we are confident in our ability to execute in the near term and beyond given the derisked nature of our plan. We are reiterating our 2026 non-GAAP earnings guidance targeting at least the midpoint of $1.89 to $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% to 9% range from 2026 through 2028. And over the long term, we expect to grow non-GAAP EPS at 7% to 9% annually through 2035. We remain committed to investing to improve customer outcomes and enabling growth across the states that we have the privilege to serve. And with that, I'll now turn the call over to Jason.

Jason Wells, Chair and CEO

Thank you, Chris. In closing, with our focus on disciplined execution, we have made meaningful progress in enabling more growth faster — particularly in our Houston and Indiana electric service territories. We believe that our ability to attract and serve large load customers will unlock the potential to transform the communities we have the privilege to serve. This growth, combined with our delivery of strong and consistent results and our proactive efforts to significantly derisk 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.

Ben Vallejo, Vice President, Investor Relations and Corporate Planning

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

Operator, Operator

Operator provided instructions for the question-and-answer session. Our first question is coming from the line of Shahriar Pourreza with Wells Fargo Securities.

Shahriar Pourreza, Analyst, Wells Fargo Securities

Just first, there's obviously more specificity around the Houston Electric load, including the 12 gigawatts of firmly committed demand and the 8 gigawatts of data center load expected online by 2029. Can you just help us bridge how much of that committed load is already embedded in the current plan versus what could represent incremental upside? And of the projects not embedded, I guess what are the gating items to include it in plant?

Jason Wells, Chair and CEO

Thanks for the question, Shahriar. The model in ERCOT is a little bit different than the rest of the country. We just provide transmission and distribution service. From a CapEx standpoint, the incremental system modifications, switchyards and substations that are needed to connect these customers timely are paid for by the large load customer. So I wouldn't look at this as necessarily a direct impact to the CapEx plan. There are two tailwinds to the financial plan that I think are important. The first is despite the fact that there is not significant CapEx — again, the customer is paying for the modifications in the interconnection — it does represent a significant amount of incremental demand charges. Probably the way to think about this is for every 1 gigawatt of industrial load that we add to our system, it's about $6 million a month of incremental demand charges. So that provides a pretty significant tailwind both from an earnings standpoint but also a customer affordability benefit. And then indirectly related to CapEx is the need to replace that capacity on the system. That's what we've been highlighting in terms of the work we're doing right now. That will result in the second half of this year in incremental projects to effectively replace the capacity and make sure the system is able to accommodate future load growth. So again, I wouldn't think about the 12 gigawatts of firmly committed load as directly driving CapEx. What it does is it directly drives demand charges that are outside of the plan. So that's a tailwind from an earnings and an affordability standpoint, and then indirectly supports the need for future CapEx that we will roll into the plan later this year.

Shahriar Pourreza, Analyst, Wells Fargo Securities

Got it. Got it. And then just correlated to the first question, with ERCOT's new preliminary long-term forecast that projects now about 278 gigawatts of total demand by 2029 and $3.68 by 2032, but both ERCOT and the PUCT have indicated that those forecasts likely overstate. Remind us how you're using this in your planning process? Should we think about it as mostly supportive of Houston's growth or as something that could ultimately drive incremental wires investment above what is already embedded in your current plan through 2026?

Jason Wells, Chair and CEO

Yes. As we've highlighted on previous calls and what you've seen in our ERCOT submissions, we are much more disciplined in terms of load that we submit to ERCOT for planning purposes. The load that we submitted to ERCOT in this most recent study was effectively consistent with the load that we have under construction. We submitted about 3.6 gigawatts, and as we're reporting today, we have 3.5 gigawatts that we're actively under construction or committing. We will be filing with ERCOT, as I said, another 9 gigawatts in the coming couple of weeks. From a CapEx standpoint, again, I think the real opportunity here is replacing the capacity for future growth. In the second half of this year, you'll see an update from us where we articulate the new projects that will be needed to support future growth and the dollars associated with those. I think this continues to be a tailwind for the continued buildout of the 765 kV system on more of a medium- to longer-term horizon. So again, the growth is fantastic and the fact that it provides significant customer affordability benefits by effectively spreading the fixed cost of our system out over a much larger customer base provides near-term opportunities for earnings from incremental demand charges and then sets us up for incremental transmission projects that likely will need to be executed before the end of the decade and again supports the buildout of the 765 kV system early into the next decade.

Operator, Operator

Our next question is coming from the line of Steven Fleishman with Wolfe Research.

Steven Fleishman, Analyst, Wolfe Research

Just wanted to go to the commentary on Indiana, and it sounds like things are maybe getting closer there. Could you talk to — I think you've talked in the past about the potential to turn your CT into a CCGT? And I don't know if there are other investments if you were to land this customer. Could you give us some sense of the investment opportunity there, both physically and then also in dollars?

Jason Wells, Chair and CEO

Yes, absolutely, Steven, happy to provide that color. So if you've looked at the MISO queue, we have a transmission project that we've filed for to provide incremental capacity in that region. In our integrated resource plan filing that we recently filed with the commission, we've got a scenario that supports the potential for a large load customer. Effectively, we've got existing capacity on our system today. We can enhance that with the new transmission investments that are articulated in that MISO queue. We can also then, as you mentioned, provide incremental capacity by converting our simple cycle to a combined cycle facility up there. All of that unlocks at least 1.5 gigawatts of incremental capacity for a large load customer because we have existing capacity and because we have the simple cycle plant already. I would think about this as more around a $1 billion opportunity as opposed to several billion dollars just to put some scale around the incremental CapEx. Again, this is an incredible opportunity for our customers up in that region. It allows us to provide customer affordability benefits that will be significant. It will provide incremental earnings from those sales and it will provide tailwinds around about $1 billion of incremental CapEx. Outside of that initial 1.5 gigawatts, we are continuing to evaluate the opportunity to support future large load customers and that could result in even more incremental CapEx down the road.

Steven Fleishman, Analyst, Wolfe Research

Would the $1 billion opportunity be kind of by 2030 or after 2030?

Jason Wells, Chair and CEO

Yes, definitely within '27, '28 and '29.

Steven Fleishman, Analyst, Wolfe Research

Okay. And then I guess just on the ERCOT numbers — I just want to clarify on the ERCOT reported demand number last week. Your numbers for your territory within that, are they consistent with what we heard today? Or is there a bigger number based on however the data were given to them that matches up with their total number?

Jason Wells, Chair and CEO

Yes. Our total submission as part of that process for large loads was roughly 4 gigawatts. That was included in those reported tables. That effectively were the large load customers that we were currently and actively constructing transmission modifications and interconnection facilities for. Outside of the number that was picked up on that table, we also filed a large load study that incorporated continued residential growth and the potential for large load customers. That was a little bit more than 11 gigawatts. Those weren't picked up in ERCOT's numbers, but were filed with ERCOT. Today, what we're doing is updating those numbers. So this is in excess of what ERCOT just reported. Given the methodology that ERCOT asked us to submit the customers under, the 9 gigawatts that we will be filing for in a couple of weeks didn't meet that criteria earlier this year. But certainly, we made a significant amount of progress on these 9 gigawatts in recent months; they meet all of the related commitments under the batching process for ERCOT, and we feel confident our committed load is firmly to be load customers. So this is an incremental amount to what was reported by ERCOT.

Operator, Operator

Our next question is coming from the line of Richard Sunderland with Truist Securities.

Richard Sunderland, Analyst, Truist Securities

Just circling back to this transmission commentary, I want to understand what you're studying for that second-half update. It sounds like the transmission need is all this decade. Could you maybe frame what's in flight now and what it's doing for capacity that's being utilized by this new load and what that might mean for this next batch of transmission out of the study? I'm just trying to think about total dollars that might come this decade that aren't reflected in the plan right now.

Jason Wells, Chair and CEO

Yes. As we've been talking about on previous earnings calls, I think the most important aspect to focus on for large load is existing hosting capacity. These large load customers need to connect in and be served timely. For us, we have existing capacity on our system of roughly 10 gigawatts. We also have about 9 gigawatts of generation that wants to connect to our system here in Houston. We're using that capacity to satisfy those customers that we talked about today. Part of the transmission plan that we have outlined in our $65 billion includes projects to make sure that we have the existing capacity where we need it. So think about that as intra-regional investments to move power around the greater Houston region. Also in the $65-plus billion CapEx plan, we have increased import capacity, primarily through the 765 kV lines that really will start to come online in '31 and '32. This transmission study that we've been alluding to really seeks to fill a gap around '29, '30 and '31, where we see existing capacity being exhausted and before those new 765 kV projects provide incremental import capacity. So it will be increasing our capacity at the tail end of this decade and then there will be incremental projects to move this load around the Houston region to where it's needed. And there will likely be system stability investments to make sure that the system can accommodate the number of large load customers that are being proposed here. So it should be a fairly significant set of new transmission projects that we'll be able to highlight in the second half of this year.

Richard Sunderland, Analyst, Truist Securities

Understood. That's very helpful commentary. And then I realize the temporary generation units were briefly referenced in the script, but just thinking high level here with all of this load commentary you've been offering today, how are you thinking about the market opportunity around those units as it stands now versus, say, a year ago?

Christopher Foster, Chief Financial Officer

Sure. We are in the market actually on some of the smaller units at this stage and already seeing very strong market receptivity. As you can imagine, when we first took these units under lease, this was back in 2021. So you can imagine just how much demand has changed since then. So we're really seeing directionally almost double the original lease rates that we had in place. So the way to think about this at a high level for those larger units, as you know, those are currently serving the San Antonio area. At this stage, the back-end date when they return to the company from when we could start to market those units would be by the end of March 2027. So at this point, our focus would be on getting ready, being prepared ahead of that to make sure that we can take advantage of what would probably be a cash upside to the company's plan.

Operator, Operator

Our next question is coming from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet, Analyst, JPMorgan

Just wanted to kind of go to the credit side, if I could. Could you expand a bit more on the timing and trajectory of the credit metrics here and how you expect to exit 2026 at this time?

Christopher Foster, Chief Financial Officer

Sure thing. This is purely a function of timing. So we're still highly confident that we will end the year at the high end of the cushion that we talk about relative to the Moody's methodology. So it's 150 basis points of cushion. And the why behind that is a couple of things. First, from a timing perspective, we pulled forward a substantial amount of debt issuances in the plan. So now we've got 70% of our planned 2026 financing needs taken care of. The other attribute I would remind you of is just that — just before our prior earnings call, there was a treasury related announcement associated with the corporate alternative minimum tax. There, there's a very good outcome, right? We'll have the opportunity to no longer be a cash taxpayer, which was previously on the order of roughly $150 million a year. So we'll get that benefit in the form of a refund that will occur here in the next few months. Beyond that, what I think is also less appreciated is that we will also pursue some prior period recoveries, which would allow for even more cash improvement once we see those refunds. So those elements really give us good confidence that at year-end again, we will be at the high end of that range.

Jeremy Tonet, Analyst, JPMorgan

Got it. That's very helpful. And I just wanted to expand the conversation a little bit. A lot has been talked about data centers here. But just wondering if you could talk a bit more on traditional large load drivers in the Gulf Coast and Houston area, and maybe how you see that trending?

Jason Wells, Chair and CEO

Absolutely. I think a lot of this has been oriented to data centers, but really when we talk about the large load customer updates today, it includes both advanced manufacturing and data centers. As you know, as we've talked about on previous calls, Houston is becoming kind of an epicenter for advanced manufacturing, basically manufacturing almost the entirety of the equipment, except for the chips that are going into these data centers. There's also advanced manufacturing on the life sciences front. These types of facilities are heavy users of electricity and power; they themselves run their own data centers to tune their advanced manufacturing facilities. So while it's not just data centers for the market, these facilities are heavy users of electricity for their function. We see this growth really driven by advanced manufacturing and data centers. We continue to see significant activity on the energy and energy export side of things. I want to continue to underscore the diversity of economic and load growth drivers that set this region apart. We don't see any slowdown in any of the large industries that are propelling Houston's economic development.

Operator, Operator

Our next question is coming from the line of Bill Appicelli with UBS.

William Appicelli, Analyst, UBS

Just a question on the batch study review process or COD. Maybe you could just expand on how the firm load commitments you guys have fit within that framework that they are in the process of reviewing?

Jason Wells, Chair and CEO

Yes. As I mentioned, we've got about 3.2 gigawatts already approved through the ERCOT process that will likely show and qualify for the baseline construct. The 9 gigawatts that we're filing for will likely qualify for batch 0. There's effectively two load studies that we have to have approved by ERCOT to qualify for batch 0; one of those two needs to be approved to the steady state load study. We're on track to have those submitted to ERCOT in a time period that would allow ERCOT to approve those to be included in batch 0. As I've mentioned, we have had very successful approvals of our previous submissions anywhere from 55 days to just under 80 days. Outside of the interconnection and load studies that are required, the customers here have the land, they're prepared and ready to pay all of the associated fees. We have the equipment — all of the long lead-time equipment, in particular for us, the high voltage breakers and transformers. The customers that will actually utilize the power are signed up. So we have all of the definitions that are required to be either baseline or batch 0 customers.

William Appicelli, Analyst, UBS

Okay. And then shifting gears a little bit, what are you guys seeing in terms of the penetration of battery storage in your service territory and what kind of impact is that having from your view? I know you're responsible on the T&D side, but just curious — you've seen a big uptick in storage in ERCOT broadly. What are the impacts and the outlook there?

Jason Wells, Chair and CEO

It has been a significant level of battery investment in the state that has changed the summer peak pricing in the ERCOT market as batteries have helped smooth the summer peak demand. What we see going forward, from our vantage point, is we have about 9 gigawatts of incremental generation that is connecting to our Greater Houston region, and much of that is solar and batteries. We continue to see a high degree of interest for solar projects to qualify for tax credits before they expire. As a result, most of these projects are co-locating batteries. We continue to see batteries as effectively a tailwind to keeping energy costs low for customers for at least the next couple of years. Then we know that there are some incremental gas developments that will really help after the tax credits expire and potentially we see a slowdown in the solar and battery build-out as we approach the end of the decade. So we believe that generation will be there for this growth. Battery will help moderate the cost of electricity for customers, and we continue to see a robust pipeline connecting to the system over the next two years.

Operator, Operator

Our next question is coming from the line of Anthony Crowdell with Mizuho Group.

Anthony Crowdell, Analyst, Mizuho Securities

I know Julian does three calls at once, so he's probably a little tied up. When I look at Slide 4, you talk about the 8 gigawatts of data center load expected to be energized by 2029. Is that the same 8 gigawatts that in the fourth quarter slide deck you guys were focused on getting on by year-end 2028? My question is: is that load getting pushed back a year, or is it not an apples-to-apples comparison?

Christopher Foster, Chief Financial Officer

Anthony, let me clarify for you. In the prior quarter, we had talked about 7.5 gigawatts. That number is now going to 8 gigawatts, and it's by the end of 2028 is the way to think about it. So apples-to-apples, that's the number from 7.5 to 8. What we provided this morning, though, is that the firmly committed top-line number is actually going to 12.2 gigawatts.

Anthony Crowdell, Analyst, Mizuho Securities

Perfect. Great. And then lastly, you talked about filing Minnesota and Indiana gas cases later this year. Is it just infrastructure investment that's driving that filing or anything else in those filings?

Christopher Foster, Chief Financial Officer

Sure. Pretty straightforward. It's really about replacement CapEx in Minnesota on a straightforward program to focus on safety and reliability. As it relates to Indiana, we are focused on affordability. In particular, we are evaluating actually combining what are currently two gas rate cases up there into one, which we would likely file in Q4 of this year. By combining the cases, we're likely to see a customer bill benefit explicitly for those customers that we serve in southwest Indiana as a result of the cost allocation changes. So anticipate both of those for Q4 of this year — both Minnesota and Indiana.

Operator, Operator

Our next question is coming from the line of Andrew Weisel with Scotia Bank.

Andrew Weisel, Analyst, Scotiabank

First question: you've talked about utilizing 10 gigawatts of existing system capacity around Houston to generate those $4 billion of savings, but you now have over 12 gigawatts of committed load. Do you have a rough ballpark number of what would be required per incremental gigawatt of demand going forward in terms of assets and CapEx needs and what kind of impact that would have on the rest of the customer base? Would it bring further customer benefits or should we think about it more like net neutral going forward?

Jason Wells, Chair and CEO

Ultimately, I think about it as further customer benefits. We have been in a very unique position in holding our rates relatively constant since 2014, and that largely has been a function of the economic growth in Houston. I can't size for you per gigawatt because it is going to be so unique — the cost depends on the length of the import lines, where intra-regional lines are needed and what's needed from a system stability standpoint. Those are all the things that we're evaluating as part of the transmission study. This will create incremental capacity at a cost, but the way I would think about it is it unlocks the benefit of future economic growth for the region. Just as we've invested in capacity in the past and that capacity has been utilized and helped keep our rates flat, the same will happen here. Ultimately, the single biggest lever for affordability of utility service is economic development, and we are laser-focused on continuing to make sure that we support the greater Houston region, Indiana and Minnesota's economic development opportunities.

Andrew Weisel, Analyst, Scotiabank

Directionally helpful. Second, on the balance sheet and cash taxes, you mentioned you'll be getting some refunds and expect to see lower cash tax outflows going forward. Do you see that as meaningful enough to reduce the guidance calling for $4 billion of common equity? All else equal, would that be meaningful enough to impact equity? And then remind me, was the convertible already embedded in the assumptions, or could that also imply some downside?

Christopher Foster, Chief Financial Officer

Sure. On the convert, you can imagine that helped reduce near-term floating rate pressure, so that was a nice add to the plan. As I think about the corporate alternative minimum tax benefit, what we had shared is that not only will you get the refund improvement for this year — roughly in line with that $150 million a year of cash tax payments that would go away — you would keep that benefit as you go forward, so that roughly $150 million a year. What we've shared is that can provide us the equivalent of adding an incremental $1 billion of CapEx to the plan with no incremental equity. And so as you heard from what Jason shared this morning, there are multiple opportunities. That's how we've tried to frame that: we actually have more CapEx we can add to the plan without adding incremental equity.

Operator, Operator

There are no further questions in the queue at this time. Ladies and gentlemen, this concludes CenterPoint Energy's First Quarter 2026 Earnings Conference Call. Thank you for your participation, and you may now disconnect.