CenterPoint (CNP) Q1 2026 Earnings Transcript

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DATE

Thursday, April 23, 2026 at 8 a.m. ET

CALL PARTICIPANTS

• President and Chief Executive Officer — Jason Wells
• Executive Vice President and Chief Financial Officer — Christopher Foster
• Vice President of Investor Relations — Ben Vallejo

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TAKEAWAYS

• Non-GAAP EPS -- $0.56 for the quarter, up from prior year, with management reiterating full-year non-GAAP EPS guidance of $1.89 to $1.91, representing 8% growth at midpoint versus 2025 delivered results.
• GAAP EPS -- $0.48 for the quarter, with non-GAAP adjustments mainly related to the Ohio LDC sale and removal of temporary generation units from base rates.
• Rate Recovery Growth Contribution -- $0.11 positive, attributed to fully effective updated rates and interim filing mechanisms.
• Weather and Usage Impact -- $(0.02) negative versus prior year, reflecting milder weather across Texas and Indiana territories.
• Interest Expense -- $(0.04) unfavorable, primarily due to new issuances, partly offset by lower commercial paper balances and favorable convertible debt pricing.
• Post-divestiture Earnings Impact -- $(0.05) negative related to lost earnings from Louisiana and Mississippi businesses, replaced by accelerated Texas investments.
• Houston Electric Firmly Committed Load -- Increased to 12.2 gigawatts, up from 7.5 gigawatts previously, with 3.2 gigawatts presently approved by ERCOT.
• ERCOT Project Approvals -- 2.5 gigawatts of load approved in less than 80 days since filing; remaining 9 gigawatts to be submitted for approval within weeks.
• 8 Gigawatts Energization -- Management anticipates energizing approximately 8 gigawatts of committed load by 2029, which is 80% of the previously forecasted increase by 2031.
• Residential Growth -- 2% annual rate sustained for several decades in greater Houston area.
• Affordable Delivery Charges -- Electricity charges are claimed as 11% below national average and currently the lowest in ERCOT, supported by diversified growth.
• Customer Savings Estimate -- Utilizing 10 gigawatts of system capacity is expected to provide approximately $4 billion in aggregate residential and commercial customer savings in Texas over 10 years.
• Indiana Load Opportunity -- Largest single load prospect identified in Southern Indiana, with an initial $250 million estimated residential savings over 15 years from the incremental load.
• Planned Capital Investment -- $6.8 billion target for 2026, with $1.2 billion already invested during the quarter.
• Long-Term CapEx Plan -- 10-year base plan of $65.5 billion, with over $10 billion in potential incremental capital opportunities under assessment.
• Debt and Financing Progress -- 70% of 2026 financing needs completed; $650 million convertible debt issued in February, with commercial paper balance at parent at quarter end reduced to zero from an average of $1 billion.
• Adjusted FFO to Debt Ratio -- 12.5% per Moody’s methodology as of quarter end, anticipated to improve as capital deployment normalizes.
• DCRF Filing -- approximately $108 million requested revenue increase; settlement reached and new rates targeted to take effect in June.
• TCOS Filing -- approximately $36 million transmission revenue increase, approved and implemented during the quarter.
• Texas Gas GRIP Filing -- Annual request for $62 million increase, anticipated to be reflected in rates starting June, pending approval.
• Convertible Debt Benefit -- Management notes reduced exposure to floating rates due to the February issuance.
• AMT Tax Refund -- Refund expected from previously paid cash taxes following revised corporate AMT guidance, with cash inflow to be incorporated into upcoming financing plans.
• Forecasted Non-GAAP EPS Growth -- Targeting mid- to high end of 7%-9% through 2028, with 7%-9% expected annually through 2035.
• Incremental Houston Demand Charges -- For each incremental 1 gigawatt load, about $6 million per month in demand charges, providing a direct earnings and affordability tailwind outside the capital plan.
• Indiana CapEx Opportunity -- Conversion of simple cycle to combined cycle unit plus new transmission investments could unlock at least 1.5 gigawatts and around $1 billion in incremental CapEx through 2029.
• Transmission Project Timing -- Near-term transmission additions planned to address capacity limitations before 765 kV projects commence in 2031-2032, with new projects to be detailed in the second half of 2026.
• Market for Temp Generation Units -- Company is “seeing directionally almost double the original lease rates” for units being marketed, with larger units serving San Antonio to return by March 2027.
• Corporate Alternative Minimum Tax Impact -- Refund and future elimination of roughly $150 million annual cash tax outflow, equivalent to adding $1 billion of CapEx to plan without incremental equity needs.
• Battery Storage Penetration -- Significant increase in battery projects connected to Houston’s system, almost exclusively paired with solar, moderating ERCOT peak pricing and expected to continue for “at least the next couple of years.”
• Pace of Regulatory Filings -- Gas rate case applications planned for Minnesota and Indiana (representing under 20% of consolidated base earnings) to be filed in Q4 2026, with expectation of customer bill benefits through cost allocation changes in Indiana.

SUMMARY

CenterPoint Energy (NYSE:CNP) reported first-quarter non-GAAP EPS of $0.56 and reaffirmed its 2026 non-GAAP EPS guidance range of $1.89 to $1.91, targeting 8% growth over the prior year. Management highlighted a substantial increase in Houston Electric’s firmly committed load to 12.2 gigawatts, with 3.2 gigawatts approved by ERCOT and 8 gigawatts expected to be energized by 2029. The company outlined $6.8 billion in planned capital investments for 2026, a $65.5 billion base 10-year strategy, and more than $10 billion in potential incremental projects tied to transmission studies and regional growth.

• Management stated that nearly 70% of 2026 financing needs are completed, with a temporary dip in the adjusted FFO to debt ratio to 12.5% expected to improve as capital is deployed.
• The company projects significant customer savings from regional growth and scale, including $4 billion for Texas electricity customers over 10 years and $250 million in Indiana residential savings over 15 years.
• Executives noted strong demand for temporary generation assets, with current lease rates trending nearly double prior levels, and plans to market additional units as contracts mature by 2027.
• Management indicated that the elimination and refund of cash AMT will enable increased capital deployment equivalent to $1 billion without new equity issuance, enhancing flexibility for future projects.
• Upcoming regulatory filings include revenue requirement increases via DCRF, TCOS, GRIP, and rate cases in both Minnesota and Indiana, with cost allocation changes in Indiana aimed at further improving affordability.

INDUSTRY GLOSSARY

• DCRF: Distribution Capital Recovery Factor, a Texas regulatory mechanism allowing utilities to adjust rates to recover incremental distribution investments.
• TCOS: Transmission Cost of Service tracker, used to recover costs associated with new or incremental transmission infrastructure investments.
• GRIP: Gas Reliability Infrastructure Program, an annual filing in Texas to recover costs of qualifying gas infrastructure investments since the last rate case.
• ERCOT: Electric Reliability Council of Texas, which operates the state’s power grid and manages interconnection and transmission approvals.
• MISO Q: Project queue in the Midcontinent Independent System Operator territory, denoting transmission and generation projects under consideration or development.
• FFO: Funds from Operations, a cash flow metric commonly used by credit ratings agencies to assess financial health and debt coverage.

Full Conference Call Transcript

Jason Wells: Thank you, Ben, and good morning, everyone. On today's call, I'd like to address 4 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 to provide incremental capital investment opportunities and further support 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 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 2 years. Our conviction in that accelerating time line 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 substation 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 in an influx of new residents, which has fueled a 2% annual residential growth, the areas 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 to 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 refresh 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: Thanks, Jason. This morning, I will cover 4 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 2 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 6 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. And 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 previous 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 has 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: 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 in 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: Thank you, Jason. Operator, I'd now like to turn it over for Q&A.

Operator: [Operator Instructions] Our first question coming from the line of Shahriar Pourreza with Wells Fargo Securities.

Shahriar Pourreza: Just first, just there's obviously more specificity around the Houston Electric load, including the 12 gigs of firmly committed demand and the 8 gigs of data center load expected online by 29. 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: Thanks for the question, Shar. 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, switchyard 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 2 though 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 it's about -- 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. And that's what we've been highlighting in terms of the trendy working through 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 is 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: Got it. Got it. And then just maybe just kind of correlated to the first question is just with ERCOT's new preliminary long-term forecast that projects now like 278 gigs of total demand by 29% and $3.68 by 2032. But both obviously ERCOT and PUCT have indicated that those forecasts likely overstate. I guess, remind us how you're using this kind of in your planning process? And 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 '26?

Jason Wells: Yes. As we've highlighted on previous calls and what you've seen in our ERCOT emissions, we are much more disciplined in terms of load that we submit to ERCOT for planning purposes. The loan 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 that we're actively under construction in terms of committing. We will be filing with ERCOT, as I said, another 9 gigs in the coming couple of weeks. From a CapEx standpoint, again, I think the real opportunity here is replacing the capacity for future growth.

And so 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, the dollars associated with those. And then I think this continues to be a tailwind for the continued buildout of the 765 kV system on what I would call more of a medium-term, longer-term opportunity.

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 for 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.

Operator: Our next question coming from the line of Steve Fleishman with Wolfe Research.

Steven Fleishman: 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's 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: Yes.. No, absolutely. Steve, happy to provide that color. So if you've looked at the MISO Q, we have a transmission project that we've filed for to provide incremental capacity in that region. And in our integrated resource plan filing that we 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 Q. 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 because we have the simple cycle plant already, Bill. I would think about this as more around about $1 billion opportunity as opposed to several billion dollars just to put some scale around the incremental CapEx. Again, this is I think 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 billion -- 1.5 gigs, 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: Would the $1 billion opportunity be kind of by 2030 or after 2030?

Jason Wells: No, no. This is all -- Yes, definitely within '27, '28, '29.

Steven Fleishman: Okay. And then I guess just on the -- I just want to clarify on the ERCOT. So that number that we got from ERCOT last week on demand, that huge number. Your what the numbers that you have for your region territory within that, they're consistent with what we heard today? Or is there like a bigger number based on however they ask the data to be given to them, that matches up with their total number?

Jason Wells: Yes. Our total submission as part of that process for large loads was roughly 4 gigawatts. That was included in those reported tables. Outside of -- and that was effectively the large load customers that we were currently and actively constructing transmission modifications, interconnection facilities. Outside of the number that was picked up on that table, we also filed a large load study that incorporated continued residential growth, the potential for large load customers. And 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.

We felt that given the methodology that ERCOT asked us to submit the customers, the 9 gigawatts that we will be filing for in a couple of weeks didn't meet that criteria back earlier this year. But certainly, we made a significant amount of progress in these 9 gigawatts that we will be filing in the coming weeks, meet all of the related commitments under the batching process for ERCOT, and we feel confident our committed load firmly to be low customers. So this is an incremental amount to what was reported by ERCOT.

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

Richard Sunderland: Just circling back to this transmission commentary, I want to understand what you're studying for that 2H update it sounds like if I was following you earlier that 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: Yes. As we've been talking about on previous earnings calls, we think probably the most important aspect to focus on for large load is existing hosting capacity. These large load customers need to connect in any power 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 it, is in the process of connecting 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 sort of like 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. And so this transmission study that we've been alluding to really seeks to kind of 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 again, 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: Understood. That's very helpful commentary. And then I realize [indiscernible] was 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: Sure. We are in the market actually on the -- 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 of the 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 data 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: Our next question is coming from Jeremy Tonet with JPMorgan.

Jeremy Tonet: Just wanted to kind of go to the credit side, if I could. I was just wondering if you might be able to expand a bit more on the timing of the trajectory of the credit metrics here and how you expect to exit '26 at this time?

Christopher Foster: Sure thing. This is purely [indiscernible], 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 so 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.

And 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, right, 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 at a year-end again, we will be at the high end of that range.

Jeremy Tonet: 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, I guess, if you could talk a bit more on traditional large load drivers in the Gulf Coast and Houston area. And I guess, maybe how you see that trending?

Jason Wells: Absolutely. Look, 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, [indiscernible] 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.

And so while it's not data centers for the market, they're heavy users of electricity for their function. So we see this growth really driven again by advanced manufacturing data centers. We continue to see significant activity on the energy and energy export side of things. Really, I want to continue to underscore, I think the diversity of economic and load growth drivers is really what sets this region apart. We don't see any slowdown in any of the large industries that are driving propelling Houston's economic development.

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

William Appicelli: Just a question on the batch study review process or COD. And 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: Yes. So 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 concept. The 9 gigawatts that we're filing for will likely qualify for batch 0. There's effectively 2 load studies that we have to have approved by ERCOT to qualify for Baxter, one of those 2 need 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 again, approve those to be included in bags. As I've mentioned, we have had very successful approvals of our previous submissions anywhere from 55 days to just under 80 days.

So outside of kind 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, this is the high voltage breakers and transformers, customers that will actually utilize the power or signed up. And so all of the definitions that are going to be required to be either a baseline or back 0 customer.

William Appicelli: Okay. And then shifting gears a little bit, I mean -- 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 realize that you're responsible for on the T&D side, but just curious, you've seen a big uptick in storage in ERCOT broadly. And so just curious from your perspective what the impacts are and the outlook there?

Jason Wells: It has been -- I mean -- and you know the numbers, a significant level than battery investment in the state that is all but sort of changed the summer peak pricing in the ERCOT market as batteries have helped really kind of smooth that summer peak demand. What we see kind of going forward, as I mentioned, from our vantage point, we've got about 9 gigawatts of incremental generation that is connecting to our [indiscernible] Greater Eastern region. And that is largely solar and batteries almost exclusively. We continue to see a high degree of interest in -- for the solar projects in particular to qualify for the tax credits before they expire.

As a result, many of -- most of these projects are co-locating batteries. And so we continue to see batteries as effectively a tailwind to keeping energy costs low for customers for at least the next couple of years. And then we know that there are some incremental gas development that will really help after the tax credits expire and potentially, we see sort of a slowdown in the solar and battery build-out as we approach sort of the end of the decade. So we believe that strongly the generation is going to be there for this growth.

Battery is going to help moderate the cost of electricity for customers, and we continue to see a robust pipeline connecting to the system over the next 2 years.

Operator: Our next question is coming from the line of Julien Dumoulin-Smith with Jefferies. I'll move on to the next questioner. Our next question coming from the line of Anthony Crowdell with Mizuho Group.

Anthony Crowdell: I know Julian does 3 calls at once, so he's probably a little tied up. Just -- I don't believe it's apples-to-apples. Apologies for the question. Just when I look on Slide 4, and you talk about the 8 gigawatts of data center load expected to be energized by 2029. Is that the same 8 gigawatts that in fourth quarter slide deck you guys are focused on getting that on by year-end '28. I mean -- my question is that load getting pushed back a year or it's actually not an apples-to-apples comparison?

Christopher Foster: Anthony, let me just go and lay off for you. In the prior quarter, we had talked about 7.5%. That number is now going to 8%. 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: Perfect. Great. And then just lastly, a quick follow-up on -- you talked about -- I think you going to file Minnesota and Indiana gas cases later this year. Any -- is it just infrastructure investment that's driving that filing or anything else in those -- in either of those 2 filings?

Christopher Foster: Sure. Pretty straightforward. Definitely, it's really about replacement CapEx in Minnesota on a very straightforward program to focus on safety and reliability. As it relates to Indiana, there, what I think is important that we have already signaled is our focus on affordability. In particular, we are evaluating actually, Anthony combining what are currently 2 gas rate cases up there into 1 which we would likely file in Q4 of this year. By combining the cases, we're likely to see a customer build benefit explicitly for those customers that we serve in Southwest Indiana as a result of the cost allocation changes. And so excited to be able to put those forward.

Both of those, I think you should anticipate for Q4 of this year, both Minnesota and Indiana.

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

Andrew Weisel: First question is you've talked about the 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 mode -- obviously, no 2 projects are the same, but do you have a rough ballpark number of what would be required or cremental gigawatt of demand going forward? I know you alluded to some new transmission projects that may be you'll announce later this year. I'm asking more like a sensitivity in terms of assets and CapEx needs and then what kind of impact would that 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: Yes. Ultimately, I think about it as further customer benefits. I think 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 kind of $1 per gigawatt for incremental because it is going to be so unique. What's the cost of and the length of the import lines, where specifically are the intra-regional lines needed 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 that I would think about it is it unlocks the benefit of future economic growth for the region. And just as we've invested in capacity in the past, that's been utilized and kept our rates flat. The same will happen here. And 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: Okay. directionally helpful. Then second, in terms of the balance sheet, on cash taxes, I know you mentioned you'll be getting some refunds and you expect to see lower cash tax outflows going forward. Do you see that as being meaningful enough to reduce the guidance calling for $4 billion of common equity. Obviously, that will depend on CapEx, which is constantly rising. But all else equal, would that be meaningful enough to impact equity? And then please remind me, was the convertible already embedded in the assumptions? Or could that also imply some downside?

Christopher Foster: Sure. So thanks for the question. On the convert, you can imagine that helped reduce kind of 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, right? So just think about that as roughly in line with that $150 million a year of cash tax payments that would go away, you would keep that benefit, right, as you go forward, right? So that roughly $150 million a year.

So what we've shared actually 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 can hear from what Jason has shared this morning, certainly, there are multiple opportunities. So that's how we've tried to share that. Actually, we've got even more CapEx we can add to the plan without adding incremental equity.

Operator: I see 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.

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