CenterPoint Energy, Inc. (CNP) Q2 2026 Earnings Report, Transcript and Summary

Good morning, and welcome to CenterPoint Energy Second Quarter 2020 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. I will now turn the call over to Ben Vallejo, Vice President of Investor Relations and Corporate Planning. Please go ahead.

Good morning. And welcome to CenterPoint's Q2 2020 Earnings Conference Call. Jason Wells, our Chair and CEO and Christopher A. Foster, our CFO. Will discuss the company's second quarter 2020 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 37¢ per diluted share for the second quarter of 2020 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 the non-GAAP measures used in providing guidance, please refer to our earnings news release 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 would like to turn it over to Jason.

Thank you, Ben, and good morning, everyone. On today's call, I would like to address 4 key areas of focus for the quarter. First, I will 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 5 years without the need for additional equity financing. And 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 affordability. I will start with our strong second quarter financial results. This morning, we reported non GAAP EPS of $0.40 for the second quarter of 2020. We are reiterating our full year 2026 non GAAP EPS guidance range of $1.89 to $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% to 9% annual guidance range, through 2028 and 7% to 9% annually thereafter, through 2035. Now I would like to provide an update on the progress we have 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. Now 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 1 of the 2 required studies already approved by ERCOT. The 4 gigawatts of study 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 peak demand and further reinforce our confidence in achieving the accelerated 50% load growth by year-end 2020. 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 10 years. We are confident the combined 14 gigawatts of baseload and study 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 facility 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 represent additional customer demand that is pending ERCOT approval of the required studies. We will continue working closely with our customers in ERCOT to advance these projects to support our customers' desired energization time lines. With that said, the next phase related to the 10 gigawatts of baseload 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 study load projects are reflected in today's announced capital investment plan increase. Which I will 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 10 years. Through the addition of 14 gigawatts of eligible baseload 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 project. As previously highlighted, our Houston Electric system's approximately 10 gigawatts of existing hosting capacity gives us a distinct advantage in connecting significant new low 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 baseload or study load eligible. This incremental capital is outside of the planned transmission investment 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 investment into 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 revitalization project. With the input of various stakeholder groups, we have made final site selections for the 2 required substation relocations. With those plans now solidified, we have refined our initial investment estimates. And 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 3 years. Christopher will cover this in his section, but importantly, today's announced capital investment increase does not result in any increased equity needs. And even after incorporating today's increase, we still maintain visibility to at least $10 billion of additional capital 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 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. 1 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 1 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, turn it over to Christopher to cover the financials in more detail.

Thanks, Jason. This morning, I will cover 4 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. And finally, I will give an update on our derisked financing plan. Balance sheet health, and credit metrics. Now starting with our strong financial results on slide 5. On a GAAP EPS basis, we reported 37¢ for the second quarter of 2020. On a non GAAP EPS basis, we reported 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 have done to derisk 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% 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 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 $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 continue to execute against our Plan 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, and as Jason highlighted, we are updating our 10-year capital plan from $65.5 billion to $66.7 billion reflecting a $1.2 billion increase driven by large load system upgrades, and the progress made related to the downtown 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 1 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 of 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 5 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 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. And with that, I will now turn the call over to Jason.

Thank you, Christopher. 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 representing 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 derisk our regulatory profile and financing plan, increases our conviction. That we have 1 of the most compelling affordability profiles and 1 of the most tangible and executable long term growth plans in the industry.

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

Thank you. At this time, we will begin taking questions. The company request that when you are asking a question, callers pick up their telephone handset. Thank you. 1 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, Shahriar. Morning, Jason. Just on the transmission study, as we are thinking about sort of the size and cash benefits, on the CapEx side, historically, you guys have referenced $8 million per mile. Well, I think the market range is anywhere from $5 million to $20 million depending on routing and land. And on the cash benefit side, you have talked about $6 million per gigawatt per month. Are these still kind of relevant in any sense of timing here? Thanks.

Yeah. Thanks, Shahriar, for the question. You know, from a CapEx standpoint, yeah, that is generally the range we are seeing sort of that 5 million to $20 million Our plan assumes $8 million We will 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. So, you know, potentially could be a tailwind as we enter next year, but that is but that is all 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. And as you can see from the growth that we announced today, you know, that really is growth that is significantly accelerating over 27, 2028, and 2029. So a very significant cash tailwind in those coming years.

Got it. Okay. And then just and, obviously, previously, you guys framed this CIMT 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 an equity guide that is kind of the key message. But batch zero transmission studies etcetera, could be kind of fairly material. I guess, how do you 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 are going to always seek to most efficiently find that or fund our CapEx growth. I think we have got a history and track record of doing so. We are not going to lean on our balance sheet. You know, we want to maintain a healthy cushion from an FFO to debt standpoint. But we are going to continue to think creatively. I think some of the cash flow tailwinds that Christopher mentioned you know, the opportunity to remarket the temporary generating units, the cash flows from the incremental demand charges from this 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 intraregional transmission capacity, and certainly to help make stability related investments. On the transmission level. So that comprehensive transmission plan that we are updating, you know, 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. And further asset optimization, is that part of the lever or not anymore?

We will always look to, you know, create value for our stakeholders you know, and if that requires asset recycling, you know, we may we may consider that. You know, as you recall, though, with the Ohio transaction that we announced, we have staged that sale with a seller note and, you know, have sold equity forward, really eliminating kind of any equity needs you know, for the near future. So, you know, I think we are in a in a good position not having to lean on asset recycling the short term, but we will 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.

Hey. Good morning. Thanks for all the updates today.

Morning.

May maybe just you know, you have kind of talked about this data center opportunity in Indiana on the on the last call. And can you just give us an update on where you stand on that and if you need to invest in incremental generation for that does that get included in this you know, no equity comment, or how should we kind of think about that? Thank you.

Yeah. I continue to remain very optimistic around the work we are doing up in Indiana. We are continuing to make, I think, very meaningful progress A couple of things to, to point out up in Indiana. As the team has done some more work around our system, we have 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. And, you know, as I alluded to in my prepared remarks, we have are already well underway from an engineering ordering long lead time materials. Securing our spot in the MISO queue for these connections. So really making, you know, meaningful progress, know, making sure that we have near term capacity to support you know, those opportunities. With respect to incremental generation costs, you know, that is outside of the CapEx update today. We will as I said to Shahriar, look to most efficiently fund any incremental CapEx increase going forward. That said, as we look at transmission related opportunities, generation in Indiana, there is likely some equity that will be needed. To support that level of incremental CapEx growth for those different CapEx drivers.

Thanks a lot. And then, I mean, maybe sticking with Indiana, just you know, there is been, the affordability report that was issued, and I think there is going to be a conference on August 7. Just anything that you are expecting from that broadly, what you expect that to address? And then obviously, you are just maintaining the current filing path for the state on both the gas and the electric side, just to confirm. Thanks.

Sure, Nicholas. It is for the last part of your question that we will maintain the current time frame 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 2020. And then as you look at the technical conference that is coming up on August 7, I think it is our current understanding. You are likely to see a series of different topics referenced there. Really, to bring about future meetings where they will 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 is by far the best way to allow for ongoing affordability for our customers from building new loads that are attractive and spread the cost, help enhance the property tax base, and that really help the community grow for the long term. We have 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 have had a commitment here that is very focused on keeping our electric rates stable up to 2020. This is my way of saying, we will be able to contribute, you know, additional thinking for incremental ideas associated with the affordability technical conference and looking forward to the conversation.

Thanks for those thoughts.

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. Perhaps just keep it 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 the allusion that later, I think you said specifically this year, you would 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 are seeing from a political perspective on both data centers and transmission of late against your commentary on that coming up--coming back to update transmission. Then if you have any comments about the substance of anything going on at Texas vis a vis timing of the large loads, I would be curious as well.

Good morning, Julien. You know, we are excited with the growth that we announced today. And, you know, as we have talked about previously and reaffirmed on this call, you know, we intend to provide a more comprehensive transmission study update the second half of this year. Look, I think it is incredibly important to do so. We have we have seen more growth than was anticipated originally out of batch zero. We see no indication that growth is slowing here in Texas, you know, 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. You know, as you know, if the load request is less than 75 MW, it does not necessarily need to go through batch zero. And as a result, what we are seeing already year to date is 500 MW 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. And so we do not see growth slowing down. To come back to the point that is being raised around you know, a larger debate around 765 kV, I do not 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 and constructive manner. And, obviously, we will take a lead with leadership in that regard. But I think the state is still aligned around continuing growing. We see tailwinds accelerating, not decelerating. We represent about 2.5% of the geography of Texas, 25% of the electric demand today. that is only growing, so we need more import capacity. And, again, we will know, happily support the direction the state heads in the way to most efficiently support that continued economic growth. So we will put our updated transmission study out in the second half of this year and engage follow the direction of the state on how to enable that. You know, I think as it relates to this overall large loads in Texas, look, I our focus is on enabling our customers 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 and that was a differentiator During this ERCOT batch process, we could with modest incremental, capital investments, unlock another 4 gigawatts through which is the 14 GW we think will be eligible for batch zero that we have identified today. And, you know, look, as I said, it is it is not slowing down. And so back to the original question, that is 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. You just clarify how much of that latitude is reflected in this updated plan here? Just how much of it are you using and reflecting in the Outlook? And as much as that is a pretty meaningful quantum of incremental revenues to come from large loads, especially if the large loads themselves accelerate. And, obviously, I think to be very clear, that comes in tandem with the temporary generation cash flow uptick that is not reflected in the outlook still as well. Right? there is several different buckets that are not reflected.

Sure, Julien. that is correct. Maybe there is probably a third category I would add to. But the short answer is we have not yet pulled in the benefit from the demand charges from these large customer loads. it is also true that we have not yet folded in benefit from resolving the central transaction related to temporary generation unit. We have indicated there We will certainly have insight ahead of the end of Q1 time frame when those units do come back. And then the third 1 I would just emphasize again, this is more near term. it is the likely prior historical recovery of the additional corporate alternative minimum tax amount that would likely come through in 2027. And so those are the 3 components all representing a tailwind to the plan.

Yes.

Precisely. But all of the incremental large load not reflected. So we will 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 Steven Fleishman with Wolfe Research. Your line is now open.

Yeah. Hi. Good morning.

Morning, Steven, Just on the Indiana customer, do you think there will be an ability to get more visibility on that by the end of this year?

Both in terms of investment opportunity and also you know, the potential savings for customers. Yeah.

Steven, I mean, we would certainly like to give a more definitive update before the end of this calendar year. You know, we continue to work and make progress. So we would love to be in a position before the end of the calendar year to give that update. You know, obviously, these things just take a little bit of time. You know, we as we have talked about our already working on advancing the actual work for the interconnections, and, you know, we hope to provide a more comprehensive definitive announcement before the end of the year. As we have already announced, you know, 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. And as we look to work with multiple parties, hopefully, we can continue to expand on that and give you know, even more customer, you know, benefit down the road. So continuing to work it, and, hopefully, we will have this finalized before the end of the calendar year.

K. And then maybe in Texas. So just to kinda make sure I have got the growth right, the 65% that you talk about growth, is that just from the large load and that does not include the growth coming from kind of distribution level customers?

that is right, Steven, This is just batch zero. And does not include, you know, what we would see from distribution level customers and, you know, as I have indicated, we are actually seeing an uptick in distribution level demand, so growth will be well north of this. We just want to provide the back share update given the process is concluding here this summer.

Okay. Great. Thank you.

Thanks, Steven,

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

Hi, good morning.

Morning, Jeremy.

Just want to come back. I think you had talked about earlier 5 in Texas, $5 billion of customer savings for the 14 gigawatts batch zero, I think, there. And so I was just curious, I guess, you could expand on that a little bit more. What does that look like for, like, annual monthly savings? And 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 is 14 gigawatts that we have as we have referenced, in base load and study load. And so from that, again, the key thing to keep in mind here and why it is important from an affordability standpoint is that these large load customers would basically absorb the cost right of the system, and so that would reduce cost for our residential and small commercial customers. So 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 have 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. So, 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 benefits 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. And then maybe same question towards Indiana. I think you referenced beyond the initial large load customer, the potential for more the future here. And just wondering, I guess, economic development and affordability are top of mind in Indiana. And, you know, 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 the state leadership level through the local level that continued economic development is the path to the strongest customer affordability profile that we could provide. I mean, 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, but, state leadership understands the opportunities that sit in front of us, and we are all working both at the state, local, and to 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. I would say in both states.

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

You know, as we said in the past around the Genco structure, I think it is a very innovative structure. It was not necessarily needed for us if we are talking about serving 1.5 GW or less, we have that incremental capacity to our system without significant generation investment. On our side. As we work with multiple in that region, and demand may exceed that 1.5 gigawatts. I think the generation, the genco structure could be something that we pursue. Know, our focus right now is landing the large load customers. And, again, if it is on the if it exceeds that 1.5 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. Your line is now open.

Hey. Good morning, and thank you for the time today. I will I will stick with the Indiana side for now. Could you parse a little bit more around that short- and medium term capacity unlock referenced in the script? Would that all be for the benefit of the first customer? Or is that accelerating discussions with potential second customer opportunity? I guess I am 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. You know, in terms of interconnections. You know, it is it is capacity that exists. We want to serve and land large loads to help support economic development. If it is 1 customer, and, you know, 1 customer is interested in that capacity, that is great. If it is multiple customers, that is also great. You know? Our focus is in ensuring that, that capacity is utilized. And so right now, it is unlocked multiple customer conversations, but, you know, we are just looking to do the right thing for the community and land those large loads.

Got it. that is that is helpful color there. And then 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 in Q1? Are you thinking about the routing work in any different fashion? Any other thoughts there would be helpful. Thank you.

Yeah. Absolutely. We are thinking about the routing in a different way. You know, we have been I think, sort of on the front end of engaging communities in a different manner. Webinars to sort of presoak the idea of these projects. You know, working with elected officials on the basis for these, the potential routes, narrowing you know, the number of routes that we will propose to limit the impact to landowners to, obviously, the town halls and workshops that we have. We really want to work constructively in this community in these communities demonstrating sort of the value of 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. And so we have taken a very community centric approach as we have started to embark on you know, the routing work that will be finalized, as I said, sometime in the first quarter next year.

Great.

Thanks for all that. Our next question coming from the line of Sophie Karp with KeyBanc. Your line is now open.

Hi. Good morning, and thank you for taking my question. So to go back to Indiana, I guess, you thinking that you will be able to show customer benefits in some tangible way when you have your first customer there signed up, or 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 will begin to be able to show immediate customer benefits because we have existing capacity on our system today that once we enter, enter a large load, we will start to be absorbed by that new large load customer as opposed to by our existing customer So it does not it does not require significant incremental investment down the road. To unlock that customer's needs. it is it is immediate as we get the large load online.

Right. So will that slow as bill credits or just as a reduced bill, I guess? I can just try and understand how visible will that be for rate payers.

it is more of the latter. You know? It offsets. Got you. Mm-hmm. Got it.

Okay. And then just on the timeline of batch zero process and the and the interconnection of all these projects, Do you anticipate what do you anticipate in terms of timeline? I guess I do not want to put the words in your mouth. Terms of how long until shovels go into the ground? From this? Because there is there can be so many administrative and permitting delays. So I am just kinda curious to see what the anticipated timeline is from paper here into shovels in the ground.

We have got work well underway. You know? We have indicated here on 1 of our slides, we are anticipating connecting 3 gigawatts in 2027, and so that work is underway. You know, from a from construction as you said, shovels in the ground, out in the field. You know, as it relates to the work for 2028, you know, we are well down the road in the engineering. We have long lead time materials. That work will begin here shortly. In terms of what we are looking for you know, on August 7, we should have confirmation of the megawatts or, sorry, gigawatts that are in baseload I think that will start in earnest the field construction work really beginning site preparation, civil work, etcetera. You know, there will be some of the batch zero study load projects that will likely want to understand the amount that of energy they are allocated which will not be finalized until April 2027. Some of those projects as a result, may be delayed from a construction standpoint. But, you know, at this stand you know, at this point, just given 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, and we are ready begin construction when the customer, gives us notification. To advance.

Alright. Thank you so much. Appreciate the comment. Thank you.

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

Hey, good morning, team. Just a to Sophie's question and another question. Just on the batch zero process, for the customers that do not get selected, maybe they applied, they thought they were going to get selected, they, for whatever reason, did not qualify, is there an appeal process for them and does that have the potential to maybe slow anything down? Yeah.

Thank you, Anthony, for the question. As we have indicated here, we have 3 gigawatts of very viable projects. That would like to move forward submitted their studies. Unfortunately, those studies were not approved by ERCOT. And so that is why we have not classified them as either baseload or study load. We continue to advocate on behalf of those customers Those customers continue to advocate. The good faith exemption that ERCOT announced is not near not oriented towards addressing those customers who have not had a study approved by ERCOT. But, this is very meaningful growth for our community. And so we will continue to work with ERCOT, our customers, to advocate to find a path to energization. It just, at this point, is unclear what that path exactly looks like.

Great. And know Christopher gets upset when he does not get a question, but just Christopher, the credit cushion is getting larger, but the Moody's outlook remains negative. Just curious on your conversation with the agency on any timing or time frame of maybe when they give an update or just any latest conversation with the agency?

Well, thank you, Anthony, for the question. So short of it is, you are right. When we came through Q1, we had mentioned that we were going to be relatively light on FFO to debt. But we have spent time with Moody's on that. But we have been through really all the key issues that they wanted to see progress on. I really do think, it is meaningful. That we delivered almost 100-basis-points of improvement quarter over quarter here. And that cushion's only going to grow because, again, keep in mind, I referenced and we spent time with Moody's on this. We referenced roughly 30 basis points of improvement this coming here in Q3 alone that was not previously in plan. Related to that corporate alternative minimum tax amount. So it excuse me. In short, confident we will be able to make progress. I cannot 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 2020 Earnings Conference Call. Thank you for your participation. And you may now disconnect.