Prepared remarks
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 contain projections and other forward-looking information and statements that are based on management's beliefs, assumptions, and information currently available to management. These forward-looking statements are subject to risks and uncertainties. Actual results could differ materially based on various factors as noted in our Form 10-Q, other SEC filings, and our earnings materials. We undertake no obligation to revise or update publicly any forward-looking statement, other than as required under applicable securities laws. We reported $0.37 per diluted share for the second quarter of 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 four 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. Fourteen gigawatts of these submissions are expected to be eligible for batch zero and would represent an increase of more than 65% from Houston Electric's current system peak of 21 gigawatts. Third, I will discuss today's announced $1.2 billion increase to our capital investment plan, driven by both the anticipated modest system upgrades expected to connect large load customers in Texas and continued progress related to the Downtown Houston revitalization project. We expect to deploy this incremental capital over the next five years without the need for additional equity financing. And finally, I will provide an update on 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 one of the two 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 2026. 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 and ERCOT to advance these projects to support our customers' desired energization timelines. With that said, the next phase related to the 10 gigawatts of 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 four 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 projects. As previously highlighted, our Houston Electric system's approximately 10 gigawatts of existing hosting capacity gives us a distinct advantage in connecting significant new load quickly and efficiently with modest incremental investment. This differentiated system profile enables us to connect these projects at less than $60 million per gigawatt, allowing us to deliver long-term growth in a disciplined and affordable manner. Beyond today's capital increase related to system upgrades for expected batch zero-eligible projects, we continue to evaluate the broader transmission investments necessary to support future demand growth through our ongoing internal transmission planning process. We expect to provide an update on these opportunities later this year. In addition to the $800 million capital increase associated with system upgrades, we have also identified approximately $700 million of additional investment opportunities that would be required to serve demand of approximately 3 gigawatts that are not 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 the 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 two 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 three years. Christopher will cover this in his section, but importantly, today's announced capital investment increase does not result in any increased equity needs. Even after incorporating today's increase, we still maintain visibility to at least $10 billion of additional capital 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, one of which would represent the single largest load we serve in that region. As a result of commitments from the customer, we have already begun work to serve this load. Outside of the project identified, we are engaged with multiple counterparties for additional large load projects in that area. As a reminder, the related investments required to serve these large loads would be incremental and outside of our current base plan. As we continue to advance these projects, we are focused on supporting the growth of the community we are privileged to serve and improving affordability for our customers for years to come. In closing, we continue to believe that we have one of the most tangible and executable long-term growth plans in the industry. We remain confident in our ability to execute our updated $66.7 billion capital investment plan through 2035 while maintaining visibility to at least $10 billion of additional upside capital investment opportunities. We are also well positioned to enable continued growth across the jurisdictions we have the privilege to serve, strengthening the economies of our service territories and improving affordability for our customers while maintaining our focus on delivering safer and more reliable service. With that, I will turn it over to Christopher to cover the financials in more detail.
Thanks, Jason. This morning, I will cover four areas of focus. First, I will walk through the details of our strong second quarter financial results and how they position us well for the rest of the year. Second, I will touch on our regulatory progress through the first half of the year as we continue to execute on the timely recovery of our customer-driven capital investments. Third, I will provide additional details on our positively revised $66.7 billion 10-year capital plan, which as Jason highlighted, will not require additional equity financing. And finally, I will give an update on our de-risked financing plan, balance sheet health, and credit metrics. Now starting with our strong financial results. On a GAAP EPS basis, we reported $0.37 for the second quarter of 2020. On a non-GAAP EPS basis, we reported $0.40 for the quarter. Our non-GAAP EPS excludes expenses related to our LDC divestiture activity, including the tax expense associated with the gain on sale of our Ohio Gas LDC which is required to be recognized over the full year of 2026, and restructuring costs in connection with our Louisiana and Mississippi divestitures given the recent expiration of our related transition service agreement. In addition, we continue to exclude the impacts of removing our temporary generation units from base rates as they are no longer part of our regulated utility business. As a reminder, we will be marketing these units for either a sublease or sale and will also exclude the associated income resulting from these transactions. Taking a closer look at the drivers of our second quarter earnings. Growth in rate recovery contributed $0.10 of favorability when compared to the same quarter last year, driven by a full quarter 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 de-risk our financing needs are additional tailwinds that further position us well to deliver as we move through the year. Over the long term, we continue to expect to grow non-GAAP EPS at the mid-to-high end of our 7% 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. 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 five years. Outside of today's update, and potential future financing tailwinds, we will continue to target funding incremental capital investments consistent with our consolidated capital structure of approximately 47% equity and 53% debt. Lastly, I want to touch on our credit metrics and balance sheet. As of the end of the second quarter, our adjusted FFO to debt ratio based on Moody's rating methodology was 13.4%. This represents a nearly 100-basis-point improvement from Q1 and we anticipate continued expansion of the cushion represented here in part due to a tax refund related to the previously paid corporate alternative minimum tax, a portion of which we anticipate to receive in the third quarter of this year. This alone could add roughly 30 basis points of improvement to our metrics. In summary, we are confident in our ability to execute this year and beyond given anticipated future financing tailwinds and continued visibility to customer-driven growth opportunities. We are reiterating our 2026 non-GAAP earnings guidance targeting at least the midpoint of $1.89 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. 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 represent a step change in growth which will meaningfully drive economic development and improve customer affordability. This growth, combined with our consistent execution and proactive efforts to de-risk our regulatory profile and financing plan, increases our conviction that we have one of the most compelling affordability profiles and one of the most tangible and executable long-term growth plans in the industry.
Thanks, Jason. Operator, I would like to turn it over for Q&A.
Questions and answers
Thank you. At this time, we will begin taking questions. The company requests that when you are asking a question, callers pick up their telephone handset. Thank you. One moment for our first question. Our first question is coming from the line of Shahriar Pourreza with Wells Fargo Securities. Your line is now open.
Hey, guys. Good morning. 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. 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.
Thanks, Shahriar, for the question. From a CapEx standpoint, that is generally the range we are seeing—$5 million to $20 million per mile. Our plan assumes $8 million per mile. 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 that could be a tailwind as we enter next year. From a cash flow standpoint, yes, we continue to see about $6 million a month per gigawatt in cash flow from demand charges from these related customers. As you can see from the growth that we announced today, that growth is significantly accelerating over 2027, 2028, and 2029, so it is a very significant cash tailwind in those coming years.
Got it. Okay. And then obviously previously you framed this corporate alternative minimum tax benefit as unlocking about $1 billion of incremental CapEx with no additional equity. This morning, you added about $1.2 billion to the plan, deployable within five years with no change to the equity guide—that seems to be the key message. But batch zero, transmission studies, etc., could be fairly material. How should we be thinking about funding needs or whether the cash benefits from these investments will be enough to offset those funding needs as well? Thanks.
We will always seek to most efficiently fund our CapEx growth. We have a history and track record of doing so, and we are not going to unnecessarily lean on our balance sheet. We want to maintain a healthy cushion from an FFO-to-debt standpoint, but we will continue to think creatively. Some of the cash flow tailwinds that Christopher mentioned—the opportunity to remarket the temporary generating units and 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 import capacity, to create more intraregional transmission capacity, and to support stability-related investments at the transmission level. The comprehensive transmission plan that we are updating has a number of different elements we can lean on to efficiently fund that growth without 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 create value for our stakeholders, and if that requires asset recycling, we may consider that. As you recall with the Ohio transaction that we announced, we have staged that sale with a seller note and have sold equity forward, really eliminating kind of any equity needs for the near future. So I think we are in a good position not having to lean on asset recycling in 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 is coming from the line of Nicholas Campanella with Barclays. Your line is now open.
Hey. Good morning. Thanks for all the updates today. Maybe just—on the data center opportunity in Indiana that you discussed on the last call—can you 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 no-equity comment, or how should we think about that? Thank you.
I continue to remain very optimistic around the work we are doing in Indiana. We are continuing to make meaningful progress. A couple of things to point out in Indiana: as the team has done more work around our system, we have found the ability to unlock incremental capacity in the short and medium term that gives us more optionality to help serve large loads. As I alluded to in my prepared remarks, we are already well underway on engineering, ordering long-lead materials, and securing our spot in the MISO queue for these connections. So we're making meaningful progress to ensure we have near-term capacity to support those opportunities. With respect to incremental generation costs, that is outside of the CapEx update today. We will look to most efficiently fund any incremental CapEx increases going forward. That said, as we look at transmission-related opportunities and generation in Indiana, there is likely some equity that will be needed to support that level of incremental CapEx growth for those different drivers.
Thanks a lot. Maybe sticking with Indiana, there's been the affordability report that was issued and I think there's going to be a conference on August 7. Anything that you are expecting from that broadly—what you expect it to address? And just to confirm, you are maintaining the current filing path for the state on both the gas and the electric side, correct? Thanks.
We will maintain the current timeframe for the consolidated gas cases by the end of this calendar year. The current timing for our electric case would be the first quarter of 2026. Regarding the technical conference on August 7, it's our understanding you'll likely see a series of different topics referenced there to bring about future meetings where topics will be discussed in more detail. Our focus is on encouraging and enabling economic development for the area—it's the best way to allow for ongoing affordability for our customers by building new loads that spread costs, enhance the property tax base, and help the community grow. We've also taken steps in the last few years that have been affordability-focused for our customers: the $50 million of O&M related to the retirement of our coal facilities, the returns that we passed back to customers related to the securitization of the coal plant, and our commitment to keeping electric rates stable up to 2026. We'll contribute additional ideas for the affordability technical conference and look forward to the conversation.
Thanks for those thoughts.
Our next question is coming from the line of Julien Dumoulin-Smith with Jefferies. Your line is now open.
Hey. Good morning, Jason and team. Thank you. Perhaps just keep it going in the same direction as the prior questioners. Can we kick off a little bit on the timing of the transmission update? You made the allusion that later 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 push 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 coming back to update transmission. Also, any comments about the substance of anything going on in Texas vis-à-vis timing of the large loads would be helpful.
We are excited about the growth we announced today and intend to provide a more comprehensive transmission study update in the second half of this year. It's important to do so: we've seen more growth than was anticipated originally out of batch zero, and we see no indication that growth is slowing in Texas. Outside of batch zero large loads, we are seeing an uptick in interconnection requests at the distribution level. If the load request is less than 75 MW it does not necessarily need to go through batch zero, and year-to-date we've seen about 500 MW of distribution-related requests just below that threshold to enable advanced manufacturing, more distributed data centers, energy-related logistics, and other industries. So we do not see growth slowing. Regarding the broader debate around 765 kV and transmission, the conversation should be about how to most effectively work with communities to enable ongoing growth in a constructive manner. We will take a lead in that regard and support the state's direction. We represent about 2.5% of the geography of Texas and 25% of the electric demand today—that is only growing, so we need more import capacity. We will happily support the direction the state heads in to most efficiently support continued economic growth. We will put our updated transmission study out in the second half of this year and engage based on the state's direction on how to enable that. As it relates to large loads in Texas, our focus is enabling our customers in the greater Houston region. We are in a unique position with 10 gigawatts of existing capacity on our transmission system and we can move quickly. With modest incremental capital, we can unlock another 4 gigawatts—totaling the 14 gigawatts we expect to be eligible for batch zero that we identified today. Growth is not slowing, which is why we need to continue to rebuild transmission capacity to support the next round of growth.
Awesome. Just a quick clarification in terms of financing and financing latitude. You provided sensitivity about what large loads can do in terms of incremental revenues. Clarify how much of that latitude is reflected in this updated plan. How much of it are you using and reflecting in the Outlook? And as much as that is a meaningful quantum of incremental revenues to come from large loads, especially if they accelerate, can you confirm that the temporary generation cash flow uptick is not reflected in the Outlook either? I think there are several buckets not reflected.
That's correct, Julien. 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 the benefit from transacting the temporary generation units. We have indicated we will have insight ahead of the end of Q1 next year when those units return. A third near-term component is the likely prior historical recovery of the additional corporate alternative minimum tax amount that would likely come through in 2027. Those three components represent tailwinds to the plan but are not yet incorporated into our Outlook.
Yes.
Precisely. All of the incremental large load benefit is not reflected. We'll see when you provide that comprehensive update. Thank you very much. All the best.
Thank you. Our next question is coming from the line of Steven Fleishman with Wolfe Research. Your line is now open.
Hi. Good morning.
Morning, Steven.
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 the potential savings for customers?
We would certainly like to give a more definitive update before the end of this calendar year. We continue to make progress and are already working on advancing the actual work for the interconnections. We hope to provide a more comprehensive definitive announcement before the end of the year. As we have already announced, we believe that at least the initial level of demand in Indiana could support about $250 million of residential customer savings over the next 15 years. As we work with multiple parties, we hope to continue to expand on that and deliver more customer benefits down the road.
Okay. And in Texas, just to make sure I understand the growth: the 65% that you talk about is just from the large load batch zero projects and does not include growth coming from distribution-level customers, correct?
That is right. The 65% increase refers just to batch zero and does not include distribution-level customers. We are seeing an uptick in distribution-level demand as well, so overall growth will be well north of the 14 gigawatts we reported for batch zero alone. We provided the batch zero update given that process concluded this summer.
Okay. Great. Thank you.
Our next question is coming from the line of Jeremy Tonet with JPMorgan. Your line is now open.
Hi, good morning.
Morning, Jeremy.
You talked about $5 billion of customer savings from the 14 gigawatts in Texas. Can you expand on that a bit more? What does that look like in annual or monthly savings, and how does this influence the tone of conversations with stakeholders?
If you look at the rule of thumb, 14 gigawatts in base load and study load is roughly $800 million of revenue requirement. Multiplying that across our customer base and allocating as we've described leads to just over $500 million a year in reduced costs for residential and small commercial customers. Over 10 years, that gets you to the roughly $5 billion of savings we referenced. Beyond bill impacts, there are localized benefits to communities such as property tax benefits and other economic development impacts.
Got it. Thank you. And on Indiana, you referenced potential for more customers. How does that influence stakeholder conversations across the state on economic development and affordability?
In both Indiana and Texas, there is alignment from state leadership through local levels that continued economic development is the path to the strongest customer affordability profile. Building new loads spreads costs, enhances tax bases, and helps communities grow, which keeps rates more affordable over the long term. Indiana has not seen the level of growth Texas has, but state leadership understands the opportunity and we are working with leaders to deliver economic growth and improved affordability for our customers and communities.
If sufficient demand materializes in Indiana, how would that influence thoughts on the potential for a Genco—would that be worthwhile and beneficial to stakeholders?
The Genco structure is an innovative option. It would not necessarily be needed if we are talking about serving 1.5 gigawatts or less, since we have that incremental capacity without significant generation investment. If demand exceeds that 1.5 gigawatts, a Genco structure could be something we pursue. Our current focus is landing the large load customers, and if demand grows beyond the capacity we have, we may pursue a Genco structure down the road.
Our next question is coming from the line of Richard Sunderland with Truist Securities. Your line is now open.
Good morning, and thank you for the time today. On the Indiana side, could you parse a little more around that short- and medium-term capacity unlock you referenced? Would that all be for the benefit of the first customer, or is that accelerating discussions with potential second customers? I'm curious how that element is impacting conversations overall.
It's more the latter. The unlocked capacity is enabling multiple conversations with customers that could follow similar timelines. If one customer takes the capacity, that's great; if multiple customers take it, that's also great. Our focus is ensuring that capacity is utilized to support economic development and land large loads for the community.
On the Texas side and the discussions around 765 kV, how does that overlay affect your routing work and the potential outcome of that routing update in Q1? Are you thinking about routing differently, and any other thoughts would be helpful.
We are thinking about routing differently and engaging communities earlier and more constructively. We've been hosting webinars to introduce the projects, working with elected officials, narrowing potential route options to limit impacts to landowners, and conducting town halls and workshops. We want to demonstrate local benefits of construction and ongoing property tax contributions, and work with landowners to find optimal routes that create the least disruption. We've taken a community-centric approach as we embark on the routing work that we expect to finalize in the first quarter next year.
Our next question is coming from the line of Sophie Karp with KeyBanc. Your line is now open.
Hi. Good morning, and thank you. On Indiana, will you be able to show customer benefits in a tangible way when you have your first customer signed up, or will that come later as an offset to future capital needs as you add to rate base to service those customers? How visible will that be for ratepayers?
We will begin to show immediate customer benefits because we have existing capacity on our system today. Once the large load comes online, the load will be absorbed by that customer rather than existing customers, so you will see an immediate offset rather than requiring significant incremental investment down the road to unlock that customer's needs.
Will that be shown as bill credits or just reduced bills—how visible will it be for ratepayers?
It's more of a reduced bill effect; it will offset costs for existing customers.
Okay. And on the timeline of batch zero and interconnection of these projects, how long until shovels in the ground? There can be administrative and permitting delays, so what's the anticipated timeline from paper to construction?
We have work well underway. We indicated on a slide that we are anticipating connecting 3 gigawatts in 2027, and that work is underway. For field construction—shovels in the ground—for 2028 projects, we are well down the road in engineering and have long-lead materials. That work will begin shortly. On August 7, we should have confirmation of the gigawatts that are in baseload, which will start in earnest the field construction work, such as site preparation and civil work. Some batch zero study load projects will need to understand their allocated energy, which won't be finalized until April 2027, and those projects may be delayed. Given the compressed timeline for much of this to come online before the end of the decade, we are starting engineering, have secured long-lead materials, and are ready to begin construction when customers give notification to advance.
Alright. Thank you. Appreciate the comments.
Our final question is coming from the line of Anthony Crowdell with Mizuho. Your line is now open.
Good morning. On the batch zero process, for customers that do not get selected—maybe they applied and did not qualify—is there an appeal process and does that have the potential to slow anything down?
We have three gigawatts of viable projects that had studies not approved by ERCOT and therefore have not been classified as baseload or study load. We continue to advocate on behalf of those customers. The good faith exemption that ERCOT announced is not oriented toward addressing customers who have not had a study approved. This is meaningful growth for our community, so we will continue to work with ERCOT and our customers to find a path to energization, but at this point the path is unclear.
Christopher, the credit cushion is getting larger but Moody's outlook remains negative. Any update on your conversations with the agency and timing for a ratings update?
We have spent time with Moody's on the key issues they wanted to see progress on, and we have delivered almost a 100-basis-point improvement quarter over quarter in adjusted FFO-to-debt. We anticipate continued expansion of that cushion, and we referenced roughly 30 basis points of improvement in Q3 alone related to the corporate alternative minimum tax refund that was not previously in the plan. I'm confident we will be able to make progress with Moody's. I can't give a specific timing for a ratings action, but we expect movement 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.