Good morning and welcome to CenterPoint Energy's First Quarter 2019 Earnings Conference Call with senior management. [Operator Instructions] I will now turn the call over to David Mordy, Director of Investor Relations. Mr. Mordy, you may begin.

Thank you, Lisa. Good morning, everyone. Welcome to our first quarter 2019 earnings conference call. Scott Prochazka, President and CEO; and Xia Liu, Executive Vice President and CFO, will discuss our first quarter 2019 results and provide highlights on other key areas. Also with us this morning are several members of management who'll be available during the Q&A portion of our call. In conjunction with our call, we will be using slides, which can be found under the Investors section on our website, centerpointenergy.com. For a reconciliation of the non-GAAP measures used in providing earnings guidance in today's call, please refer to our earnings news release and our slides. They've been posted on our website, as has our Form 10-Q. Please note that we may announce material information using SEC filings, news releases, public conference calls, webcasts and posts to the Investors section of our website. In the future, we will continue to use these channels to communicate important information and encourage you to review the information on our website. Today, management will discuss certain topics that will contain projections and forward-looking information that are based on management's beliefs, assumptions and information currently available to management. These forward-looking statements are subject to risk or uncertainties. Actual results could differ materially based upon factors including weather variations, regulatory actions, economic conditions and growth, commodity prices, changes in our service territories and other risk factors noted in our SEC filings. We will also discuss guidance for 2019 and 2020. The 2019 guidance basis EPS range excludes the following impacts associated with the Vectren merger: integration and transaction-related fees and expenses, including severance and other costs to achieve the anticipated cost savings as a result of the merger; and merger financing impacts in January prior to the completion of the merger due to…

Thank you, David, and good morning, ladies and gentlemen. Thank you for joining us today and thank you for your interest in CenterPoint Energy. This is our first quarter presenting combined results and we're pleased to be talking with analysts about the post merger company. We're also pleased with our integration efforts to date and we'll provide more detail on integration later in the call. I will begin on Slide 5. This morning, we reported first quarter 2019 income available to common shareholders of $140 million or $0.28 per diluted share compared with income available to common shareholders of $165 million or $0.38 per diluted share in the first quarter of 2018. On a guidance basis and excluding merger impacts, first quarter 2019 adjusted earnings were $222 million or $0.46 per diluted share compared with adjusted earnings of $241 million or $0.55 per diluted share in the first quarter of 2018. Notable factors contributing to the $0.07 reduction are $0.07 from our Energy Services business, which is largely timing-related and driven by weather and a $0.02 noncash loss from the dilution of ownership in Enable as a result of the vesting of additional common units under Enable's long-term incentive program. Utility Operations, particularly our natural gas distribution business, had a strong quarter. Overall, our businesses are performing well and we remain on target to achieve our financial objectives for the year. Increases for the quarter were associated with rate relief, customer growth, lower federal income tax expense and the benefit from businesses added as a result of the merger. These increases were more than offset by the Energy Services and Enable-related impacts I mentioned earlier as well as higher operations and maintenance expense, higher depreciation and amortization expense, lower equity return primarily due to the annual true-up of transition charges…

Thank you, Scott. I'm excited to be part of the CenterPoint Energy team. I have worked with many of you in the analyst community in my past, and I look forward to connecting and working with you in my new role. I will start with quarter-to-quarter operating income walks for the Houston Electric and natural gas distribution segment, followed by an overall guidance basis EPS walk and then additional detail on the merger. Turning to Slide 13. Houston Electric performed well during the first quarter, on track with our expectations. As you see on this slide, core operating income for the first quarter of 2019 was $74 million versus $99 million for the first quarter of '18. Lower revenue related to the TCJA provided a $6 million negative impact to operating income with an offset in income tax expense. Rate relief provided an $11 million positive variance and customer growth provided a $6 million benefit. Equity return primarily related to the true-up of transition charges, decreased $10 million. As you’ll recall, we made a nonstandard filing to lower the transition charge for Transition Bond Company IV in late second quarter of 2018. So the quarter-over-quarter variance should be reduced for the third and fourth quarters of 2019. Usage accounted for a $15 million negative variance primarily driven by more extreme weather patterns in January of 2018 compared to January of 2019. Higher O&M accounted for an unfavorable variance of $6 million, and miscellaneous revenues accounted for an $11 million positive variance. In addition, depreciation and taxes accounted for a $7 million negative variance. Houston Electric also incurred $10 million of merger-related expense. The total variances related to equity return, TCJA and merger-related expenses are $26 million. Excluding those variances Houston Electric’s operating income was up $1 million quarter-over-quarter. We are…

Thank you, Xia. We will now open the call to questions. [Operator Instructions] Lisa?

[Operator Instructions] The first question comes from the line of Insoo Kim from Goldman Sachs.

Maybe starting off at Energy Services, are the margins that you saw this quarter reflective of more normal level going forward for the first quarter? I understand first quarter '18 was a strong weather quarter for the segment, but just trying to look out beyond 2019 to see like what type of margins we should be assuming going forward.

Insoo, good morning. This is Scott. I'll make some comments. If Joe wants to add, I'll ask him to do so. I would characterize the first quarter of '19 as a little below what we would expect. It's certainly well below what we saw in '18, but it is a little lower than what we would expect on a normal basis in the first quarter. That said, since we weren't able to do much optimization in the first quarter, those storage assets are now available for us to take advantage of optimization in the latter part of the year. And we've already begun signing some commitments that do exactly that. So it essentially moves some of the earnings capacity for the first quarter to later in the year.

Understood. And perhaps on -- and then Indiana with the CCGT no longer in the plans, I understand there's going to be alternatives posed in the 2020 IRP with potential CapEx starting in 2021 likely. But in the '19 and '20 time frame for the moderate amount of CapEx you guys did have for the CCGT, are there some offsetting CapEx levels or investments that you're contemplating that could fill that gap in the next couple of years?

So I would say as we look at our total capital plan and spend, given the relatively small amount that was associated in those years, it's quite possible that capital could be redeployed to other areas where there may be additional needs. We're going to go through an exercise associated with the new IRP of understanding what the shift in investment looks like in Indiana. And as we do that as you know, we do that on an annual basis where we look at capital, we will update capital plans elsewhere. And it may well include the ability to deploy that limited amount of CapEx either on other needs within Indiana or elsewhere in our service territory.

Understood. But at this point, the earnings power that you see for this year and next year should largely be unchanged or not impacted that much?

That's correct, yes.

Our next question comes from the line of Ali Agha from SunTrust.

Scott, the Energy Services full year outlook you that you've laid out of flat is certainly lower than I think what your expectations were previously. So what could offset that in the portfolio? Or is that something we should be thinking about in terms of adjusting our numbers? Let me start there.

So Ali, the amount of expected annual performance change from where we started the year, I would say, is minor in the business. What we're really seeing is a shift of anticipated earnings from one quarter into other quarters. To the extent that it is slightly less than what we originally anticipated. We can look at other levers to help manage our overall performance, including necessary cost levers or other options we have to continue to make us feel good about the earnings guidance that we've given for the year.

Okay. And then overall, how are you looking at your nonutility businesses, given this volatility that creeps up in your earning stream and obviously the negative reaction to your stock price? How do they fit into the predictable growth rate you're thinking about long term? And I put Enable in there as well in terms of your latest thoughts there. And also on Enable, can you just clarify, so your ownership used to be 54.1%. Has that come down? And what is the current ownership in Enable?

Current ownership is 53.8% and the -- that modest or very slight reduction was due to the additional units that were awarded as part of Enable's management LTI compensation program. So that -- does that answer your second question?

That does answer that part, yes.

So the first question you're asking is about variability with our competitive businesses. I want to point out that a look at business performance or competitive business performance on a single quarter basis is where it -- inaccurately or incorrectly characterizes the volatility of the business. And the reason is that the businesses have some seasonality to them, as do our utility businesses, quite frankly, have seasonality to them. So to the extent that you want to characterize a business with greater levels of variability I think we need to look at that overall over the entire course of a year. And what we've seen is consistent performance -- relatively consistent performance over a 12-month period as opposed to some variability you might see with any given quarter.

So these are core for you?

Yes, these are businesses that we are operating and we are looking to grow. And we understand the fundamentals that drive them. And they're complementary to our much larger utility business, which comprises roughly 70% of our total earnings.

Our next question comes from the line of Jonathan Arnold from Deutsche Bank.

I have a question on Indiana and the IRP process. Could we have a -- just a refresher? Are you required to put other options you might pursue out to RFP? Or is this just a question of replacing one rate-based investment with others of a different flavor? Just some sense of timing and how confident you are that this would end up in rate base.

So Jonathan, I'll start with the first. The first one was a question around the process. So State of Indiana has a cycle of do-over -- refreshing the IRP every 3 years. So we're on -- we started our last one that ultimately included the recommendation or the request with the CCGT that started in 2016. So we are in the process now of filing our next one, which was due in 2019 anyway. We believe the process of -- it's a very stakeholder-rich process. That process will take us into probably mid-2020 before the new IRP is finalized. And that IRP process will bring forward the multiple ideas and multiple options in terms of how to meet the generation needs going forward. And then that process will conclude with some recommendations and ultimately the filing on our behalf of equivalent of CPCNs for the solution that we believe is aligned with the stakeholders and the commission. So we would then begin the process of requesting certain elements of generation. Exactly what that looks like is to be determined. We do know that the commission would like to see smaller, more discrete projects in there as a way of hedging against uncertainties in the future. But we do believe given our experience with the last IRP that the alternatives represent investment that are similar to the total investment we had represented in this case. The time frame may change slightly but the amount of investment that we think is needed to achieve our future state, we think is likely to be similar to what we were looking at.

And the confidence of those would be sort of rate base investments as opposed to PPA? I was just curious what -- do you have any comment there?

Yes. I think our confidence at their rate base is reasonably high. We were successful in putting together a project for 50 megawatts of solar that we will have in rate base. And we think that type -- a similar type of approach can provide us rate base opportunities. There may be some element of PPA in there, but we think the preferred path, the one that would be best overall, would be investments that go on a rate base.

Our next question comes from the line of Greg Gordon from Evercore ISI.

I don't want to beat a dead horse on the issue. But I think the volatility in earnings in the gas business has just got some people confused. So if you could just explain to people what the commercial opportunities were that you were able to optimize Q1 last year and why this Q1 was different from last Q1? And why there's durability over the course of the year and your ability to achieve those earnings outcomes.

Fair enough. Greg, I'm going to ask Joe to make some comments on this.

Thanks for the question, Greg. Again as you know, last year there were some extreme weather opportunities in various parts of the nation and those opportunities occurred where we had the ability to optimize those assets at that time. 2018 was unusually favorable as a result of those, offset by less than favorable 2019 from a weather perspective, especially in the areas where we have operations. So when you compare those to year-over-year, it created a tremendous downfall. But as a result of the lack of activity in the first quarter of this year, we are well positioned with our assets, assuming normal weather for the rest of the year to take advantage of that, an opportunity we did not have the chance to do it last year because of the amount of work we did in the first quarter of 2018. If you look at our projections for the rest of the year they are more in line with what we would call a normal year with 2018 being the aberration. So with that, we believe we have the ability to recover going forward for the rest of this year.

Greg, I'll just add to Joe's comments. In the first quarter of '18, when we were able to capitalize on some extreme weather, we essentially utilized the capacity of the storage that we had during the first quarter. And we then spend the balance of the year kind of refilling inventory and refilling storage, which means you don't have opportunities to optimize, whereas in this year, we weren't optimizing as much in the first quarter, those assets are available to us to optimize and we've already begun to sign up commitments for that margin for the latter half of the year.

Got you. Okay. That's more clear. And then with regard to Indiana, it does sound like ultimately there's a need for a generation solution. It just -- it may be configured differently and because of the timing of the IRP that capital might be deployed over a longer time horizon. But ultimately, from my perspective and correct me -- please correct me if I'm wrong, there is a capital need there. It's just a question of the types of resources you deploy and perhaps over a slightly longer time frame. Is that fair?

Yes. Greg, you said it very well. That's the message we were wanting to get across. We absolutely believe that there is a similar investment opportunity to meet those needs. It's just a matter of what it looks like, what those pieces look like and some element of timing given the timing impacts of going through another IRP before we begin to make those investments.

Greg, I would add that for the smaller scale projects, solar for instance, the spending curve is much shorter. So remember that $850 million, very little is in 2020 and before. So the majority of that was in '21 and '23. So if we replace with smaller scale projects, the timing may work out, we just don't know that yet. But smaller scale typically take shorter period to finish.

Our next question comes from the line of Abe Azar from Deutsche Bank.

So just 2 questions. How much merger cost do you expect in the balance of the year?

On Slide 23 we provided you with the year-to-date spend. So year-to-date we spent a little over $110 million. And I think that's roughly half of what we plan to spend for the year.

Got it. And can you break down the pieces within the $0.15 of other on Slide 15?

Sure, absolutely. The majority of the $0.15 is related to 2 things. One is the merger financing. If you remember we had a combination of seniors note, commercial paper, perpetual preferred, convertible and common equity. So the combination of those merger financing is roughly about $0.12 out of that $0.15. Additionally, we took on some more Vectren debt. So that was the interest expense that we didn't have same quarter last year. And we issued some new debt at Houston Electric. But the majority of the $0.15 is related to the merger financing.

Our next question comes from the line of Michael Weinstein from Credit Suisse.

Just to follow up on, I think it was Ali's earlier questions about the Infrastructure business. Can you talk about how that rolling 12-month backlog flowed? How should we think about that number in terms of how it converts into earnings over time? And also I think Vectren's old guidance used to be around $50 million to $54 million for that business a year. And what's the seasonality look like over the course of the year for that business?

So I'll take the second one first. The second part of your question, the seasonality is such that the first quarter is always a very weak quarter for them, in that the majority of their contribution is in what I consider the more construction-friendly times of year of second, third quarter and part of fourth. So the first is traditionally their weakest. And I think we've referenced that in my comments, trying to do a comparison of what performance looked like this year versus last year, even though last year was under the ownership of Vectren. And remind me what your first question was.

It has to do with the backlog number that you put in there.

The backlog, that's right.

Yes. How does that work?

So the best way to think of it now is the amount of contracts that are in place that are to be addressed over the coming 12-month period and that is a -- it's an important measure on kind of a relative basis to what it's been in prior quarters. So as the backlog has grown, it suggests there's more demand in the coming 12 months, more commitments in the coming 12 months than we had in the prior -- maybe the prior look at it. So the backlog is approaching $1 billion at the moment. Forget what the number was last year, it was probably a little -- $750 million, mid-7s type thing. We constantly have new projects that are rolling into the gas distribution type business. Some of those contracts roll off. Some of them get updated and renewed. And then we have new contracts that show up in the transmission side of the business, some contracts roll off and then other ones roll on. One of the big drivers for the sizable increase was a single large project that was contracted at the end of this past year and that's reflected in the numbers. But both the distribution work and the transmission work are both up from the last time this was reported.

All right. What's the average length of time that you work on a project? How should we divide that $1 billion number? Into how many years?

Michael, this is Joe. Again on the -- those contracts can vary. They can be anywhere from 3 to 4 months up to 12 months to 18 months. As Scott reflected, we try to average that, but over -- that $1 billion that we have in backlog will be realized over the next -- between now and 18 months from now.

Our next question comes from the line of Steve Fleishman from Wolfe Research.

Scott, can you disclose what this $300 million transmission project is? The one in your backlog?

We have not disclosed it by company name, if that's what you're asking.

Okay, okay, okay. So I can't just track which one it is. Okay.

That's right. Yes.

All right. And then I guess separately, just is there any kind of refreshed or change in views on Enable's strategy or thought process?

No. I mean we've commented each time we meet that we appreciate Enable's performance and their contribution that they make to us. We know that, that market is challenged at the moment. The capital markets are challenged there. But we're pleased with Enable's performance and the contribution they are making to us. I think that's probably the best way to summarize it.

Our next question comes from the line of Aga Zmigrodzka from UBS.

How has the integration process of Vectren been progressing? Have the assets so far operated in line with your expectation?

Yes, integration is going extremely well. As we mentioned earlier, we've taken the necessary actions to begin achieving our targeted synergies. And we've also put in place the management structure to begin operating the businesses that have overlapped combination, like our gas LDC businesses. So that's all been put together. So we're operating it as a single business, which is what helps drive the performance that we expect for customers. It also helps drive the financial performance that we've targeted. So integration has been going very well in my opinion.

[Operator Instructions] Our next question comes from the line of Ali Agha from SunTrust.

Scott, just one clarification. This CCGT in Indiana, was this a product of the 2016 IRP? And if so, I mean if the commission changed their mind now, could they also change their mind by 2022 when you file the '19 IRP? Just give us the context of where this project came from?

Yes. The project was the result of the 2016 IRP, and -- but as you go through that IRP process and you present your findings, there's input provided and commentary. There is no approval, if you will, of the IRP. There's just a recognition of the merits of different options and then we proceed with filing our request for investment that we want to make against that IRP. Clearly, our views was that it was the low-cost solution. But I think the difference in time between when the IRP started in '16 and when it -- and where we find ourselves today, that the commission understands we need to make investment, but they wanted to see the investment made in a way other than a bet on one single large plant. Now you ask the question, is it possible that commissions can change their mind? We all know that's the case. So what we plan to do with this next revision is take the direction that they provided about the future and modify our thinking and plans in a way that aligns with the direction they gave us. And our hope is that when we get to the point of submitting requests for investment and recovery that we will minimize the chances that they will not be supportive of that.

I see. But to be clear, they had never blessed their CCGT either directly or indirectly?

They don't do it until you actually file the CPCN and the filing goes through of that particular request for that particular asset.

Our last question today comes from the line of Insoo Kim from Goldman Sachs.

Just one quick follow-up. I know we asked questions around this in the last call regarding the guidance and inclusion or exclusion of the cost to achieve the merger synergies. As I look at your deck today, I don't think the language has changed. But I'm still trying to get clarity on whether '19 -- it seems like it's saying it's exclusive of costs to achieve synergies versus 2020 guidance, which says it's inclusive to those savings. Am I reading that right? And if that's the case on a more apples-to-apples basis for 2020 if you exclude those costs to achieve, is the range actually higher than what you're providing?

So Insoo, let me try to clarify -- the benefits is as we talk about guidance for 2019 we are excluding the cost to achieve. So those are excluded from our guidance EPS. When we get to 2020, our EPS guidance range that we have provided is inclusive of those costs to achieve. Now what we said on the last call was $75 million to $100 million in 2020 of benefit and what we didn't clarify until now is what we believe the costs to achieve number would look like in 2020. So here we've just provided an update to that of $15 million to $25 million of expected costs to achieve in 2020. That's a new number that is really kind of an offset to the $75 million to $100 million that we provided. And it's the -- all of that is inclusive in the range that we gave, our earnings range for 2020.

Right. So $15 million to $25 million is the cost related to it. So if you take that out, am I thinking about that right -- the right way -- that, that's actually a benefit?

That's the right way to think about it. You could for the year if you're wondering what the net was, it's closer to the delta between those. And as you think about going beyond 2020 then cost to achieve is lower in 2021, for example.

We have no further questions in queue. I'll turn the call back over to the presenters for closing remarks.

Thank you, Lisa. Thank you, everyone, for your interest in CenterPoint Energy. We look forward to seeing many of you at the upcoming AGA conference. We will now conclude our first quarter 2019 earnings call. Have a great day.

This concludes CenterPoint Energy's First Quarter 2019 Earnings Conference Call. Thank you for your participation.