CenterPoint Energy, Inc. (CNP) Q1 2019 Earnings Report, Transcript and Summary

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 the issuance of debt and equity securities to fund the merger that resulted in higher net interest expense and higher common stock share count. Both the 2019 and 2020 guidance ranges consider operations performance to date and assumptions for certain significant variables that may impact earnings, such as customer growth, approximately 2% for electric operations and 1% for natural gas distribution; and usage including normal weather, throughput, commodity prices, recovery of capital invested through rate cases and other rate filings, effective tax rates; financing activities and related interest rates; and regulatory and judicial proceedings; as well as the volume of work contracted in our Infrastructure Services business. The ranges also consider anticipated cost savings as a result of the merger. The 2019 guidance range assumes Enable Midstream Partners 2019 guidance range for net income attributable to common units provided on Enable's first quarter earnings call on May 1, 2019. The 2020 guidance range utilizes a range of CenterPoint Energy scenarios for Enable's 2020 net income attributable to common units. The 2020 range also considers the estimated cost and timing of technology integration projects. In providing this guidance, CenterPoint Energy uses a non-GAAP measure of adjusted diluted earnings per share that does not consider other potential impacts, such as changes in accounting standards or unusual items including those from Enable, earnings or losses from the change in the value of the ZENS securities and the related stocks or the timing effects of mark-to-market accounting in the company's Energy Services business, which along with certain excluded impacts associated with the merger could have a material impact on GAAP reported results for the applicable guidance period. CenterPoint Energy is unable to present a quantitative reconciliation of forward-looking adjusted diluted earnings per share because changes in the value of ZENS and related securities and mark-to-market gains or losses resulting from the company's Energy Services business are not estimable as they are highly variable and difficult to predict due to various factors outside management's control. During today's call and in the accompanying slides we will refer to Public Law No. 115-97, initially introduced as the Tax Cuts and Jobs Act as TCJA or simply tax reform. Before Scott begins, I would like to mention that this call is being recorded. Information on how to access the replay can be found on our website. I'd now like to turn the call over to Scott.

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 and higher financing costs associated with the merger. Our business segments continue to implement their strategies, which are focused on safely addressing the growing needs of our customers while enhancing financial performance. It is worth mentioning that our first quarter 2018 guidance basis earnings of $0.55 per diluted share represented 34% of total earnings for 2018, largely due to weather-driven opportunities at Energy Services that allowed the company to capture earnings early in the year. By comparison, in the years 2015 through 2017, first quarter guidance basis EPS represented 27% to 28% of our annual guidance basis EPS. Considering this more historic distribution of earnings, our first quarter 2019 guidance basis EPS excluding merger impacts is aligned with our EPS guidance range of $1.60 to $1.70 for the year. Now I will cover business highlights starting with Houston Electric on Slide 6. Core operating income, excluding merger-related expenses of $10 million, was $84 million in the first quarter of 2019 compared to $99 million in the first quarter of 2018. This decline of $15 million includes 2 anticipated reductions: a $10 million reduction in equity return and a $6 million decrease in revenue as a result of tax reform, which is offset by a reduction in income tax expense. Absent these known reductions, Houston Electric was up quarter-over-quarter. Xia will provide more detail later in the call. On April 5, we filed the first Houston Electric rate case in nearly a decade, requesting an ROE of 10.4% along with a 50% equity, 50% debt capital structure. The rate case includes all invested capital through the end of 2018, including investments made as a result of Hurricane Harvey. After new rates have gone into effect, we anticipate we will seek recovery for investments made since the end of 2018, utilizing our distribution and transmission investment recovery mechanisms, known as DCRF and TCOS, respectively. As a reminder, DCRF is filed in April, reflecting the prior calendar year's qualifying distribution investment and TCOS may be filed twice per year. We continue to see strong growth in our electric service territory in Texas, adding nearly 41,000 metered customers since the first quarter of 2018. It is worth noting we have added approximately 400,000 customers since the last rate case and we're proud of the part CenterPoint Energy plays in servicing that growth. We included Slide 17 in the appendix to demonstrate the consistent customer growth at Houston Electric over the last 30 years. Turning to Slide 7. Indiana Electric contributed operating income of $11 million for the February 1 through March 31 period, excluding merger-related expenses of $20 million. In March, the Indiana Utility Regulatory Commission or IURC approved construction of a 50-megawatt universal solar array. In late April, the IURC approved both our plan to retrofit Culley Unit 3 and recover certain costs associated with ash ponds as well as past power plant pollution control investments. These capital expenditures will be recovered through a new annual environmental cost adjustment mechanism. Rather than approve our plan to build a 700 to 850-megawatt combined-cycle natural gas turbine or CCGT, the IURC instructed us to minimize the risk that any one fuel source becomes uneconomic by pursuing multiple smaller scale options. The IURC concluded these smaller scale options would better position Indiana Electric to respond to changing circumstances. We have begun work on a new integrated resource plan that reflects the direction provided by the commission. This plan is expected to be finalized by mid-2020 and will form the basis for future requests to transform our generation resources. Approximately $850 million of capital, primarily in the 2021 to 2023 period, is associated with the previously-planned CCGT plant. And while we cannot know the outcome of the new plan until the analysis is completed, we know that alternative capital investments identified in our 2016 integrated resource plan were of similar magnitude. For a complete overview of both electric segments' year-to-date regulatory developments, please see Slide 18. Now turning to Slide 8. Natural gas distribution operating income in the first quarter of 2019 was $220 million compared to $156 million in the first quarter of 2018, excluding merger-related expenses of $53 million in the first quarter of 2019. This includes operating income from the newly-added businesses in Indiana and Ohio, which Xia will further detail in her walk-through of the segment. Natural gas distribution added nearly 1.1 million customers since the first quarter of 2018, more than 45,000 in legacy CenterPoint jurisdictions and the remainder as a result of the merger. This business continues to benefit from effective annual cost recovery mechanisms, which can be utilized in 7 of the 8 states we serve. These mechanisms include the Gas Reliability Infrastructure Program or GRIP in Texas, the Formula Rate Plan or FRP in Arkansas and the Distribution Replacement Rider or DRR in Ohio. We continue to anticipate a final order from the Public Utilities Commission of Ohio in the second or third quarter of this year regarding the settlement agreement, which reflects a $23 million increase in annual revenues. We anticipate filing rate cases during the fourth quarter in Minnesota and the Beaumont, East Texas jurisdiction. For a complete overview of natural gas distribution's year-to-date regulatory developments, please see Slides 19 and 20. We were pleased with the performance of both the legacy CenterPoint and the newly-acquired jurisdictions. Turning to Slide 9. Energy Services operating income was $14 million in the first quarter of 2019 compared to $54 million in the first quarter of 2018, excluding a mark-to-market gain of $19 million and a loss of $80 million respectively. On average, roughly 80% of annual operating income is considered base business, with the remainder considered opportunities managing storage assets, which benefit from nonnormal weather in specific locations. Given the extreme weather conditions in the first quarter of 2018, our financial expectations for first quarter of 2019 were below what we achieved in first quarter of '18. Further, market conditions did not support our planned level of optimization in the quarter. As a result, we have assets in storage that we believe better position us to capitalize on opportunities through the remainder of the year. Therefore, under normal weather conditions, we expect full year operating income to be at or near 2018's level of $63 million, excluding mark-to-market impacts. Infrastructure Services, acquired as part of the merger, is a new business for CenterPoint. This segment is primarily focused on pipeline construction and maintenance for natural gas distribution as well as transmission pipelines for natural gas, oil and liquids. Infrastructure Services had an operating loss of $1 million for February and March as part of CenterPoint Energy, excluding merger-related expenses of $15 million. For reference, the business' full quarter operating loss, including January and excluding merger-related expenses, was $11 million compared with an operating loss of $14 million in the first quarter of 2018 as part of Vectren. This business is typically weaker during the first quarter as less work can be done during cold weather months. However, the backlog for the next 12 months is almost $1 billion, over $200 million higher than the backlog at this time last year, which we believe suggests ongoing strong demand for the business. On Slide 10, we've captured some of the highlights from Enable's first quarter earnings call on May 1. Enable reported strong rig activity as well as higher volumes of natural gas gathered, processed and transported as well as higher volumes of crude oil and condensate gathered. Enable's recent Gulf Run Pipeline project, anticipated to be completed in 2022, is backed with a long-term agreement with Golden Pass LNG. And we anticipate the project will provide a valuable earnings contribution to Enable for decades to come. We are pleased with Midstream Investments performance. On Slide 11, we are reiterating our guidance for 2019, our guidance for 2020 and our EPS growth target CAGR of 5% to 7%. We have begun realizing the anticipated merger benefits with more than $50 million of projected cost savings for 2019, excluding costs to achieve. Xia will discuss merger savings and costs to achieve in more detail. Overall, our businesses are performing well. We enjoy strong fundamentals that will continue to drive our earnings growth. Our continued focus on safety, reliability, customers, communities and financial performance will serve us well as we work to optimize our businesses post-merger. As many of you know, Xia Liu joined CenterPoint a few weeks as our new Chief Financial Officer. Xia brings with her tremendous experience with more than 20 years in the utility industry, including roles in finance, operations, regulatory and corporate strategy. Today, Xia will cover additional financial details and wrap up the prepared remarks. I also know she's looking forward to catch up with -- catching up with many of you at the upcoming AGA conference. Xia?

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 pleased that Houston Electric’s core business performed in line with our expectations. Turning to Slide 14. Natural gas distribution performed very well for the quarter. Operating income for the first quarter of 2019 was $167 million versus $156 million for the first quarter of 2018. Lower revenues related to TCJA provided a $12 million negative impact to operating income with an offset in income tax expense. Rate relief provided a $21 million positive variance and customer growth provided a $5 million benefit. Decoupling timing provided a $15 million positive variance, and higher O&M accounted for an $8 million unfavorable variance. Additionally, depreciation and taxes accounted for a $3 million unfavorable variance. Newly acquired Vectren businesses contributed $46 million and merger-related expense was $53 million. Overall, excluding TCJA and merger-related expenses, natural gas distribution was up $76 million with the legacy CenterPoint business up $30 million. We are pleased with the performance and are on track with our expectations for this business. Slide 15, we have the consolidated guidance basis EPS drivers. We started with $0.55 for the first quarter of 2018. Within utility operations, Houston Electric was lower by $0.02 attributable to lower equity return that we discussed earlier. Newly acquired Indiana Electric contributed $0.02. Our natural gas distribution business added $0.14, $0.05 from our legacy business and $0.09 from the newly added Indiana and Ohio jurisdictions. With regard to our competitive business, as Scott detailed earlier, Energy Services was lower by $0.07. Infrastructure Services had no impact on the variance for the quarter. Midstream Investments was down $0.01, inclusive of a $0.02 charge related to dilution that Scott discussed earlier. Merger financing impacts post February 1 and interest associated with the debt acquired in the merger were the primary drivers of the remaining $0.15 negative variance. Overall, our first quarter 2019 EPS on a guidance basis, excluding merger impacts, was $0.46s per diluted share. Now I need to provide some details associated with the merger. In terms of cost savings as well as costs to achieve those savings, as Scott mentioned, in 2019, we now begun realizing the anticipated merger benefits with more than $50 million in projected cost savings for the year, excluding costs to achieve these savings. In 2020, as discussed on our fourth quarter 2018 call, we continue to anticipate savings in the range of $75 million to $100 million. This range does not include approximately $15 million to $25 million of costs to achieve those savings primarily technology integration expense. For additional detail on year-to-date merger-related expenses, including the amortization of intangibles that we exclude from 2019 guidance, please see Slide 23 of the appendix. Before I wrap up my comments, let me remind everyone of CenterPoint's commitment to solid investment grade credit quality. We believe strong financial integrity and credit quality provide long-term value to our customers and shareholders. Let me also remind everyone of our recently declared dividend of $0.2875 per common share. This is an approximate 4% increase relative to a year ago and consistent with our 4% annual increases in dividends over the last several years. CenterPoint has paid dividends each quarter since our company’s inception in 2002, demonstrating our commitment on delivering long-term value to our shareholders. I'd like to wrap my comments with some closing thoughts. I'm honored to be a part of CenterPoint Energy's leadership team and I'll -- work alongside Scott to help lead the company forward following our strategic merger with Vectren. We will work hard to deliver long-term value from the merger to investors and customers for years to come. CenterPoint Energy is strong, diversified company with strong values and a strategy that keeps us focused on the priorities to safely meet the needs of a growing customer base, realize financial growth and deliver shareholder value. Operationally and strategically, we are well positioned to meet customers' future energy delivery needs through a combination of traditional and innovative solutions. I'll now turn it back to David.

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.