CenterPoint Energy, Inc. (CNP) Q4 2017 Earnings Report, Transcript and Summary

Good morning and welcome to CenterPoint Energy's Fourth Quarter and Full Year 2017 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's remarks. [Operator Instructions] I will now turn the call over to David Mordy, Director of Investor Relations. Mr. Mordy?

Thank you, Jennifer. Good morning, everyone. Welcome to our fourth quarter and year end 2017 earnings conference call. Scott Prochazka, President and CEO; and Bill Rogers, Executive Vice President and CFO; will discuss our fourth quarter and full year 2017 results and provide highlights on other key areas. Also with us this morning, are several members of management who will be available during the Q&A portion of our call. In conjunction with the call today, 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 press release and our slides. They have been posted on our website, as has our Form 10-K. Please note, we may announce material information using SEC filings, press 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 is going to 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 risks 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 our guidance for 2018. The guidance range considers Utility Operations performance to-date and certain significant variables that may impact earnings such as weather, throughout, commodity prices, effective tax rate, financing activities and regulatory and judicial proceedings to include regulatory action as a result of recent tax reform legislation. In providing this guidance, the Company uses a non-GAAP measure of adjusted diluted earnings per share that does not include other potential impacts such as changes in accounting standards or unusual items, earnings or losses from the change in the value of the Zero-Premium Exchangeable Subordinated Notes or ZEN securities and the related stocks, or the timing effects of mark-to-market accounting in the Company's Energy Services business. The guidance range also considers such factors as Enable's most recent public forecast and effective tax rates. During today's call and in the accompanying slides, we will refer to Public Law Number 115-97, initially introduced as the Tax Cuts and Jobs Act as TCJA or simply tax reform. Before Scott begins, I want to mention that we expect to increase our -- we expect to release our 2017 corporate responsibility report in March; our report will follow the Global Reporting Initiative format. We look forward to sharing additional insight on CenterPoint with investors. Finally, this call is being recorded. Information on how to access the replay can be found on our website. And with that, I will now 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. I will begin on Slide 4. 2017 was a strong year for CenterPoint. This morning we reported 2017 diluted earnings per share of $4.13. On a guidance basis, excluding the benefits of tax reform we finished the year at $1.37 per share versus 2016 earnings of $1.16 per share, an increase of more than 18%. The $1.37 for 2017 is $0.04 above the top end of the $1.25 to $1.33 guidance range we set in January of last year. Our strong performance in 2017 can be primarily attributed to growth in our core businesses, in addition to the performance of midstream investments. Turning to Slide 5; we added more than 70,000 combined utility customers in 2017. Additionally, rate relief added approximately $90 million for the combined utilities. 2017 also saw numerous operational achievements including the installation of all structures for the Brazos Valley Connection and finishing the replacement of all cast iron pipe in Texas and Minnesota. Hurricane Harvey tested our system and demonstrated the value of past investments in technology and grid hardening. We also completed an acquisition in our CES business which was accretive in its first year. In short, we saw several opportunities and handled numerous challenges in 2017 and I'm proud of what our nearly 8,000 employees accomplished. On Slide 6, you can see Houston Electric had a solid 2017. Core operating income was $535 million in 2017 compared to $537 million in 2016. Excluding equity return operating income increased 4.2%, primarily due to rate relief and continued customer growth. Houston Electric added nearly 41,000 metered customers last year and we were able to use both of our investment cost recovery mechanisms to effect timely rate relief. These increases were partially offset by increases in depreciation and operations and maintenance expenses, as well as lower usage and miscellaneous revenues as compared with 2016. Turning to Slide 7; in response to ongoing customer and load growth and lessons learned from hurricanes this past year, Houston Electric will continue to invest significant capital to ensure our system has sufficient capacity and is safe, resilient and reliable. Our most recent 5-year plan includes $4.8 billion of capital investment at Houston Electric. This plan is now inclusive of the approximately $250 million Bailey to Jones Creek project that will serve the growing needs of the petrochemical industry in the Freeport, Texas area. This project was endorsed by the Electric Reliability Council of Texas or ERCOT in December of 2017. We expect to file an application for approval with the PUCT later this year and anticipated a decision in 2019; we would begin construction shortly after approval. I'm very pleased with Houston Electric strong operational and financial results in 2017 and we expect continued growth in the coming years. Moving to Slide 8; natural gas distribution delivered strong results in 2017. Operating income was $328 million in 2017 compared to $303 million in 2016, an of 8.2%. The business benefited from rate relief, customer growth and higher transportation revenues. During the second quarter, we also had a $16 million benefit due to the recording of a regulatory asset and a corresponding reduction in expense to recover prior post retirement expenses in future rates. These benefits were partially offset by increased depreciation and amortization, and operations and maintenance expenses, in part due to acceleration of selected reliability projects. Natural gas distribution added more than 30,000 metered customers last year with Texas and Minnesota leading the growth. Turning to Slide 9; we invested $523 million of capital in our natural gas distribution business in 2017. Our new $3.2 billion 5-year capital plan reflects steady growth and focuses on safety, growth, reliability and infrastructure replacement. This was an impressive year for natural gas distribution, especially considering we started the year with an extremely warm first quarter throughout our service territories. Turning to Slide 10; our capital plan is expected to translate to an annualized consolidated average rate base growth of approximately 8.3% through 2022. The majority of this growth is driven by strong capital investment. Tax reform also contributes to the growth; changes in tax depreciation at the lower federal rate are expected to increase forecasted year end 2019 average rate base by approximately $300 million. This increase in rate base will be included in our normal recovery mechanisms beginning as early as 2018. Moving to Slide 11; in 2017, the Texas legislature passed a law that provides permanence for the distribution investment recovery mechanism removed the four time limit on its use between rate cases and calls for the PUCT to create a rate case schedule for all Texas electric utilities. Given that our last rate case occurred in 2010, we recently agreed to file a base rate case no later than April 13 of 2019. Our most recent Earnings Monitoring Report or EMR for the year 2016 indicated a 9.6% ROE which is below our allowed our ROE of 10%. Additionally, rather than waiting until our next rate case to incorporate tax reform, we will utilize the existing electric rate mechanisms, TCOS and DCRF to accelerate returning certain tax reform benefits to our customers; this will not impact expected earnings. With our natural gas distribution business, tax reform related benefits for our customers will be incorporated through rate cases, annual mechanisms or other regulatory proceedings and will differ from state to state. Turning to Slide 12; Energy Services delivered solid results in 2017. Operating income was $46 million 2017 compared to $41 million in 2016, excluding a mark-to-market gain of $79 million and a loss of $21 million respectively. This improved performance was achieved despite incurring $5 million of expenses, specifically related to acquisition and integration cost during the year. We expect to capture synergies and reduce G&A overtime as we realize economies of scale. We anticipate energy services will contribute $55 million to $65 million in operating income in 2018. Slide 13 shows some of Enable's highlights for 2017. Enable performed very well in 2017 exceeding their net income guidance range. Operationally, they had record results achieving their highest full year performance on gathered volumes, processed volumes, NGLs produced, and volumes transported since their formation. Enable remains on-schedule for key project integrations and completions throughout the year. As of February 5, Enable had 49 active rigs, drilling wells connected to their gathering system. We continue to believe Enable is well positioned for success; they have an attractive footprint, strong balance sheet, and are focused on pursuing accretive growth and maintaining a solid distribution coverage ratio which was 1.2x in 2017. Slide 14 illustrates the spirit of our industry, our Company, and our employees. When energy delivery systems are devastated, we respond. Many came to our aid following Hurricane Harvey, we were pleased to help Puerto Rico with their hurricane restoration effort. I will wrap it up with Slide 15. Today we are announcing our 2018 guidance range of $1.50 to $1.60 per share. We're also targeting guidance EPS growth of 5% to 7% in 2019 and in 2020 off the previous year's EPS on a guidance basis. In 2017, each of our business units had solid operating income growth excluding equity return for Houston Electric. Our projected 5-year rate base CAGR of 8.3% is strong as we invest to meet the needs of our growing service territories. Bill will now provide more detail on CenterPoint's financial performance, impacts of tax reform, balance sheet strength, and capital formation. Bill?

Thank you, Scott. Let me begin with a reconciliation of our GAAP and guidance basis earnings for the fourth quarter of 2017 shown on Slide 17. This morning we reported fourth quarter earnings of $2.99 per diluted share, $2.89 on a guidance basis, and $0.33 on a guidance basis without the benefit of tax reform. This compares with reported earnings of $0.23 per diluted share and guidance basis earnings of $0.26 per share for fourth quarter of 2016. In the fourth quarter of 2017, we subtract $0.09 of mark-to-market adjustments for our Energy Services business, and $0.01 as ZENS related adjustments in order to arrive at a guidance basis earnings of $2.89. We then subtract the $2.56 per share benefit associated with tax reform to arrive at $0.33. This represents a 27% improvement on a guidance basis adjusted for tax reform on a quarter-to-quarter basis. For the full year 2017, we reported $4.13 and earnings per diluted share. $3.93 on a guidance basis, and $1.37 on a guided basis without the benefit of tax reform; this compares with a reported earnings of $1 per diluted share and guidance basis earnings of $1.16 for full year 2016. For 2017, we subtract $0.12 of mark-to-market related adjustments from our Energy Services business, and $0.08 of ZENS related adjustments in order to arrive at a guidance basis earnings of $3.93. We then subtract the $2.56 benefit associated with tax reform to arrive at $1.37. This represents an 18% improvement on a guidance basis adjusted for tax reform on a year-to-year basis. Turning to Slide 18; I will review our year-over-year utility operation EPS walk on a guidance basis excluding tax reform. We began with $0.80 in 2016, operating income improvements excluding amounts associated with the equity return equate to a net $0.07 per share improvement. We had further $0.03 per share improvement from interest expense reduction despite approximately $650 million in additional borrowing at year end '17 relative to year end '16. Interest expense benefit was primarily due to the refinancing and balance sheet management of our company. Equity return reduced earnings by $0.03 per share and other income improved earnings by $0.04 per share. Other income include $17 million in lower charges for bond redemptions relative to 2016 and a $14 million in additional income from a full year of dividends on the Enable preferred securities. This brings us to $0.99 for utility operations in 2017 over a 12% improvement versus 2016. Now turning our attention to Slide 19; we showed the combined $0.11 per share utility improvement and $0.10 per share year-on-year improvement from our midstream investments bridging the $1.16 of 2016 guidance basis EPS and the $1.37 of 2017 guidance basis EPS without tax reform. As depicted on this slide, midstream investments included $0.04 of improvement from mark-to-market accounting on commodity derivatives. Slide 20 highlights the impact of tax reform on CenterPoint. We anticipate a shift upward in earnings of approximately $0.10 in 2018, primarily as a result of a lower effective tax rate for our income from unregulated businesses. We anticipate the effective tax rate will decrease from approximately 36% in 2017 to approximately 21% in 2018 as a result of tax reform. This effective tax rate of 21% is inclusive of state taxes and the projected amortization of excess deferred income taxes through the income tax expense line. There are four impacts on our cash flow as a result of tax reform. First, the change in tax depreciation expense at the lower tax rate reduces tax shield, thereby reducing expected near-term cash flows. Second, the timing of the return of the excess deferred tax regulatory liability may reduce expected near-term cash flows; this will ultimately depend upon the amortization schedules established in each jurisdiction. The third impact relates to our income that is not under utility rate regulation; that income will now enjoy the benefit of a lower cash tax rate. The final impact is also expected to be positive to our cash flow; Enable has the option to elect -- to fully expense its capital investments for tax purposes. Should Enable make this selection, this will create greater tax shield at the CenterPoint consolidated income tax return level. In aggregate, we anticipate a reduction in expected near-term cash flows as a result of tax reform. However, we do not foresee this impacting the strength of our balance sheet or our ability to maintain our credit metrics at/or above our target ranges. Slide 21 provides more detail on our balance sheet and the credit metric impacts of tax reform. My first comments relate to the deferred tax liability adjustments at year end. This tax benefit recorded at year end associated with the tax reform improved our year end consolidated equity to capital ratio from 35% to 40%. Additionally, as the capital base at Houston Electric and CERC improved, we were able to reduce the percentage of our holding company debt to total debt from 21% at year-end 2016 to 14% at year-end '17. Regarding our credit metrics, for the full year 2017 adjusted FFO to debt was approximately 24%. As noted earlier, our debt increased by $650 million in 2017. Over $300 million of this increase was temporary in nature and that it was associated with working capital financing as we experienced higher gas prices and much colder weather right at year end. We anticipate adjusted FFO to debt will be reduced by approximately 300 basis points in 2018, principally as a result of the cash flow impacts from tax reform as discussed earlier. Finally, tax reform is a win for CenterPoint utility customers as a result of the $1.3 billion regulatory liability and the lower 21% federal tax rate for 2018 and beyond. As discussed earlier, these benefits will be returned to customers through various mechanisms or rate proceedings for each jurisdiction. On Slide 22, we note our planned $1.7 billion investment for 2018 and our current ratings with Moody's, Standard & Poor's, and Fitch. Our financing plan for 2018 does not contemplate the issuance of common equity, nor does it suggest a need to sell some of Enable units as a source of capital. As we've shared in the past, our goal over a multi-year period remains to reduce our exposure to commodity prices through the sale of Enable common units in public equity markets or otherwise. The timing and the size of any sale will be subject to equity market conditions. With any action we take, Enable's public float will likely impact sizing. As a reminder, approximately 80% of the common units are currently held by the general partners. Net proceeds from any sale will support our balance sheet and the recently announced increase investment in our utilities. In December we announced $0.2775 per share quarterly dividends. This represents a 4% increase over the previous quarterly dividend, consistent with our 4% increases in 2015, 2016 and 2017. This marks the 13th consecutive year we have increased our dividend. Further, we have had a significant reduction in our dividend payout ratio. Assuming the midpoint of our 28 guidance basis EPS range and annualizing the recently declared dividend over four quarters, our dividend payout ratio will have been reduced from 90% in 2015 to 72% in 2018. Let me wrap up by reiterating five key messages; first, as a result of higher capital investment and the changes in tax depreciation rates for utility investments we now have a combined expected average rate base growth above 8% through 2022. Second, our credit metrics are strong with adjusted FFO to debt projected to remain above 20%, which means we are not anticipating a secondary offering of equity in 2018. Third, 2017 guidance basis EPS without the tax reform benefit surpassed our EPS guidance range for 2017 and produced an 18% increase over 2016. Fourth, we've provided 2018 guidance with a midpoint 13% above our 2017 guidance basis EPS excluding tax reform benefit. And fifth, we are targeting guidance basis EPS growth of 5% to 7% off our prior year EPS in each of 2019 and 2020. I will now turn the call back over to Dave.

Thank you, Bill. We will now open the call to questions. In the interest of time, I will ask you to limit yourself to one question and a follow-up. Jennifer?

[Operator Instructions] Our first question is from Michael Weinstein with Credit Suisse.

I understand no equity for 2018, maybe you could comment on how financing will shape up in terms of equity and debt going forward through 2022?

With respect to 2019 and beyond, I think it's -- let's begin with -- we have a commitment to our capital investment on our utilities, we have a commitment to our credit quality, and we've spoken about our dividend; therefore, I think it will matter what the forward-looking credit metrics are at that time and how much debt we can reasonably take on and whether we should consider sales of Enable units as a source of financing and/or sales of common equity. In any event if we were to consider the sale of common equity, it would be modest.

Just a follow-up question on Enable; now that you'll be holding onto it a little bit longer than I think the original plan would have been if you had been able to sell it through a direct sale. I'm just wondering if this changes your view on M&A. In other words, is there a view that the company needs to acquire more regulated utilities or more regulated exposure considering that you will be holding on to Enable probably longer than you initially planned?

I don't believe the status of where we are with Enable impacts our views with respect to M&A. Our comments in the past have been that we have -- we've got a very large capital budget, as you've seen $8.3 billion over the next five years that we can invest organically, and can grow our core utility business through that investment with known returns. To the extent we were to look at anything outside of that we have to weigh the returns available against what we can get internally. So, perhaps opportunistic but our core attention remains on our -- on the investments in our core business.

Our next question comes from Julian [ph] with Bank of America.

So perhaps just to follow a little bit up on the commentary, on the balance sheet impact and the cadence of the Enable share monetization; how are you think about that through the forecast period? I mean, obviously you've commented that I believe I understood that no sale for this year, but how are you thinking about the future years against the backdrop of where you want your balance sheet to be from a FFO to that perspective?

Just to clarify our prepared remarks, we said that we do not require the sale of Enable units to support the strength of our balance sheet and credit metrics in 2018. With respect to the cadence of any sales, I think there are two points for consideration; one is capital markets considerations in the sector and Enable, so we want to be doing that constructively in the marketplace. We also want to be respectful of any capital formation needs that Enable might have. And then the second consideration is our use of proceeds and strengthen our balance sheet to redeploy that into our utilities businesses.

Maybe to help provide a little bit more certainty around this; what is the FFO to debt that you're thinking about through the forecast period? Obviously, you're talking about a 300 basis point impact on '18 metrics; would you expect us to support that kind of a roughly consistent level, net of the drop here?

Should be at that level, if not higher.

But still from a modeling perspective, it would be probably a good assumption for us to backfill monetization of units to kind of keep you there?

That would be one way to approach it.

Your next question comes from Ali Agha with SunTrust.

Bill, when you look at your CapEx plan which you've laid out to us through 2022, and the rate base growth assumption that goes with that; does that provide you also visibility or confidence that this 5% to 7% growth rate to 2020 could actually continue through 2022 which is kind of the timeframe for your CapEx plan?

Ali, I think one way to think about this is we've provided growth guidance in earnings for shorter period then we've provided CapEx for; and that's because of visibility around Enable, primarily. But as you can tell from our spending that the impacts associated with earnings are coming from the utilities would conceptually continue given the CapEx that we're spending throughout the entire plan period.

And on Enable, I understand you talked about the balance sheet issues to keep an eye on, the capital markets etcetera; but just strategically coming back to your original premise that you don't want that commodity exposure as part of your business mix or earnings profile. So from a strategic perspective, when would you like to have that exposure eliminated from the overall CenterPoint portfolio?

We haven't specified a timeline, what we have done as you know is, go through the process of considering options that were more rapid exit from this investment; and as you know, none of those worked for us. So having completed that we are now in the mode of focusing on selling units in a constructive fashion over a longer period of time to reduce our exposure to the commodity space. And as we've outlined, we don't have any specificity on what that looks like other than to say; over a period of time, we intend to reduce our exposure and ownership here.

And lastly just to clarify; I believe it was in the slides but the '19 and '20 growth rate numbers that you've laid out for us, that does not assume any sale of any units of Enable, that just assumes your current ownership continues in those two years as well?

I'd say that the fairest way to say that is, we are committed to targeting that growth rate over this period of time and we've considered a number of options for financing on how we could get there.

Our next question comes from Insoo Kim with RBC Capital Management.

In terms of a sell down of Enable units, would there be a possibility for you to pursue potential private placements instead of at the market type of transactions that will enable you to tellegrade [ph] a portion of the unit at a faster pace?

You're correct and that remains an option. Our only constraint there is in our partnership agreement, we can -- are limited to selling no more than 5% of our current holdings to one buyer.

My second question is, I might have missed it but is the proposed $250 million Freeport project included in the 5-year forecast that you laid out or is it not?

Yes, it is now included in the new $8.3 billion total.

Our next question is from [indiscernible].

Bill, I'm having a little bit of trouble [indiscernible]; 8.3% CAGR growth in rate base but only 5% to 7% growth in next '19 and '20. So does that mean you're expecting a higher growth rate past '20 or is there something else? And then, I am seeming that Enable stays off the discontinued operations; are you expanding for example, fee as a drag down earnings going forward?

I think you're right, directionally, and that rate base growth should translate into EPS growth with adjustments for regulatory lag and any common equity that utility company might contemplate. We have a visibility into what our midstream segment will produce in the next three years, there are midstream segment as publicly said, only what 2018 looks like. So suffice it to say until we get better visibility over the longer term period, we're not able to stretch out that growth rate beyond 2020.

So when you're say that -- what I think you're saying actually I should say and that while you expect a certain outcome you're not going to commit to it until there is more visibility from the midstream sector. Am I right?

Yes.

Then we should be conservative.

We think we're providing a reasonable view of growth through the 3-year window that we are providing, given the visibility that we have to the various business components.

Our next question is from Charles Fishman with Morningstar Research.

Bill, I just want to confirm -- I appreciate your comments on the dividend payout ratio overall, but your dividend policy has not changed; in other words, 60% to 70% payout at the utility and I think it was 90% flow from Enable; is that correct?

The way we express this is, first thing, the Board takes a look at our dividend every quarter, our capital needs, the strength of our financials, and so forth; and then decides whether the clear dividend. With respect to the trajectory of the dividend we are intending to grow the dividend, we have deliberately shared that it grew 4% in each of '15, '16, '17 and '18; we recognize that it is a lower growth rate than our earnings per share growth rate but that allows us the ability to retain earnings and reinvest that capital in our utility business.

But at the end of the day, I mean, because of Enable you still -- and I realize Enable is only going out this year on their guidance but it does put you in a position to be at the upper end of that 60% to 70% and the Board would still feel comfortable potentially, correct?

I won't speak for the Board but I think we're certainly comfortable with the dividend payout ratio we have today.

Our next question is from Ryan Levine with Citi.

What's driving the large increase in your load growth electric CapEx for '18 through 2021?

So to make sure I understand the question, what's driving the investment need over this period?

Yes, 7 of your presentation increased from 3.02 to 4.19 and beyond.

You're talking about the growth in CapEx during the middle part of the plan?

Yes.

Okay. That is being impacted heavily by the single project I referred to as the Bailey to Jones Creek project; it is incorporated that $250 million is a discrete project that's incorporated centrally right in the middle of that plan with the majority of the spend occurring in 2020.

But there is a big increase between '18 and '17; so is any of that in '18 number?

Yes, part of that is '18 but we've also -- as we rework our plans for growth and investment needed for growth, we've just updated the amount of spend that we associate with or related to load growth and that's what's being categorized here as a recognition that the spend would go up from the $300 million range to $400 million for load related investments as a result of the planning exercise we do each year.

And then how does tax reform impact basis that you have in Enable?

I think you're aware we have a negative basis in Enable. Our tax reform does not impact our basis. Tax reform does impact the capital gains rate that we pay if we were to sell any of our investment in Enable.

Our next question is from Greg Gordon with Evercore ISI.

If I missed this -- the 5% to 7% EPS growth target in '19 and '20; could you tell us what are you assuming for Enable in that growth? Is it flat? Is it high growth or it is growing or is it actually deteriorating?

We have not specified what our assumption is there, we take into consideration a range of options and incorporating that with the capabilities and the options for the rest of the portfolio, we're comfortable that 5% to 7% growth off of prior year is a very doable target.

The $8 billion roughly CapEx -- the total CapEx through 2022; high level what percentage of that CapEx is actually covered through like existing mechanisms, so you don't actually have to go in for like a major rate case filings?

So I'll give you the answer in pieces. So on the electric business, it's approximately 95% that can be achieved through -- recovery achieved through mechanisms. On the gas side, it's virtually all of it with the exception of Minnesota which does not have these mechanisms but has a forward-looking test year and also utilizes interim rates; so those two features in Minnesota mitigate regulatory lag.

The actual cash tax rate Bill, how does that look like through the forecast period versus the effective tax rate; so what actual cash backs that you'll be paying?

Our cash tax rate should approximate or be below our provision rate of 21%.

Our next question is from Christopher [ph] with JP Morgan.

Most of my questions have been answered. I just wanted to get a sense, if you guys could classify your revision of your deferred tax liability; you already gave us I think the 1.2 for the utility piece but what's the total amount that was classified and what are the ramifications on your subsidiary catalyst structures?

The total amount of access deferred income taxes was $2.4 billion. $1.1 billion of that was associated with income from non-utility regulated investments; and so that went through the income statement and strengthened the balance sheet in 2017. $1.3 billion of that $2.4 billion was recorded as a regulatory liability which will be amortized over different lyse [ph] depending upon the assets associated with those liabilities and depending upon the jurisdiction. And your second question was on the balance sheet?

Yes, the ramifications for that at the subsidiary level balance sheets.

Got it. so the $1.1 billion recognition that went through the income statement stripped for strength in the consolidated balance sheet from 35% to 40% equity at the cap after adjusting out securitization bonds. And some of that benefit flowed through the balance sheet for Houston Electric and for CERC where those balance sheets are close to 45% at year end and at 50% at year-end 2017. Now to get those balance sheets at that level because they had more equity content as a result of tax reform, there were dividends from both of those entities to CenterPoint and the holding company.

Our next question is from Michael Lapides with Goldman Sachs.

I want to come back to regulatory lag and I ask this seeing in the K that O&M at the Houston Electric was actually up a good bit year-over-year. On a net income basis, let's not worry about the financing and share count but on a net income basis, how much regulatory lag do you think you have electric versus the gas LBC business? I mean, do you think you can unauthorized -- do you think there is just some natural lag on O&M that you can't recover so you earned something below; if so, how material -- how do you think about that or what do you assume kind of in your multi-year outlook?

Let's begin by assuming that O&M growth stays with volume of sales growth on the residential side; so that way we have an offset if you will to that element of regulatory lag. But the real regulatory lag is how quickly our mechanisms allow capital expenditures to go into rate base and earn a return. The T-cost mechanism allows for filings twice a year and is relatively quick when that gets into the revenue requirement and so that regulatory lag can be as short as six months. The DCRF mechanism is filed once a year, that's in April and that's off of books that close at year end. And our experience in the last filings is; that then gets reflected at revenue requirement towards the end of the third quarter. So if you assume that we had an average spend and distribution investments in the prior year you get a regulatory lag of as short as 9 months but it could be upto a year.

A tax follow-up, very simple one. Do you assume you're a full cash tax payer at all during the next four or five years; like when I think about the backend of the forecast, are you still not a full cash tax payer out there?

We don't expect to be a full cash tax payer.

Finally, just a regulatory question; what's the process for the proceeding that's coming up in Texas regarding the commissioner's memo and the rate review for CenterPoint at Houston?

We have agreed recently to file a rate case before April 30, 2019. So sometime before then we will -- we're obligated to make our next full rate case filing.

Using a historical test here would kind of six months of known and measurables type of deal?

It's a full historical test year and we've not specified exactly that what that test year would be but it obviously has to be sometime between now and when we have to file.

Our next question is from Angie [ph] with Macquarie.

So given the tax flow changes and the lower tax spend sale of your stake in April would entail; would you potentially reconsider strategic options for that business? I mean, I understand that the tax leakage was a big adverse effect of potential sales downs of the assets in the previous review but now with the tax law changed, does it change your perspective?

No, we are not -- it does not change our perspective on it. You are right, it gets better but it's still very challenging to do and accomplish our financial objective. So it doesn't change our intent in terms of how we plan to reduce our exposure there.

And separately on potentially incremental transmission CapEx; we're seeing finally some inflection point in forward power prices and are cut north and probably more so than Houston. Is there -- I mean, have you identified any potential additional transmission projects that could be necessary given the recent wave of requirements?

We have not but our operators continue to study this and depending on how the system is performing and what the needs are with respect to capacity to move power as demanded by the system it could give rise to additional investments, we look at this annually, we adjust our plan annually based on how the system is operating and what the most recent projections are. But as of now we've included everything that we have insight to.

Our next question comes from [indiscernible].

What is the portion of Enable earnings within 2018 guidance?

If you were to take the midpoint of Enable's net income guidance that they've put out last year, and then translate that into CenterPoint EPS, you would get $0.46 per CenterPoint share. And the way to do that is to take the midpoint of their guidance, the effective tax rate, state and federal associated with our Enable investment as 24%; we own 54% of Enable. And then after you've done that, add $0.07 per share for the accretion.

And then just to clarify; there is no Enable sales contemplated in 2018 but in the three-year CAGR timeframe is there Enable unit sales contemplated in that?

What we've said is that our 2018 plans doesn't call for the sale of Enable units in order to support our capital investment. We've also said that this multi-year view that we've given you contemplates a range of scenarios to include a range of financing alternatives.

Our last question is from [indiscernible].

Bill, CSE [ph] has $900 million credit facility on which $899 million was used through February or at February 9. Is that an indication CSE is doing a lot of business or is there something else and would you be looking to increase the facility going forward?

Well, just speaking to the specific credit facility for CES?

I'm just looking to the 10-K and said that CES had a $900 million credit facility outstanding on which $899 million was used as of February 9.

That is the credit facility for CERC; and CERC includes CES as well as all of our natural gas distribution utilities. And those companies along with other companies share a common money pool.

So what's driving that -- I mean, it's pretty close targeting $1 million cushion less there, I mean that's kind of tight. So what's the [indiscernible]?

As shared on our call, we had a run-up in gas prices right at year end; and in our disclosure you'll see that we went from receiving a marginal collateral at year end 2016 to posting margin collateral at year end 2017. So that's just -- that's the price impact. And then we had to purchase gas at higher prices, put it into storage which we then provided to our customers; so that was -- I characterize it as a temporary swing and we're beginning to see that cash flow come in as our customers pay their bills.

So my conscience says not something that's critical or with new potential?

No, sir.

With no additional questions, thank you everyone for your interest in CenterPoint Energy. We will now conclude our fourth quarter 2017 earnings call. Have a great day.

This concludes CenterPoint Energy's fourth quarter and full year 2017 earnings conference call. Thank you for your participation.