Entergy Corporation (ETR) Q3 2013 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Entergy Corporation Third Quarter 2013 Earnings Release Conference Call. Today's call is being recorded. At this time, for introductions and opening remarks, I would like to turn the conference over to Vice President of Investor Relations, Ms. Paula Waters. Please go ahead.

Good morning, and thank you for joining us. We'll begin today with comments from Entergy's Chairman and CEO, Leo Denault; and then Drew Marsh, our CFO, will review results. [Operator Instructions] As part of today's conference call, Entergy Corporation makes certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these factors is included in the company's SEC filings. With respect to the planned spin-merge transaction, ITC filed a registration statement with the SEC, registering the offer and sale of the shares of ITC common stock to be issued to Entergy's shareholders in connection with the proposed transaction, and the registration statement was declared effective by the SEC on February 25, 2013. ITC is expected to file a post-effective amendment to the registration statement. In addition, on July 24, 2013, our subsidiary, Mid South TransCo LLC, filed a registration statement with the SEC, registering the offer and sell of TransCo common units to be issued to Entergy's shareholders in connection with the proposed transaction. This registration statement includes a prospectus of TransCo related to the proposed transaction. Entergy also will file a tender offer statement on Schedule TO with the SEC related to a planned exchange of shares of Entergy common stock for the TransCo common units. Entergy's shareholders are urged to read the registration statements, prospectuses and other documents referenced above, when they are available, and any other relevant documents because they contain important information about ITC, TransCo and the proposed transactions. These documents and other documents related to the proposed transactions, when they are available, can be obtained free of charge from the SEC's website at www.sec.gov. The documents, when available, can also be obtained free of charge from Entergy, upon written request. Now, I'll turn the call over to Leo.

Thanks, Paula, and good morning, everyone. I've been talking a lot lately about simplification. In my remarks, I will review major events of the past 3 months and how they relate to that objective. As I know many of you are well aware, especially given the number of other earnings calls scheduled this week, the annual Edison Electric Institute Financial Conference is just around the corner. As such, we will focus the call today on updating you on the developments in the past 3 months and defer more strategic updates to the conference. Starting with the proposed transaction to spinoff and merge the transmission business with ITC Holdings. In September, Entergy Texas and ITC refiled our application for transaction approval before the Public Utility Commission of Texas, acting on the opportunity the commissioners gave us in the August 9 open reading. The refiled application put in the record the enhanced rate mitigation plan that includes a benefits test and mitigation of 100% of the effects of the weighted average cost of capital for retail customers, as well as other testimony quantifying the benefits to customers. The Texas Commissioners agreed to hear the matter directly next month, and briefing will end in December. In Mississippi, briefing concluded at the end of September, and an order is now pending from the Commission. In Louisiana, a revised procedural schedule was set to conclude briefing on November 8. In Arkansas and New Orleans, we are working with the parties to come up with a new schedule. Efforts were temporarily suspended during the quarter until the refiling in Texas was made. And in Missouri, an order is pending. These schedules, once set in each of the jurisdictions, will provide more insight about the potential timeline for the transaction. The revised closing date in 2014 has…

Thank you, Leo, and good morning, everyone. In my remarks today, I will cover financial results for the quarter, 2014 earnings guidance and other forward-looking financial updates, starting with the quarterly financial results. Slide 2 summarizes third quarter 2013 results on an as-reported and on operational basis. Operational earnings per share were $2.41 versus $1.95 a year ago. Third quarter as-reported earnings in both periods included special items for expenses associated with the decision to close Vermont Yankee and implementation of the human capital management imperative in 2013, as well as the spin-merge of the transmission business with ITC in both 2012 and 2013. The decision to close Vermont Yankee in third quarter 2013 resulted in a noncash impairment of the carrying values of VY and related assets to the fair value of $62 million, as well as other related charges, including the effect of capital spending not chargeable to expense because of the plant's shortened life. Going forward, we'll continue to classify VY's capital spending as operating expense and it will be reported as part of the asset impairment and related charges line item. And we will include this expense, as well as any VY severance and retention expenses as special items this year and next. Slide 3 summarizes operational earnings per share by business segment, including major drivers of period-over-period variances. Third quarter operational earnings per share were higher than the same quarter last year. Results at Utility and Parent & Other increased, while EWC results declined. Utility operational earnings were $2.04 per share, which is higher than $1.72 earned in the third quarter of last year. The overall increase was driven by higher net revenue and a lower effective income tax rate, partially offset by higher nonfuel O&M and higher depreciation expense. Utility net revenue increased due…

[Operator Instructions] Will go first to Greg Gordon with ISI Group.

My first question is on the expense outlook. So I know the guidance midpoint of $5 is unchanged from -- but the components have changed significantly. And specifically, the guidance midpoint at the beginning of the year for Parent & Other was $0.50. It's been rebased to $0.85 in the context of the current $5 guidance, and rises to $1.05 next year. Can you take us through the progression from $0.50 to $0.85 to $1.05? And then I have a follow-up.

I'll let Drew handle that, Greg.

Well, as you know, the Parent & Other is primarily comprised of interest expense and taxes. And of course, there's the affiliate preferred expenses in there as well. So that's certainly contributing as that's grown. The primary thing to think about is the tax piece of it. And particularly, as we move into 2014, we have historically used a weighted average sort of probability expectation of what our income tax is. And we place that in the Parent at the a beginning of the year, given the certainty of where it may ultimately shake out. This year, we have a better expectation of where it would probably land in that set Utility, so we've highlighted some of those Utility income tax benefits that I discussed a minute ago. That's the primary driver that you see kind of moving forward.

Okay, great. And my follow-up question is on the CapEx guidance. It looks to me, based on where your 2014 rate base is sort of going to end up, based on looking at your rate case filing, et cetera, that the level of CapEx spending, minus level of depreciation you played out in your slides, that the rate base growth profile looks like it's more or less the same rate, i.e., around 6%, that had it had been in the past. So assuming consistent rate treatment, wouldn't it be fair to assume that your earnings growth aspiration would be consistent with that through '16?

You're jumping ahead of us a little bit on that, Greg, in terms of providing any kind of forward-looking outlook. We will discuss a little bit of that when we get to EEI in terms of what the opportunities are going forward and where we see the Utility. But, right now, we're not really prepared to go out beyond 2014.

I'm sorry. But arithmetically the -- but arithmetically, it looks like rate CapEx minus depreciation, you're growing at about a 6% rate from '14 to '16, based on what you outlined, is that fair?

There are other components of rate base. But the pieces you're looking at have -- but there's deferred taxes and other things that go into that calculation as well. And I'm not trying to argue the math with you. I apologize, I'm just not prepared to go beyond 2014 right now. Sorry about that, Greg. I appreciate the question, though.

And we will now go to Paul Patterson with Glenrock Associates.

Just wanted to touch base on the depreciation study. It sounded like quite a significant move in expected depreciation because of it. And I was wondering if you could just elaborate a little bit more as to what went into that?

Yes. Drew?

So we use the group method of depreciation, which means that from time to time, we have to do an updated depreciation study to sort of reflect consistency with our actual experience. And we alluded to it very briefly on our last call, but didn't really give it a full discussion. Ultimately, the effect is to take away large increases that we would expect to see towards the end of life for the nuclear assets and sort of make the depreciation more ratable, like you would expect under normal situations when you kind of go forward. As you think about depreciation, it's a zero-sum game. By the time you get to the end of life on an asset, you're going to have to depreciate all of it. And so we're -- it's a little more ratable now with the new depreciation study. It doesn't affect the cash flow at EWC.

Okay. So it would suggest that the detriment in value that we'd be seeing later years is now being brought forward. And so, I guess, near term, the EPS would be more conservative in terms of the value of those plans, is that the way to think of it?

Yes, on an EPS basis, yes. Not on EBITDA basis. I think it would be about the same that we were seeing before.

Okay. Then moving to Slide 18, on EBITDA basis, you guys show it, an increase now in 2014 versus 2013 versus last quarter. And I was wondering, you mentioned a few things on the slide, one of which has to do with Vermont Yankee. And I'm wondering whether or not the fuel expense is being reflected in EBITDA since the expense of, I believe, is being amortized. That's number one. And then number two, what's leading to those changes? I mean, I realize that there's a change in prices that would be benefit, I guess. If you could just elaborate, sort of just give us a little bit more quantification or sensitivity to that.

I'll answer the first one, and then I'll turn the second none over to Bill. Fuel amortization is in the EBITDA number for Vermont Yankee.

So that's being reflected in Slide 18, the expense of fuel, the noncash expense of fuel?

Yes. One thing to think about there is fuel is -- it's part of the write-down. You write-down all of the assets at Vermont Yankee, not just the actual plant itself. So that includes part of the fuel, so you see the fuel going down as well there.

Okay, so that's benefiting EBITDA?

Yes.

As it relates to the revenue side of things, from a capacity perspective, Drew mentioned the fact that we included Lower Hudson Valley in our projections for 2014, basically assuming a $3/kW-month increase over rest of state prices. So that's included in our numbers here.

Would that change from last quarter?

Yes. I think, last quarter -- we've typically been talking in a range of what we've expected. And I think, even in the last call, there was a little bit of confusion in terms of what was actually included, but in terms of how much was included over rest of state. So this is much more specific that we're including the $3 per kW-month on an annualized basis for Lower Hudson Valley.

And I'll just add, Paul, that we have historically used market views, and there wasn't a market view of Lower Hudson Valley, so we didn't have it. What we had was effectively a rest-of-state view in our last call. So this time, we are explicitly pointing out that we're putting a point of view in place for Lower Hudson Valley, since there's no specific price target out there. And we'll go back to a market view once that develops.

[Operator Instructions] We will now go to Jonathan Arnold with Deutsche Bank.

One question on VY, when you made the announcement about the shutdown, you said it was expected to be sort of a negligible contribution to 2013 at the bottom line. So firstly, I guess, is that still the case? And then, you give us an EBITDA number for '14, but with all these other moving parts, can you kind of comment on how much is the actual depreciation associated with VY in '14? And what would your, sort of, net-income-type expectation be embedded in these numbers in '14?

I'll let Drew answer it. Obviously, when you say negligible in 2013, certainly, the -- on an operational basis, it's negligible. And on an as-reported basis, I wouldn't necessarily call the parent negligible. But...

I think you -- okay, fair enough. You said around breakeven operationally.

Operationally. Operationally.

That's right. And I think that's still the case. I think it's a little better, as we've pointed out, because of, like, the fuel write-down. And we're seeing a little bit of that in '14. In '14, there's a little more EBITDA pickup because of the fact that we're not actually having a refueling outage in that particular year. And so, that's what's your -- that's part of the driver for the improvement in EBITDA in '14, which we wouldn't have other normal -- otherwise seen under normal operating conditions.

Okay. And you attributed $0.04 of the $0.25 depreciation delta to VY. But can you give us the -- what is the number that refers to the delta?

I don't have the exact depreciation for total VY in front of me, but we can follow up with that offline.

Okay. And then just on one other topic, if I may. You have -- in the nonfuel O&M outlook slide, the reading that's rightly -- the 0.5% to 2.5%, should be looked at net of the VY cost. Firstly, is that correct?

Yes. What we're trying to point out is you could take the $145 million of direct cost out of sort of our base year of 2013, and you could still apply the 0.5% to 2.5% compound annual growth rate to that. And that would be sort of our revised view of where we might get to in 2016.

Okay. So if that holds, though, looking at the slide, you have the step down in the underlying costs, and then -- yet the CAGR is still up to 2.5% in '16. I mean, when you do the math on sort of what looks like a somewhat quantifiable step down in '14, to get to 2.5% growth CAGR sort of 3 years compound by '16, you'd had to have some pretty much higher percentages than that. What kinds of things could drive you to the high end of that range, I guess, is my question? Or am I missing something on the map?

Yes. I think the big things are, like, pension expenses could be a big driver, if we were to acquire to more assets within the Utility, for example, that certainly adds more O&M expenses. Those are the kinds of things that could drive it up, if there are additional regulatory costs, that's something that certainly grown outside of typical inflation growth rates over the last few years. Those are the kinds of things that could push it up. Given our current expectation, 2.5% is probably on the -- it is on the high side, obviously. And I don't think under normal operating conditions, we'd expect to get all the way back to 2.5%. But those are the kinds of things that we're trying to account for, given the uncertainty associated with where the portfolio may go or where pension expenses may go, that kind of thing.

So it includes potential portfolio additions, that presumably would up revenues associated with them at the high end?

Yes, 2.5% is accounting for the possibility of that. That's not to say that, that's what we are going out to do right now. It's just within the range.

But in order for it to be that high, would it require that relative -- I'm just not sure how significantly to take that as part of this answer.

I mean, you were asking what could drive it up there, that's what we were thinking about when we put a number out there like that.

Okay. And if I -- can you just share your with us sort of what you're trying to achieve, what's your budget, if not much else changed?

Outside of the 0.5% to 2.5% growth area? I mean, I think that's where we are generally targeting. I mean that's what our -- we were trying to achieve the low end to that range, an idea where we might even beat it. But that is -- that's where we were comfortable putting out our guidance on '14 to '16 CAGR.

And we will now go to Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Leo, just catching on kind of your ends of the EWC comments, you seem like you've made note of the idea of maybe trying to find some sort of settlement or resolution on any endpoint, given the time horizons and license extension, that sort of stuff. Can maybe share some color on kind of what the tone or interest is on that and whether that's something you can realistically get done in sort of timely fashion?

Really, Dan, all I'm trying to say is nothing different than what we've said before. We really view Indian Point as a high quality asset, very vital to the region. And certainly provides the majority of the benefits that you would like to see in a power market in the economic environment. It provides jobs. It provides tax base. It provides reliability to the grid. It provides low-cost clean energy. It provides all the things, from a public policy standpoint that you would want. And certainly, we recognize that there are some folks who would like it to not operate to the end of its license life, and that's certainly not the opinion that we have. We think it's vital not only today, but it will continue to be a vital part of that market for years to come. We're just acknowledging that we know other people have a different point of view. And if there's something there that could result in common ground, where we can come up with, as we've talked about before, the certainty equivalent of value and glide path for the market, we'd be willing to do it. But there's no more emphasis on it than that. It's just something we're willing to explore. Dan Eggers - Crédit Suisse AG, Research Division: Okay, got it. And then on the ITC process with, I guess, the commissioner coming out on Friday and saying that voter decision couldn't presumably happen until January, given their scheduling and how that corresponds to a year-end merger agreement date. Would you guys need to formally extend the merger agreement to keep the deal going beyond December? Can you guys kind of function in an at-will basis pending more regulatory action?

Technically, the merger agreement allows either of us to terminate the transaction after December 31. How we'll handle going beyond December 31 will be dependent on seeing the rest of the procedural schedule, and seeing what comes out of Arkansas and New Orleans, for example. And then, obviously, something that ITC and us will have to consider. But we're not prepared to go there at the moment. Dan Eggers - Crédit Suisse AG, Research Division: But just -- from just a technical perspective, would you guys need to sign a new agreement be to go beyond year-end 2013? Or could you guys function without an explicit time extension involved?

Technically speaking, we would not have to amend the agreement.

And we will go to Julien Dumoulin-Smith with UBS.

First, just with regards to the $5.20 at the regulated [indiscernible] next year, how do you think about that within the context of your earned ROEs overall? I appreciate that you have pending rate cases, et cetera. But generally speaking, would you say that you're earning your ROE in that $5.20? I suppose that was contemplated in your initial 6% growth CAGR, I suppose.

I'll let Theo talk about what, on each of the utilities, to the extent that he can.

Julien, it's Theo. Actually, I think, the last comment you made probably speaks to the best way to describe and respond to your question. I can't talk specifically on -- respond specifically to kind of what the assumption was. But obviously, the growth assumption in 2014 is consistent with, obviously, all of our other planning assumptions. And as you look at 2014 and you see that our growth assumption hits the 6%, you would expect that you're planning assumptions are aligned, then that would produce something that would be relatively within the range of what we would expect to achieve from earned-ROE perspective, as it relates to our allowed ROEs. With that said, the 2014 rate case is obviously -- don't go full -- don't go in effect at the beginning of the year in their entirety, some go in effect later in the year. And also, there is some small element of regulatory lag. Obviously, since you file the cases, from the time you file to the time rate's go into effect. But, obviously, when you see the 6% growth aspiration in 2014, achieving that, you would think -- you would also -- I think, we'd also say that, that moves us closer to our goal, obviously, which is to earn our allowed ROEs within the context of Utility.

Great. And then with regards to the latest update guidance. I suppose, in the preliminary release just that it was towards the midpoint now. Could you talk of what changes occurred in the quarter that led to that decision? Specifically, I suppose, the district sale appears to be reflected in your adjusted EBITDA in '13. Just perhaps, the various walk, if you will, to get to that, I suppose, revised range within the '13 range.

We didn't change the range, Julien, you're just talking about the fact that we said we should be around the midpoint.

Yes.

Okay. Drew, I don't know...

Yes. I don't think -- I think our suggestion before was that we weren't -- I think at the beginning of the year, we were suggesting that we were at the lower end of the range. And I think maybe the -- after the first quarter or the second quarter, we said that we were no longer in the lower end of the range. And for now, we're just saying we're in the middle. So I don't think, from our perspective, we've really moved a whole lot. And so, you're right, the district energy sale is reflected in there, it's about $0.15, and so that's part of the overall piece. But as you may recall from the beginning of the year, on January 1, we had about a $0.20 deficit on the pensions that we had to overcome because interest rates fell so far towards the end of last year. And so, I think that if you look across the businesses, I think there's good -- there's gives and takes at EWC, for example, with higher pricing in the first half of the year on energy, higher capacity pricing through the middle of the year, but some reductions from a volume perspective. And at the utility, I think there has been a little bit of negative weather, and that's offset a little bit lower growth -- well, I shouldn't say it's offset, it's a little -- there was a little bit lower growth than maybe we expected at the beginning of the year. That's been offset by some tax benefits and some other things. So I think, actually -- and I'll probably mention that, too, on the tax side, we guided you at the beginning of the year to about a 34% effective tax rate. And while we expect to do a little bit better than that by the end of the year, we expect it will to still be around that 34% effective tax rate range.

And we will take our last question from Steven Fleishman with Wolfe Research.

Just to -- I wanted to think a little bit about kind of the Utility net of parent drag. When you look at the guidance for '14, I guess you have a $5.20 Utility, $1.05 of parent drag, that's about $4.15 net. Is that a good clean base to think of kind of a future growth for the core Utility business?

Drew, you want to ...?

You're asking about the Utility preferred elements of that, Steve?

Not necessarily, specifically. let me ask the question this way. So your 2013 initial guidance had $4.70 for the Utility, $0.50 of parent drag, so a net of $4.20. So even though the Utility has gone up a lot, it's been all kind of absorbed by, in the '14 guidance, a much bigger parent drag. So I just want to kind of think about on a moving forward basis, is this kind of a clean year for Utility net of parent from which to really think about growing the company?

Yes. I mean, I think -- let me answer it this way. I mean, beyond 2014, we should have a pretty good view of our rate cases, as Leo mentioned earlier, and so that part will come into play. The HCM program should be in full swing, and we're going to try and get a better view of what we can do maybe even beyond HCM going forward, we're beginning to work on that. And a big piece of what the storyline is going to be beyond 2014 is going to be the possibilities with industrial growth at the Utility. And whether or not our historical load growth can actually begin to move at a higher rate than what we've seen, thanks to sort of the industrial renaissance. And I think we're going to talk a little bit more about that at EEI when we get there.

That concludes today's question-and-answer session. Ms. Waters, at this time, I will turn the conference back to you for any additional or closing remarks.

Thank you, Angela, and thanks to all for participating this morning. Before we close, we remind you to refer to our release and website for Safe Harbor and Regulation G compliance statements. Our call was recorded and can be accessed on our website or by dialing (719) 457-0820, replay code 8044514. The recording will be available as soon as practical after the transcript is filed with the U.S. Securities and Exchange Commission due to filing requirements associated with the proposed spin-merge transaction with ITC. The telephone replay will be available through November 5, 2013. This concludes our call. Thank you.

Ladies and gentlemen, this concludes today's conference. We thank you for your participation.