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

Good morning, and thank you for joining us. We'll begin today with comments from Entergy's Chairman and CEO, Leo Denault; and Andrew 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. Now I'll turn the call over to Leo.

Thanks, Paula, and good morning, everyone. 2013 was a good year, considering everything we set out to do and what was before us. Importantly, we maintained low rates for our customers, our employees had a great safety year, we contributed to our communities, and we put in place a platform of lower costs, improved risk profile and simplification our business while delivering strong financial results. Moreover, our strategic imperatives positioned us to execute on our strategy to aggressively grow our utility business, driven primarily by the economic renaissance that is unique to the Gulf South while we preserve the optionality and manage the risk in our merchant operations, Entergy Wholesale Commodities. So starting with the results. I'm pleased to report, after beginning the year with higher-than-expected pension costs pushing us towards the lower part of our guidance range, we delivered operational earnings of $5.36 per share. That's near the top of our guidance range of $5.40. We returned nearly $600 million in common stock dividends and maintained solid credit metrics for our owners. Our residential, commercial and industrial rates remain among the lowest in the nation. Our residential rates are in the lowest cost quartile in 4 of our 6 retail jurisdictions, and our low industrial rates are contributing to the regional industrial growth we're experiencing. In addition, our residential customers viewed us more favorably in 2013 than the year before. Overall, the percent reporting favorable views grew by 12 points to 78%. Also for our communities, Entergy and the Entergy Charitable Foundation invested more than $15 million of cash contributions to nonprofit partners, and our employees and volunteers logged more than 85,000 hours of volunteer service valued at approximately $2 million. What matters most to us is safety. Our employees reduced the OSHA recordable accident index by more than…

Thank you, Leo, and good morning, everyone. Today, I will review the financial results for the quarter, highlights from the full year, then I'll spend some time discussing our forward outlook. Starting with Slide 2, our fourth quarter 2013 results are shown on an as-reported net operational basis. Fourth quarter operational earnings per share were $1 in 2013 compared to $1.72 in 2012. The decline was largely due to the income tax benefits recorded in the prior period. There were other largely offsetting items, which I'll discuss momentarily. Operational earnings excluded special items from the ITC transaction, the Vermont Yankee closure decision and HCM implementation. Regarding HCM, the net charge was $60 million on a pretax basis. This included about $110 million from pretax expenses, net of approximately $50 million from regulatory assets. Turning to operational results by segment on Slide 3. Earnings per share at the Utility and Parent & Other decreased, while EWC results were higher. Starting with Utility, operational earnings per share were $0.86. This was lower than the $1.63 earned in fourth quarter of 2012. As expected, income tax expense was a driver, due to the prior period benefit. Recall, in fourth quarter 2012, income tax expense was reduced approximately $155 million as a result of an IRS settlement. Partially offsetting in 2013 result was an approximately $0.08 per share of income tax benefit, including the reversal of previously accrued interest after resolving an IRS audit. Utility also saw strong results in net revenue. We talked about pricing factors throughout the year. The benefits from conducted 2012 investments were realized in 2013 results. Utility retail sales were also higher this quarter, on both an as-reported and a weather-adjusted basis. Weather-adjusted sales increased 1.5% quarter-over-quarter driven by strong industrial growth, which is 3.2% higher than the fourth…

[Operator Instructions] We'll take our first question from Julien Dumoulin-Smith with UBS.

So first, just going back to the rate case strategy, you've talked about -- a lot about load growth here. You've also alluded to O&M inflation. Could you perhaps just talk Arkansas, Mississippi, just rate case filings expectations over the next couple of years and the ability to hit the 5% to 7%? What are you thinking right now in terms of going back in, rehearings, et cetera? If you could kind of delineate that.

Theo, you...

I'll start. This is Theo. I'll start with Arkansas. I mean, obviously, we've made a filing for our petition for rehearing, and we'll see how that goes. And that will obviously inform us in terms of what we do going forward. In Mississippi, we're still evaluating whether we need to file a rate case. But the -- we do know that 2013 test year for our fee filing is suspended. And if we do file a case, it'll be to prepare Entergy Mississippi for a post-System Agreement timing and also to move some of our power management riders that we recover certain costs around -- capacity costs around plants today into base rates. We also had a depreciation rate filing that we did or studied. I believe that was done in 2011. That could be operated in a rate case in Mississippi. But I think also, it will allow us the opportunity to explore some alternatives to unknown and measurable changes that could occur during a rate effective period, as Leo talked about in his opening comments. As you go forward, obviously, whether we file additional rate cases will be impacted by a couple of things you mentioned: where we see ourselves in terms of sales growth; the bearish regulatory mechanisms we have in play within some of these jurisdictions that might allow us to change the dollars we're recovering without necessarily filing a base rate case, for instance in Texas, where have rider opportunities. We have rider opportunities in other jurisdictions as well, Louisiana and the case I just mentioned, Mississippi. In certain cases, you can get recovery through riders, primarily around capacity, without filing base rate cases. As to where we go past the case that I just discussed, that'll have a lot to do with the cost structure, with sales growth, with the investment opportunities that we have overall and the mechanisms that are in play that will allow us to recover that without necessarily having to make a base rate case filing.

Great. And I suppose just following up on the ITC deal a little bit here, just thinking about ability to reinvest in the system, specifically on transmission. I'd be curious, is there an ability to ramp up spending there? Is this more about a wait-and-see in terms of what MISO opportunities might be forthcoming? Can you perhaps give us a little bit more context for what that opportunity might be, if it exists?

Julien, the -- where our transmission is today, we do have in -- as we said, over the next 3 years, $1.7 billion in our plan for transmission expenditures. As I mentioned in my comments, there are several things out there that could increase that if there are projects that are beneficial to customers that reduce congestion, that improve reliability, that provide access to generation within the MISO equipment, et cetera, or they -- any PMBP projects that would be out there, part of the Order 1000. So there are things out there just in the system as it stands. The other aspect is, as we start to get more line of sight on this economic development front, certainly if 2,400 megawatts show up or more, that's just what's been announced to date, and there's nothing in the commodity strips that would lead you to believe that, that renaissance is over, that's going to provide a situation where there might be more transmission investment as well if you start adding -- like the Sasol example that Drew gave us, 200 megawatts in one facility. Those sorts of things are going to have an impact. So there is the opportunity for that transmission investment to be larger if there are things that we can do to benefit customers or to hook up new customers. And it would appear that the market is ripe to have some of that happen, but it's a little early to tell right now.

We'll take our next question from Kit Konolige with BGC.

Just a couple of somewhat unrelated questions. On the impacts that have been -- increased the expectations for 2014 EPS to the top end of the range, I think you mentioned pension was a $0.09 positive, and the -- and then the -- it appeared that a significant driver was higher expected prices at the nuclear fleet, the EWC nuclear fleet. Did you quantify that? Or did I miss that?

Well, I think, Kit, if you look at the slide that shows the EBITDA for EWC, you could see where most of that is, particularly if you compare to kind of the last update we gave last quarter with the same slide. And so it's up considerably. And eyeballing it, $150 million, $175 million.

$150 million, $175 million. And this is due to just higher prices as a result of higher gas prices and cold weather and generally the '14 commodity prices being very robust recently?

Yes, and part of it is what we've seen very recently. There's still a good bit of it that is still to come. This is a mark of current expectations using forward prices as of December 31st. And so this includes -- at that point, it included the entire year of forward prices. So we -- obviously, we experienced some of that in January. Some of that has been realized early this month. But then, we have the full year still ahead of us.

Right. And then, to switch to your discussion of strategic outlook for the nuclear plants in EWC, it sounds as though there's a little bit of a change in tone, whereas previously, I think, for example, at EAI, you had said that if you own ETR, you should expect to own Indian Point. Now if you -- sounds like if you own ETR, you should expect to own all the currently held nuclear plants, with the exception of Vermont Yankee, obviously. What's been the change there? Was that the capacity pricing in New England that really made the difference? Or am I seeing a change where there really hasn't been one?

No, I think you're seeing a change, Kit. You could – [indiscernible] anything to do with the near-term pricing. It's really a function of -- we've been telling you for a while that we are exploring opportunities, and in the exploration of those opportunities, we didn't find anything that we liked, and we like owning them better. And so that's where we are at this point. Then we still own Vermont Yankee also. I mean, we'll continue to open it, even when it's being decommissioned. So there is a change. We still believe that the separation of the risks would make sense, but we also believe in creating value. And if we can't do it without the right amount of value, then we're going to continue to hold those ransom [ph]. As you say, our strategy is to preserve optionality in those plants, and we do that operating and through our hedging strategy and through the licensing process, I mean, obviously, to manage the risk as best we can. So you did pick up on a change.

We'll take our next question from Stephen Byrd with Morgan Stanley.

I wanted to follow up on Julien's question on transmission. And Leo, you talked about a couple of categories of potential spend over time. Could you talk a little bit to the process at MISO and just what we should be looking for or thinking about in terms of, for example, as customers start to show up as MISO continues its planning, how we should expect to start to see some of the these plans sort of come forward in terms of further spending on transmission?

Well, the majority of it is going to be -- is what's in our base plan. And then the next layers of it will be what comes about through just normal business. It's just such that our normal business includes some significant potential load, as it were. It's if they're industrial customers as opposed to the residential customers and industrial customers of size. So a lot of that, while it's in MISO and there's a planning process when it becomes part of the plan, it's not -- in the realm of outcome, I don't think it's significantly different than what we have in general and have traditionally had. We just might have an opportunity bigger than the $1.7 billion. And then, as it relates to the process, once we start to move in over the next few years with the Multi-Value Projects, NEP projects, the more FERC Order 1000 things, then we'll have to compete in that arena, and we would expect so to do so and to be successful.

Okay, great. And I wanted to shift gears over to Indian Point. You had, on Slide 28, given an update on the status. I wondered, on the Coastal Zone Management paths, if you could just speak to next steps we should be looking for. You gave an update on sort of all 3 elements of the coastal zone process, but I wondered if you could just give us a sense for what -- next steps on those different paths.

Yes. Stephen, a couple of things here. So first is the consistency filing itself, well, has been extended to the end of 2014. That's simply due to the need for the parties to work together, share more information, further vet issues. So we really -- so that was previously set for March and was moved back to the end of the year. As it relates to our other option on grandfathering, I think you're well aware of the fact we lost the initial decision on that. We are in the process of appealing that decision to the state courts. And we may have further appeals depending on the outcome of that case. That will probably take us through the end of 2014 as well. And then, of course, we have the previous review argument, which is kind of held in the background as another option that the NRC has not yet ruled on and is also being considered by the state of New York. So we think, through all these various processes, that this will go on for a period of time. And eventually, we plan to be successful with it, but obviously, a lot of uncertainty now with the various cases that are ongoing.

Our next question comes from Steven Fleishman with Wolfe Research.

A couple of questions. On the EWC outlook, it looked like '15, '16 was a little lower if I -- kind of my ruler was correct, than at EAI. Is that just updating this New York capacity assumption?

That's certainly in there, Steven. Yes, it's -- yes, I don't know that we're as precise with rulers, but yes, it's -- that's baked in there. That's part of it.

Okay. So it's -- I mean, it's about flattish, I guess, overall. So it's not that [indiscernible].

Yes, I mean, I would -- that's the way I would describe it. I mean, we haven't seen the energy markets really move upward in any material fashion since then, a little bit in '15. But the capacity prices has clearly, like we've said, been offsetting.

Okay, because the '15, '16 kind of switched a little bit. '16 looks like it's stepping down a little bit. I assume that's the capacity, and the energy has moved, okay. And on your utility sales growth and the -- all this new industrial load and potential, can -- I know you've probably answered this, but just how can we track what is in your forecast and what is not? And if you do better in terms of getting more load and customers, is that something that definitely benefits the bottom line? Or is there like a lag issue in terms of spending money to serve it? Just how should we think about kind of when you update this? What's in there? What's not? And is doing better just definitely an upside?

Yes, Steve, this is Theo. I think when you think about what's in it, what's was not, primarily -- I think did talk about this a little bit at EEI, if I recall. What's in and in the forecast is basically the things that we felt had a clear line of sight on, felt good about at that time, which primarily are things we've had signed agreements or arrangements in place or was very clear we were going to have such an arrangement. So that's what you have in the forecast. As we move forward, you see on Drew's slide, and I believe this is on Page 12, contracts signed. A lot of that will show up in that particular category. And basically, I believe maybe about 1/3 of that maybe shows up through 2016. So there's still amounts post the years 2016. So I think that's how you think about it. In terms of how it affects the bottom line, obviously, as the sales take place, depending on where you are within a process of your various regulatory mechanisms in those jurisdictions, will inform as to the impacts those will have. If there is investment associated with it, as Leo talked about, the transmission opportunity, obviously that investment would be incorporated, and you would have the sales, you would have the cost. As rates get reset, obviously the sales become a part of your revenue requirements, the costs become a part of your investment. And the investment, obviously, and the returns on it flow to the bottom line. The sales get -- become a part of that process of resetting rates

Steve, this is Leo. Just to kind of add to that, if you think about it, for the near term in particular, it would primarily be transmission investment. To the extent these are large loads, you would anticipate that the sales level would be significant enough to make it positive to the bottom line, even though there could be some lag in the recovery of the transmission investment. In the areas where you've got FRPs, you're going to have some catch-up in the next year. And then in the case of Texas, for example, you've got the transmission rider, which could help in some respects. But we're trying to put the regulatory mechanisms in place to mitigate any lag. But at the same point in time, the size of these could make a big difference in how this turns out as well.

Okay. So just one other clarification. If you announce another kind of new customer contract, let's say tomorrow, that could be already in your backlog? It's not necessarily incremental? Like not all these have already been announced?

That's correct. Yes, so that would move something from the potential pipeline maybe into the contracts signed line.

Our next question comes from Paul Patterson with Glenrock Associates.

The expectations for the new capacity zone in New York, I was wondering if you could just sort of give us a little bit more flavor as to what they might be. And the impact of Danskammer, if it's there or not there, do you guys have any sense -- sensitivity about that? Or any sense you could tell us about that?

Sure. This is Bill. As it relates to -- I think Drew mentioned in his script that as it relates to Lower Hudson Valley zone, we saw a decrease there from the plan that we had announced last fall probably a little over $1 a kW-month for LHV. We've seen -- our point of view for the rest of the state perhaps increased a little bit. So if you think about it in doing your analytics, you might want to think about it as right now, we're at probably a $2 a kW-month uplift for all of our New York ISO capacity, whereas previously, we had indicated a $3 a kW-month uplift for the LHV zone itself. Right now, that estimate does not assume that Danskammer is in service for this summer. My understanding of that right now is that, that is a issue which will be evaluated in March of this year, and we will know better then as to whether or not that is -- that plant will be able to operate and qualify as capacity for that zone.

Okay. And any sense as to what that would be if they -- if it does show up?

I do not have that at this point in time.

Okay. Okay, great. And then just finally, with the mark-to-market loss reversal, I thought the explanation was really great. I just wasn't clear on the quantitative impact that, that had in terms of the impact for 2014 versus 2013 as a result of it.

Okay. So the mark-to-market loss in '13 was around $45 million pretax. And then we would see that uplift in '14. So in that -- it's in that EBITDA number that you're seeing in that chart on EWC.

Okay. And so that's not going to be there probably in 2015? So that's probably part of the reason why it goes down as well then?

That's correct. That's correct. And actually, some of it's at VY as well. That's -- for some of the hedges there. So that's one of the reasons why VY looks much larger than expected.

Our your next question comes from Michael Lapides with Goldman Sachs.

A couple of questions, a little bit unrelated to each other here. First, residential demand. As I understand it, you get a lot more of your Utility margin from the residential and small commercial customers than you do on the industrial side. Can you just talk a little bit about what you're seeing in residential demand? I mean, it's lagged industrial significantly. The major start-ups you're seeing in your service territory would imply a growth in job levels and improvement in unemployment rates, but it doesn't seem to be reflected in residential load levels.

Theo?

Sure. Mike, I think what you're seeing, I would believe, would be consistent with what you're seeing with other companies across the country. You're starting to see the effects of energy efficiency. And I think as we started the year of 2013 on our first call, we talked about our views of the impacts of that. And we would expect to see residential sales growth tempered. And, as you can see from our results for the year, they were actually slightly down a little bit. That's not inconsistent with our expectations. I will say the degree of which it's down is probably maybe a little more than we had expected, but not much. As it relates to kind of the economic change, I think what you see, obviously, is a net effect. We do see -- still see positive customer growth if you look at our customer count numbers. But what you're starting to see, again, I think, is a phenomenon that you see across the industry, which is usage per customer is going down. So while I don't -- I think that you are seeing some positive economic effects through actual increase in customer counts, energy efficiency, obviously, is having an impact on what you would see incrementally relative to those increased customer counts.

Can you talk a little bit about the utility margin, meaning how much as a percent of total comes from the 3 big customer classes? Just trying to kind of, I don't know, get my arms around demand levels, customer growth and megawatt levels on the industrial customer side versus what's happening -- actually happening to the Entergy Utility's margins.

Just in ballpark numbers, I think what you see, residential maybe is maybe even larger, around a $0.04 or so; commercial is $0.03; and maybe industrial, maybe somewhere around $0.02, generally speaking.

Got it, okay. Drew, a question for you just real quick. On cash versus GAAP taxes, what do you expect to be in the way of a cash taxpayer over the next few years? What's embedded in 2014 guidance?

Well, we haven't -- from a guidance perspective on earnings, we've put in -- I think it was about 36% for an effective tax rate. Given our NOL position, we would expect our cash tax rate to be lower than that, but we haven't put any guidance out for that specifically.

Materially lower? Like do you -- would expect to be a cash taxpayer? Or are you likely in non-cash tax paying status for a few years?

I wouldn't say we're in noncash tax paying status because we actually make deposits and those types of things as we go forward. So we will be paying some taxes, but it will be materially lower, I would expect, to the effective tax rate, at least for '14.

Got it. And how big is the NOL at the end of the year?

Well, that will be out in the K. Right now, I think it was at -- as of last year, it was still around a little over $12 billion. Most of that was tied up in the decommissioning election of cost of goods sold. About 3/4 of it was there.

Our your next question comes from Brian Chin with Merrill Lynch.

Could you just remind us again where the dividend policy is at? What's sort of the clean slate here?

As Drew mentioned, right now, the plan we have supports the dividend policy. The board will continue to look at where we stand at the dividend, as we have always been. The dividend comes from the utility, and anything that comes out of the merchant business is distributed differently. So that strategy or that outlook hasn't changed. As we look at the dividend, we would be looking at that as we grow, as the utility grows, as we look at the overall risk profile of the company and we look at the reinvestment needs that we have based on just how quickly the utility grows and what happens with the need for capital there. If it were to be above, just for example, the 3-year plan that we have now, if the load growth shows up the way we would like it to, which would be higher than the 2% to 2.25% range, then certainly that may increase the need for capital within the utility impact. Not only earnings growth that would give us the opportunity to pay a higher dividend but also the reinvestments we need to be returning to make it. So all of that's going to go into the mix, pretty much like it always has. But the bottom line of the utility pays the dividend and the merchant business cash flow is distributed differently is still the order of the day.

And we'd like to turn the conference back over to our speakers for any additional or closing remarks.

Thank you, David. 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 6761109. The telephone replay will be available through noon Central Time on Tuesday, February 18, 2014. This concludes our call. Thank you.

That does conclude today's conference. We thank you for your participation.