Welcome to Entergy Corp. Fourth Quarter 2016 Earnings Release and Teleconference. [Operator Instructions]. As a reminder, this conference call is being recorded. I would now like to turn the conference over to David Borde, VP, Investor Relations. Please begin.

Thank you. Good morning and thank you for joining us. We will begin today comments from Entergy's Chairman and CEO Leo Denault and then Drew Marsh, our CFO, will review results. In an effort to accommodate everyone who has questions, we request that each person ask no more than one question and one follow-up. In today's call, management will make certain forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these risks and uncertainties is included in the earnings release, the slide presentation and the Company's SEC filings. Entergy does not assume any obligation to update these forward-looking statements. Management will also discuss non-GAAP financial information. Reconciliations to the applicable GAAP measures are included in today's press release and slide presentation, both of which can be found in the Investor Relations section of our website. And now I will turn the call over to Leo.

Thank you, David and good morning, everyone. Today we're reporting final results for 2016, a pivotal year for our Company, a year in which our objectives were ambitious and our execution was on the mark. We delivered on our commitment to grow our core business and our utility, parent and other adjusted earnings reflected over 40% growth year over year. These financial results are the outcome of exceptional performance and have positioned us to achieve our financial outlooks in the coming years and to deliver steady, predictable growth in earnings, as well as our dividend. We raised our dividend for the second consecutive year, a trend we expect to continue subject as always to Board approval. And finally, with the Indian Point announcement last month, we completed our plan to exit the merchant power business and transition to a pure play utility. Our results today are the outcome of the disciplined execution of our strategy for the past few years, a strategy intended to fundamentally reposition our Company on a steady, predictable earnings trajectory. And today we're initiating guidance for 2017. We're also affirming our three-year utility parent and other adjusted earnings outlook, targeting a 5% to 7% growth rate, acknowledging that some years may be above or below that range. This morning, I will provide more detail about our longer term initiatives and the progress we made toward them in 2016, as well as our plans for the future. As I mentioned at the outset, 2016 marked a critical milestone in our exit from EWC and the risk associated with the merchant power business. We have finalized plans to sell or shut down all remaining nuclear plants in the EWC portfolio through a deliberate, planned and orderly process to cease all merchant nuclear operations by 2021, effectively exiting the…

Thank you, Leo and good morning, everyone. As Leo mentioned, 2016 was a pivotal year for Entergy. We continue to execute on repositioning our Company towards a steady, predictable, earnings and dividend growth trajectory. Today I will discuss how our core utility, parent and other adjusted EPS grew by over 40% in 2016 and I will provide an overview of our guidance for 2017. I will also provide our perspective on EWC going forward and potential tax reform. Now let's jump into 2016. I will start with the key takeaways from fourth quarter consolidated results on slide 5. On the left, Entergy's as reported loss of $9.88 included special items totaling $10.19 related to the decision to sell or close each of EWC's nuclear plants. The majority of that was for previously disclosed impairment charges for Indian Point and Palisades. On an operational view, our consolidated earnings were $0.31 per share in 2016. This compares to $1.58 a year ago. Remember that 2015 results included significant income tax benefits, largely from the business combination of the two Louisiana operating companies. Turning to utility, parent and other on slide 6, operational earnings-per-share decreased $1.07 quarter over quarter. 2015 income tax items net of customer sharing were $1.15 -- excuse me, $1.57. Conversely, weather was favorable in 2016. Adjusted EPS normalized for tax items and weather improved year over year. This was partially due to rate actions to recover investments that benefit customers and improve returns. Specific drivers include Entergy Arkansas's rate case, Union Power Station acquisition, Entergy Mississippi's Formula Rate Plan and Entergy Texas transmission cost recovery writer. Results also included lower write-offs and reserves related to regulatory proceedings. We reported an $0.08 charge in the fourth quarter of 2016 related to the Waterford 3 steam generator replacement project which I…

[Operator Instructions]. The first question is from Stephen Byrd of Morgan Stanley. Your line is open.

I wanted to go through the tax reform updates that you provided. For the reduction income tax rate from -- to 20% from 35%, is there a sense of the magnitude of the EPS impact from that? I'm thinking really more for parent and other, not as much for EWC. But is there an approximation that we should be thinking about in terms of the magnitude there?

Sure. Just from the tax rate change in isolation, it is probably $0.10 to $0.15 if you went from 35% to 20%. But, again, as I mentioned, we would still have the NOL in place. So we wouldn't expect any real cash impact near term for that.

Understood, understood. And then just as a follow-up in terms of thinking about EWC and its cash flow over time, would you mind just giving us your latest thoughts on what is the likely cash flow profile for that business through this period of time overall?

Stephen, our expectation through 2021 is that we would be able to get back to about flat from a cash flow perspective and you can see where the EBITDA is. And net of all the specialized -- and that includes all of the -- the special items include all of impairment expectations and the capital expenses and everything else. It doesn't include the ND team which I mentioned is sensitive which would take us a little further negative. But we have opportunities operationally and in some of our balance sheet items like working through the working capital and other things to bring us back to negative. And if we're successful, we can get a little higher than that.

Understood. So you would be neutral by 2021 and any guidance in terms of the cash flow position prior to 2021?

I'm sorry. Say that again, Stephen?

So it sounds like you are on track to be neutral by 2021. But prior to 2021, is there any guidance in terms of the cash flow position for EWC during 2017 through 2020?

2017 through 2020? I think this year will probably be probably a negative cash flow year because we have three refueling outages in the business and as we move forward, it would be a little bit better than that. And then as we get toward -- we will have expenses associated with severance and retention that we incur as each plant shuts down. I think most of that is detailed in the back in the appendix.

The next question is from Praful Mehta of Citigroup. Your line is open.

So a question firstly on the utility group and with the Trump growth and infrastructure plan, there seems to be lots of talk on the spend and one benefit could be your service territory. So I wanted to understand given you haven't really changed your utility group profile, if you expect to see anything and if you do, how will that translate to utility growth?

Well, I will start and then I will let Theo or Rod jump in. But our growth profile right now, particularly over the term that we give the outlook through 2019, is pretty set as it relates to the modernization of our infrastructure across all segments of the business, whether it is generation, transmission or distribution. And recall that a lot of what we're doing on the generation and transmission side is both catching up to a short position plus modernizing aging and less efficient infrastructure on both sides. So changes in growth profile that would be caused by anything that's coming up with Trump would probably not happen fast enough to have any kind of impact on our growth strategy as it stands right now. If we were to start to see things happen that -- particularly in the energy sector that started to provide a stimulus for growth where we started to see our existing customers expand or new customers show up, that would really be more of a continuation of the existing story. We've got the 3% industrial growth that we had in 2016 that we're looking at again in 2017. That just might continue that path, but that most likely would be in projects that would show outside of the 2019 timeframe.

Got you. Thank you. The next question I had was on just the decommissioning. On slide 49, you lay out the decommissioning status and just, for example, the Vermont Yankee trust assets are higher than the liability, but the sale of the asset is basically at no cost or no price. So I am trying to figure out how do you think about decommissioning funded status relative to your strategy to sell these assets to somebody else to decommission? Shouldn't there be some value in the decommissioning trust relative to the liability?

Well, that is true and I can just talk to the balance sheet items and what is going on there. I will let Bill talk to the commercial element that I think is associated with your question. The trust -- the liabilities and the trust -- well, let me say the liabilities are accreting over time. I'm not sure I understand if there's a question in there about the liabilities. But they are accreting over time and we're seeing some expense associated with that. The trust assets -- and our seed minimums are all met. The trust assets are growing at about -- we're assuming the growth is around 6.25% over time. By the way, there is a rule change in 2018 about how much income we may recognize because we moved to mark-to-market on the equity portion of our trust. But I think that we're anticipating and our current plan is profitable that we would put some money into the decommissioning trust. We talked about that. There is some we're expecting to put in for both Palisades and Indian Point, but the Pilgrim trust is pretty well funded at this point, as you can see in that table. It's at $960 million. So I will turn it over to Bill to allow him to talk a little bit about the commercial implications of where the trusts are and how we might disposition them.

Yes, I mean essentially -- if you take the VY deal, the way it was looked at is you've got the -- obviously we've got our projected liabilities and you would compare that to what the NDT is. What we're looking at is folks who have the capability to do this on a much more aggressive schedule and a much more efficient schedule. So while there could be a small top-off with something like VY, that has all been taken into consideration in the negotiation of the commercial deal. If you look at what we're looking at in terms of the transaction with Pilgrim and Palisades, you're looking at one which is overfunded, one which they would look at as being underfunded, but they have the ability to look at that on a combination basis and that's why we packaged those together to do some -- do preliminary due diligence to look at doing a very similar transaction.

The next question is from Michael Lapides of Goldman Sachs. Your line is open.

Couple of questions. First of all, Leo, you commented briefly about opportunities in terms of rightsizing the corporate organization. Can you give us a little bit of detail about that in terms of how big of an opportunity from a cost saves prospective and kind of a timeline that -- when -- how long do you think it would take you to achieve and when do you think you'd be at a more normal run rate?

And I guess we're at a normal run rate right now and if you think about it, Michael, we're actually in the -- and I was talking that section of my script around the nuclear corporate organizations, as well as the corporate organization as it relates to overhead inside EWC. We're -- as we have said here over the course of the last several months, we're running somewhat of a lean shop strategy. So we've got that going for us to begin with as we start to ramp up to get more towards industry benchmarks at the same point in time the EWC is shutting down. The whole point there is we made the decision to shut down Vermont Yankee in 2014. We started looking at the issue in terms of rightsizing the organization then with an eye towards recognizing that a lot of this stuff has been in the works for a long time. From 2014 to 2021, we had a seven-year period where the plants will sequentially go away and we have already started working on that organizational size. The question comes up from time to time about the overhead as if it's an issue. It is just not. That was the point I was trying to make.

Okay. Super helpful. One, if you don't mind one quick follow-up. At what point -- like the deal with the state of New York regarding the retirement of Indian Point and the planned retirement is 2020, 2021, but there's the potential the plant could live out to 2024, 2025. At what point would you know? How does the decision-making process happen in terms of the state decides or some combination of other and how early do you need to know? Like at some point, refueling decisions or other similar decisions have to get made if the state decides to play it and wants to operate beyond 2020.

Yes, Michael. This is Bill. So, really, the responsibility for the resource need will fall with the New York ISO. So what you need to be watching for is they will do an updated load and resource study probably the second half of this year where they will start to incorporate the shutdown of Indian Point, as well as any other additional resources that may be coming online. So that will start to paint the picture of what 2021 looks like. And so that will look at overall capacity needs, as well as specific reliability needs in terms of system security. And then that will be updated on an annualized basis. What we're going to need to be watching for -- and the state will be watching for -- is that we will have to likely make a decision sometime in the second half of 2018 if we want to extend the operations of that unit. And then we would have to enter into negotiations with New York State because, remember, that is a mutual option. We both have to agree, so obviously they have to recognize the need for reliability and we have to ensure that we fully recover all of our costs.

Got it. So, in other words, post 2020, if there is in operation, it is likely under some form of PPA or some other agreement that probably looks, smells and acts a little bit like an RMR because it is actually needed for reliability purposes?

Yes, sir. That's correct.

The next question is from Steve Fleishman of Wolfe Research. Your line is open.

Just didn't hear much of an update on the nuclear improvement program. Could you just maybe talk about how that is progressing? Any update on the cost levels that you gave before those? Should we just assume those are the same? And just how do you plan to update us on how that is going, kind of going in the future?

Steve, I would say that right now there is no update on the costs. You should assume that they are what we have outlined in originally and continue in the numbers today. As far as updates, right now the nuclear strategic plan is all wrapped up in our expenditures. They are in all of the guidance that you have got right now. We're beginning to see improvements in the operations of the facilities. So I think it would just be on a regular basis and probably more by exception than anything else as far as what we would be updating you on. As far as where it sits in the regulatory process, as Drew mentioned, everything that we've got going on at the moment is just running through the normal regulatory processes that we've already got in place, particularly given the fact that we've put some pretty good mechanisms in place over the course of the last several years to adjust things on a regular basis. And, as you know, we're in the process of reviewing some of those costs that were in the 2017 -- or the 2016 filed Formula Rate Plan. There is no procedure in Arkansas. There is no procedural schedule for that at the moment. We would anticipate that that will get done if not before, at least within the same context as when we make the next filing of the FRP in Arkansas.

That last point is that you are referring to the small prudence thing that was opened up on the last -- on your settlement on the filing there?

Really what that is the fact of the matter is the process is a brand-new process, the Formula Rate Plan with the forward-looking test year. And so we're just going through the process and the Commission just wants to make sure they got it right, that's all.

Okay. But, operationally, do you feel that the nuclear performance improvements are going on plan? Ignoring cost, just operationally. Okay.

Both. Both. Not ignoring costs. Everything is on plan.

Everything is on plan. Okay. One other question. Just to clarify, I know you give the three-year utility guidance, but the 5% to 7% that you mentioned at the beginning of the call and I think you said something about that being some years above, some years below, what are you now using as the base for that 5% to 7%?

Well, we're still -- this is true. We're still thinking about, I guess either place you could base it off of where we're for 2016 or if you went back to an adjusted view of 2015, it would be a little bit higher than that. But either way, I think our objective is to try and get in that range each year, although at times it will be a little lumpier than most. So I think it doesn't really matter, Steve, where you would start from is our objective, but we should be able to get in there over time.

Right. Because obviously 2016 -- 2017 is below, but then I think 2019 is well above based on your guidance. So that's what you mean by the back and forth. That's kind of --

That's right. That's right. If you recall, last year before we put the nuclear costs in, we were expecting to be more steady in that. And now we've got the nuclear costs in. But as time moves forward, we would expect to get recovery of those costs and we would get back on track to our original plan. So that's why 2019 is still where we would put it, I guess, a year ago. And the other, 2017 and 2018 moved down slightly, but we expect to get back on track.

Okay. One last thing, Leo. I think you are on the EEI tax committee -- the tax reform committee. Just maybe any just more color on how we should think about tax reform given the discussions that you have had and just where it might go?

Well, I mean I think, as Drew mentioned and I think everybody else in the industry has probably mentioned, it's pretty early in the process as it relates to what's going on in the dynamics. Then I think what will be the most determinative over time are the interplays of all these different items, not only how they impact our industry, but others as well. But I would say that the dialogue that the industry has had with folks at the White House and on the Hill has been constructive. I think the history the industry has in terms of the way our rate regulated regimes work is understood by a large number of folks. And so I think that we're in a position where we're talking to the right people. We're having a lot of dialogue. Everybody's doing it with a pretty aligned point of view and we hope that things constructive come about because of it. And, again, the nature of our business being rate regulated certainly does provide some nuances that are important to us. It may not be important to other industries, but that has been provided for in the past when there's been tax law changes. And, also, the fact that we're rate regulated gives us some ability to make sure that we have rational regulation around the way the law turns out, just like we do today in terms of normalization practices and things like that.

The next question is from Julien Dumoulin-Smith of UBS. Your line is open.

Just wanted to follow up a little bit on some of the last questions here. Can you talk a little bit about some of the costs associated with EWC and how that might get allocated out in the future vis-a-vis the regulatory business? It might somewhat dovetail with your talk about spreading down costs overall, but just wanted to understand how that process plays out. Then I've got a follow-up.

Well, the way the process falls out is we have corporate organizations that allocate costs to EWC. Again, a seven-year period over which plants go away one at a time to be able to manage that process. We have already begun managing it on Vermont Yankee which is over -- we have already gone through the process of shutting down Vermont Yankee. We have already managed it as it relates to the Rhode Island plant which we have already sold. We have already managed it as it relates to the wind assets which we have already sold. We will manage it as it relates to Fitzpatrick which will be sold this year. We will manage it as it relates to Palisades which will shut down in 2018 and Pilgrim in 2019 and then in 2020 and 2021. It is just -- it's a process that has to be managed as it relates to what those costs are. But to right-size the organization over a seven-year period is something that we will be able to manage. So I guess, Julien, it's just not an issue of significance that I would say.

I can throw in some modeling elements, too. This is Drew. From a modeling perspective, when we started we had about $35 million per plant of overheads. And we've had direct costs for each plan. I don't have the percentages in front of me right now for each plant going back to Vermont Yankee. But each one of those is going to peel off as those plants are shut down. And I think there may be about 40% or so left that is indirect costs and those are the ones that we will have to work down over time that Leo is talking about and we've got a really good headstart. So I think at the end of the day, what we're going to end up with is the costs that are reasonable and necessary to operate the business going forward. And that should make sure that we have reliable and safe operations of our nuclear plant. So I think that's the -- from a modeling perspective, those are the things that you would look at as it winds down over time.

But just to follow up here just quickly, you talked about the non-nuclear assets and Cooper contract being generally earnings neutral. But just outside of that on a go forward basis, 2021 onwards, you're talking about ramping down the costs. There should be no other costs outside of decommissioning and NDT that need -- that are ongoing. The remainder is either cut and/or allocated out and largely there is no other cost EPS that you are going to [indiscernible] the business.

That's correct. And in the slide in the front, we talk about the NDT earnings and the decommissioning expense that is on slide 13. And you see initially, there's a pretty big gap between the decommissioning expense and the NDT earnings. I think one thing that is important to know there is, for the earnings part of that, we're assuming that we're realizing only about 45% of 6.25% of the earnings in 2017. And so it is effectively showing you a 3% return on your NDT earnings. The rest of it is going straight to the balance sheet. And then in 2018, we will have an accounting change which would cause us to mark-to-market much more of the equity portion of the trust. And so our return will go up substantially, not from 6.25%. It's going to stay there, but we will just acknowledge more of that in the income statement which will close that gap. And then over time, if we're successful, of course, in doing more VY-like type transactions, that should shrink as well.

Sorry. Just a quick follow-up on Arkansas Nuclear One, what is the timeline for filing for and/or process to just get recovery on the regulated expense there? Just a quick one.

I think as it relates to -- there is no filing around Arkansas Nuclear One. There is a Formula Rate Plan filing that we had, the one that is already in place. There is the review that is going on where there is no procedural scheduled for yet and then we will just make another Formula Rate Plan filing. Is that what you're asking about, the recovery?

Yes, I was presuming it was part of the FRP, but I wasn't 100% sure.

Yes, yes. It was part of the FRP as it relates to the rates that are in effect today and that's where we're going through the process where the Commission wanted to go back and review some more information on those costs. There is no procedural schedule around that at the moment, but then there will be another FRP filing this summer. And so there will be more costs associated with every -- the whole business, including ANO, at that point in time. So we would anticipate that the one that is out there today will either get a procedural schedule before that time or it will get wrapped up at the same point in time. That's the next step --

The next question is from Jonathan Arnold of Deutsche Bank. Your line is open.

Hey, Leo. Actually I wanted to clarify just on the question you were just talking about. Firstly, are those costs likely to get recovered in 2017 under the 16 FRP if they wrap it up sooner or are they sort of -- I think they set them aside, so they wanted more information, but would it be retroactive to the beginning of the year if decided on a more timely basis than next year's filing?

They are in rates now.

Okay. So the question is whether they stay in or you are collecting it today?

Correct. They are just reviewing them. They didn't set them aside out of the pricing. They are all being recovered today.

Great. Okay. Thank you for that. And secondly, I know you gave a number on what you thought the potential utility or parent and other exposure to tax reform at a lower tax rate would be. If you layered in losing interest deductibility as well, in that kind of scenario, would you guys still see yourselves in the 5% to 7% range? Does it move you in the range? What's the -- how should we think about that kind of incremental scenario?

Jonathan, this is Drew. Clearly we have a fairly narrow range out there for utility, parent and other. And if you were to layer on the change in tax rate and the interest expense, that -- assuming that was the scenario you ended up with, it would probably move you close to the bottom of that range. It's too early to tell about what we decide to do with the ranges at this point. But if you just were to take those two things in isolation, that would probably bring it to the bottom of the range. But it's not clear yet that we would move the range or change our guidance or anything at this point.

Thank you and at this time I would like to turn the call back over to David Borde for closing remarks.

Thank you, Latoya and thanks to all for participating this morning. Before we close, we would remind you to refer to our release and website for Safe Harbor and Regulation G compliance statements. Our annual report on Form 10-K is due to the SEC on March 1 and provides more details and disclosures about our financial statements. Please note that events that occur prior to the date of our 10-K filing and provide additional evidence of conditions that existed at the date of the balance sheet would be reflected in our financial statements in accordance with generally accepted accounting principles. The call was recorded and can be accessed on our website or by dialing 855-859-2056, confirmation ID 52887956. The telephone replay will be available until February 22 and this concludes our call. Thank you.

Thank you. Ladies and gentlemen, this concludes today's conference. You may now disconnect. Good day.