Good day everyone, and welcome to the Entergy Corporation First Quarter 2014 Earnings Results Conference Call. Today's conference is being recorded. And at this time, I would like to turn the call over to Vice President of Investor Relations, Ms. Paula Waters. Please go ahead, ma'am.

Good morning. 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. Now, I'll turn the call over to Leo.

Thanks, Paula, and good morning, everyone. By any objective measure, the first quarter of 2014 was extremely successful. Our operating groups provided excellent service to our customers under extreme conditions. Our commercial groups continued to provide growth opportunities while aggressively managing risks. Our support functions continued to evaluate and implement more standardized lower cost end-to-end business support processes, spanning multiple functions within the company. We continued our mission to support our communities through assistance programs and our direct contributions, and as a result, we created value for all 4 stakeholder groups: our customers, our owners, our employees and our community. This performance was achieved in both the Utility and at EWC, and our financial performance followed suit. Mainly, operational earnings per share were more than double those of last year, setting a new first quarter record and were driven by top line growth and lower costs. This quarterly performance, coupled with higher Northeast forward prices for the next 9 months, led us to raise 2014 earnings guidance by more than 20%. To be clear, weather is not a strategy. Colder-than-average temperatures for multiple stretches of time in the Northeast and in the 4-state Utility service territory had a significant impact, but weather is just one part of what we think is a strong overall story. We must perform day in and day out. To that end, our employees and equipment performed great this quarter. Let me give you some highlights. Starting with EWC, our nuclear plant performed well overall to help serve increased power needs due to increased demand in New York and New England over the past 3 months. To put this into perspective, the weather in this region, as measured by heating degree days, was 11% colder than normal and 13% colder than last year. As it relates…

Thank you, Leo, and good morning, everyone. Today, I will review the financial results for the quarter as well as our updated 2014 operational earnings guidance. Starting with Slide 2, our first quarter results for the current and prior years are shown on as-reported and an operational basis. Operational earnings per share were a robust $2.29 for the first quarter of 2014 compared to $0.94 in 2013. The significant increase was due largely to higher net revenue from EWC's Northeast nuclear fleet, while Utility net revenue was higher as well. Operational earnings excluded special items from the decision to close Vermont Yankee and HCM implementation. Earnings and operational results on Slide 3. Starting with Utility, operational earnings per share were $1.13. This is $0.40 higher than the $0.73 earned in the first quarter last year, and there are a few key drivers that I'll highlight starting with net revenue. As reported in the pre-release, weather was positive in the current period compared to the mild temperatures in the fourth -- first quarter of last year. In addition, positive weather-adjusted sales growth contributed about $0.05. On a weather-adjusted basis, billed sales were 2.1% higher than the comparable period. The increase was consistent across the residential, commercial and industrial customer classes, with industrial sales growth for the quarter at 2.5%. Industrial gains were broadly spread across multiple segments. The net effect of regulatory actions was also a factor for Utility net revenue but was largely offset by other line items and therefore contributed only about $0.03 to the quarterly earnings increase. The net revenue increases were partially offset by an unfavorable unbilled revenue variance of approximately $0.09 quarter-over-quarter. Besides net revenue, nonfuel O&M was also favorable quarter-over-quarter, reflecting lower pension expense from a higher discount rate as well as last year's cost…

[Operator Instructions] We'll take a question from Kit Konolige from BGC.

A couple of follow-up items. So can you go into a little more detail on the increase in the O&M spending? If I understood it correctly, I took away that it's an opportunistic spend due to the improved revenues and sort of reinvestment, if you will. Are there particular segments or companies or projects that you're spending that O&M in?

Thanks, Kit. Yes, so at EWC, that is certainly the case as well as the Utility. And so at EWC, part of that is paying people for the great performance that Leo talked about in the first quarter, and part of it is looking for opportunities to move projects forward if those arise. The challenge associated with those, of course, is that they are difficult projects to plan. It's not easy to move a lot of O&M forward like that, and so we are getting an early start on it. It's easier to pull back than it is to decide at the end of the year that you want to move a lot of O&M forward. At the Utility, we're a little ahead of -- in that same regard. It's something that's beneficial for customers in terms of rate stability if we can offset some of the beneficial weather. And since it's still early in the year, we don't know that we'll be able to actually have the opportunity at the Utility to do that. And we'll certainly be looking at each company, because not all Utility companies will likely have that same opportunity. So -- but that's what we're working on today. We're preparing. We're trying to form up projects, and we're looking for those opportunities. But there's no guarantee that we'll openly end up spending that O&M.

And on a separate area, you mentioned that -- if I heard it right, that 80% of the EBITDA in 2014 first quarter could recur in first quarter '15 and at $0.90 a share of the increase in the guidance range was due to the first quarter. First, just wanted to confirm that those were correct, and I just want to try to get an idea of how much of a, if you will, permanent baseline change there is here in level of EPS and EBITDA that will recur in '15 and forward. Obviously, forward prices have gone up some, and as you say, volatility has gone up and so on. If you can give us some idea of what we're looking at going forward, that would be a big help.

I'll start with the math part, and then I'll turn it over to Bill for the point of view discussion. So I think the math that you had, Kit, was correct, but I'd put a bunch of caveats in there as well. So those are -- it's 80% under the same market conditions that we see next year in the first quarter. And yes, that is against the $0.90 increase plus the part that we already had built into guidance. So it's the overall EBITDA that I was talking about when you look at it that way. And so part of that is from the fact that Vermont Yankee is not going to be in our portfolio next year. And part of that is, as you said, forward prices have already moved up, so we do have some still open positions in our remaining portfolio. They benefited from some of the price moves so far. And so you get up above what Vermont Yankee's contribution was this quarter, because some of our other positions have benefited from that early price rise. So with that, I think I'll turn...

This is Leo, Kit. Let me just jump in to make sure I -- I don't want you to -- I want to make sure you get the right specifics. The 80% Drew was talking about is if the same price volatility happened next first quarter that happened this first quarter, we're positioned that we can capture that value. If you want to look at -- when you were asking about permanent, the slide we have in the deck on EBITDA, that's where the market is today. And so you may not have been thinking this, but I just want to make sure. We're not saying that we already have 80% of what we've got this quarter -- first quarter next year. If the same thing happened, we're positioned to capture it. That's what Drew was trying to say.

It's the same market conditions but not the same weather, obviously.

Well, Kit, whatever reason. It might happen because of weather. It might -- that would probably be why it would happen.

I get it, okay. It's basically just removing the Vermont Yankee impact.

That and some of the price rise that we've already seen so far this year. As you said, [indiscernible] prices have come up a little bit already.

Our next question will come from Jonathan Arnold with Deutsche Bank.

Just a quick one on the -- in the Slide 21, you're just alluding to talking about just sort of the look at market today. Obviously, you don't specify the numbers, but it seems from the movement in the 2015 number in particular that it took -- probably up about $100 million of EBITDA outlook versus the prior version of this slide. I guess my question is, you've got 74% hedged. You now expect to realize 53% on that versus 49% before, which is a $4 uplift, and then the market pricing slide is also kind of a $4 uplift. And it seems 4x your generation ought to be closer to $150 million than $100 million. So is there some offset? Does my math make any sense there? And is there some offset embedded in there? Or are you sort of embedding some conservatism about next year in particular?

I'm not sure I followed all the way through on the last part, but I think it should all kind of hold together. I don't think there's any big offset built into the numbers that we're showing you there.

But your hedged is up $4, and your open is up $4, and you've got 35 terawatt hours. It just doesn't seem that the bar is moving as much as it should by some reasonable margin.

Well, there is a bit of rounding in there as well, but there's -- we don't have any unplanned or hidden offsets in there. We're showing you just the revenue uplift there.

Okay. And then if I may, on this discussion you just had about the 80% and the 20% if we have a repeat of this year's conditions next year. What -- can you be a bit more specific about what kinds of products that you use this year are not available in the market for next year and how you're -- and just some more color on how you're adapting to changes in available products in the market?

Sure. This is Bill. I think as we've explained previously, we use a variety of different products. So some of that includes unit contingent. Some of that includes cap collars. And we use a variety of different option structures, both European, which clear on a forward basis versus Asian options, which clear more on a daily basis. As you can appreciate, as the volatility in this market has increased and if you look at daily volatility from -- for example, from winter '13 to winter '14, we've probably seen a pickup of over 50% between '14 and '13. Obviously, some folks who were willing to sell those products in the past have reconsidered their risk profile. And so right now, they are not as willing to offer those products, and so we have to readjust our portfolio to what's actually available in the market to be able to capture that. However, as Drew said, we still believe we have the opportunity to capture a significant portion of those upside, but it will be a different portfolio and there will be different prices associated with the products available due to that increased volatility.

We'll take our next question from Paul Fremont with Jefferies.

I think I just want to better understand the changes that are taking place in the Utility guidance for '14. I guess the starting point would be there's a $0.20 reduction in the midpoint, and that includes the $0.18 of positive weather in the first quarter. So are we really looking at sort of a delta here of $0.38? Is that...

Yes. This is Drew, Paul. That's a good question. So in the net revenue line, there is an offset to that $0.18 in our unbilled revenue category. And unbilled is something we don't normally talk about, because it's usually kind of plus or minus right around 0. But this quarter, it's a large number, and it has to do with sort of the estimates at the end of each quarter that we make. And so it was -- it's really sort of a holdover from the very end of '13 when it was really cold, those last couple of weeks in December. Those dollars have since gone into the build revenue category. And we're backing them out of the unbilled category, and you see the offset to the build. So it's about -- as I said, it's $0.09 quarter-over-quarter. It was about $0.10 between December and the first quarter of this year. So that's the biggest thing in that net revenue line that you're probably not seeing completely there.

Right. So that -- in other words, if that's $0.09 out of what would be potentially $0.38, what would be -- or is it $0.09 out of what really is $0.20? That's what I'm trying to figure out, because don't I need to add the...

If you're looking at $0.30, I think you're looking at quarter-to-quarter versus the $5.20 midpoint is just for 2014. And so our expectations for 2014 from the net revenue perspective have been largely met except you would say plus $0.18 for weather, minus $0.10 for unbilled and then a little other noise in there to get you that plus $0.05. And then...

Okay, so that -- but then that still leaves like $0.28. So in other words, I'm just trying to figure out what drove it -- what's driving the $0.28 and whether that's -- we should look at that as potentially recurring items or nonrecurring items?

I'm not sure I'm following where you're getting the $0.28 from. I'm sorry. I think when we said $0.28, it's plus $0.18 weather this quarter versus minus $0.10 first quarter of '13. So there's a $0.28 weather delta there. Is that what you're looking at?

No, I'm just taking the $0.20 change in the midpoint of the guidance, adding in the weather of $0.18 and then subtracting out the $0.09 or the $0.10 that you gave me for...

Okay. So then -- so if you come down on the guidance table, maybe what you're seeing is there's a bit of the opportunity spending, and then the other part is the taxes piece. There were some tax items that we thought would occur this year when we set guidance in October. It looks like those have pushed back a little bit, probably into '15, and so that has moved out. We don't -- we still think those things will happen. The timing has just changed on them. So those are the -- from the guidance table, those are the main drivers.

And the opportunity spend and the taxes together would sort of represent the difference? And -- because you also mentioned somewhere in there rate case outcomes.

Right, right. And so that's the smaller piece that's in that net revenue line item. That's part of what gets you down to the $0.05, and it has more to do with the Arkansas rate case at the end of the year probably than anything.

Okay. And still the expectation -- so even with sort of -- so in other words, if the Arkansas decision isn't reversed, you're still confident that you can come up with other offsets by '16 to get to the same $950 billion Utility net income number.

That's correct. That's correct. And as Leo said, we're looking for ways to exceed that. So we feel pretty good about where we are in terms of our 2016 number. Recall that, that doesn't include any tax benefit in it, and we have all the industrial renaissance and economic development opportunities in front of us. We think that's pretty safe right now.

Our next question will come from Dan Eggers with Credit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Just on the hedging strategy, just make sure so I understand this, in the ratable or kind of point of view base that you guys are using, you didn't really increase hedge positions in the quarter. What is the thought process for adding on any out years as we move through this year? And what kind of percentage hedges do you want to have maybe going into 2015?

What -- I mean typically, we look at prompts here, we hedge 85% of that position. So that's kind of the guidelines that we followed and we'll expect to continue to follow. Of course this year, effectively, we were a little less than that due to the fact of the uncertainty around VY and how long that unit would run and the uncertainty around the CPG. But we would intend to be hedged in an 85% level. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And then on -- kind of with the MISO integration, you haven't had a little more time with it and then some of these issues that have come up between transfer between MISO classic and MISO South. Can you maybe give a little color on how you guys see that getting resolved, what impact that's had on even with the value proposition of joining MISO from what you guys originally anticipated? And is that going to have any bearing on potential CapEx opportunities with the MISO transformation?

[Indiscernible].

And gentlemen, this is the operator. We are unable to hear you at this time. [Technical Difficulty]

The point I was making on the SPP MISO issue for the company, SPP filed a complaint at FERC seeking to -- in essence, to have FERC charge MISO for any excess capacity beyond the 1,000-megawatt limitation and the tie-in between MISO North and MISO South, the point being that we're in the initial stages of the litigation, if you will. We have not -- we've not ruled out the possibility or likelihood of resolving that issue by way of settlement. But if we were to ultimately go to hearing and if SPP were to maintain their position, that is essentially what they're seeking, to limit that inner regional dispatch to 1,000-megawatts and to issue that payment to SPP from MISO for any megawatts beyond that 1,000-megawatt capacity, so the debate is really about that. We don't have a point of view on how MISO would address it if FERC were to find that SPP's position was well founded. But again, it's early in the process, so we really don't know kind of how that plays out at that the moment. Daniel L. Eggers - Crédit Suisse AG, Research Division: If this were to not get resolved, would this affect the value proposition of you guys joining MISO?

No.

Next we'll hear from Steven Fleishman with Wolfe Research.

Just wanted to first clarify how the LHV pricing came in relative to your expectation of a $2 increase for the full year, maybe just some color on that.

Yes. I think, as you know, the LHV pricing came in for the summer strip rider a little bit under $10. May auction, spot auction was around $12.25. So that's in excess of our original estimate.

Okay.

Not a whole lot. No, not significantly higher, but I mean it was a limit bit higher than what we had used as our kind of midpoint.

Okay. It's really hard to tell, because the $2, like an average for the year.

That's right.

So if we were thinking about this for a summer strip, was it $1 or $2 or something like that above what you would have thought the summer strip price?

It's less than -- much less than $1 on an average basis.

Okay. So that's -- any LHV pricing that's assumed in the EBITDA -- any New York capacity pricing assumed in the EBITDA charts that you have should be pretty close even though you didn't update for that. It shouldn't be that different based on what came out.

No, that's right. It should be consistent with what came out.

Okay. One other question just on clarifying kind of your point of view on New England and the like. And one could argue that there's obviously some pretty severe constraints. We also did seem to have some relatively severe weather, maybe not as much just in New England but like kind of the whole regional area or maybe the whole northern part of the country. So when you're talking kind of the bullish point of view and keeping your strategy the same, is it -- in a normal winter weather situation, do you think there'd be this much extreme or still have kind of an extreme option value that things are that bad in New England, that even normal weather, you want to keep the big option position?

Yes. I mean, here's the way we think about it is, we've seen volatility in those markets in the last 2 winters, okay? And this winter, obviously, was more severe than the winter of 2013, but nevertheless, we saw volatility. Now take into consideration for 2014, you've got Salem Harbor coming off, that's about 750 megawatts. VY will be off in the first part of 2015. It'll actually shut down at the end of this year. And then you've got other units like Brayton Point that will come off in 2017. So you're losing a substantial amount of resources over the next 4 to 5 years. In fact, if you look at their overall portfolio, you're going to lose about 4,000 megawatts which represents about 10% of their generation -- over 10% of their generation capacity. And reserve margins, obviously, have declined to the point where FCA 8 resulted in a deficiency, and you went to basically new build prices for new resources. So there's a lot of dynamics going on there, but we believe that there will continue to be constraints. While there's a minimal amount of new pipeline capacity coming on due to compression projects, that type of thing, we don't believe it's adequate to replace the additional capacity that will be retired.

Next we'll hear from Paul Patterson with Glenrock Associates.

So I hear your comments with Steve on the markets and what have you, and I also heard your opening comments which sort of indicated substantial concern with the way the market's being structured and what have you. And so I guess so to follow-up on this, do you guys -- I mean, I know what you guys are planning in terms of your filings, and I've followed your Exelon and Entergy joint filing on the Forward Capacity 9. But is there a plan b if, in fact, we don't get the market structure that you guys contemplate? Or should we think, basically, that things are sort of going in your direction and you guys are cautiously optimistic, and we're going to be seeing this sort of process continue in the stakeholder process, what have you and see how it plays out? Or is there perhaps another strategy you guys might be thinking about to get more value for your generation plan?

Well, it gets to be a little bit complex, but let me lay this out. So we're working through the stakeholder process both in New York and in New England and at FERC, and we believe there's improvements to be made in the capacity market design. We believe there's improvements to be made in the energy market design, and we also believe that there are opportunities to be fairly compensated -- for generators to be fairly compensated based on the actual attributes they provide, for example, on-site fuel, 0 carbon emissions, et cetera. That is going to be a fairly lengthy process. We think we will see some immediate improvements, for example, in ISO New England with real-time energy pricing coming up by the end of this year. Leo mentioned the slope demand curve. In the interim, as we have mentioned, we expect to see quite a bit of volatility in the markets just due to the constraints themselves. And so when you say is there a plan b, I mean we're kind of working all of those in parallel and we expect to see some continued volatility until some of these market issues get resolved. And I think the polar vortex brought to the attention of all the markets and to the regulators that we've got some structural design issues that need to be addressed.

Okay. Going back to Forward Capacity Auction #9, there is this new entry pricing extension that's being proposed, and I was wondering if you could -- if you have any thoughts -- I mean, obviously you guys are against it. I understand that. But if you have any thoughts about what the -- I mean what the impact might be if that provision stays in the -- it could be whatever the proposal that New England put forth?

I'll make sure I understand. Are you talking about the exemption as it relates to the renewables associated with that and the slope demand curve?

Yes, the slope demand curve filing and the new entry pricing extension, they're going to increase by 40%, MISO proposing, from 5 to 7 years for new entry pricing.

Yes.

Right. And I'm just wondering if you have any thoughts about what that impact might be or if that's significant given the constraints you're talking about on the gas side or...

I think our point of view is, we're not necessarily probably hung up on the 5 to 7. What has -- the most challenging for us is that when the ISO sets -- has new capacity enter the market, they choose a number of $7 a kW/month to provide existing generators. And so we believe, with the slope demand curve, that we have the opportunity, depending on resource availability, to see additional upside probably somewhere -- to $10 or $11 of kW/month once that slope demand curve gets put in place.

Regardless of these other market design issues such as the extension and the exemption that you were discussing earlier, that even with those in place, you still think that the capacity price should probably get up there. Is that right?

We still think -- I mean, obviously, we're concerned about the exemptions because it's another intervention into kind of what's referred to as the competitive market. But we -- even with that, we believe that there is some additional upside from a capacity perspective, capacity pricing perspective.

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

I wanted to just talk through the low growth numbers that you're seeing which is obviously robust compared to the national average. Are there certain areas that stand out as the strongest areas of growth? And do those offer potentially more transmission spend than you've been currently contemplating?

Theo, you want to...

Steven, this is Theo. I guess we talked about that we would probably want to talk, to answer the second part of your question, really more around customer class maybe somewhat. And when we look at residential and commercial, I think for the past few years, we've expected what we saw last year, kind of a dip in growth, that being driven primarily by energy efficiency policies primarily at the federal level, somewhat around -- primarily around lighting. And I think what you're seeing now in 2014 and the first quarter as compared to 2013 is really a return to what we had probably seen on the simple average load growth 2010 through 2012 prior to 2013. So -- and it's something, I mean, we somewhat anticipated post the dip we saw in 2013. When you now talk about industrial and you talk about the industrial renaissance, we talked about fairly extensively, Leo mentioned on this call and we've talked about previously, as that growth shows up and it shows up to the extent that we've embedded it within the context of our guidance numbers and to the extent it shows up even greater, yes, there is the opportunity for additional transmission investment to connect that resources to that demand growth, to that load growth. We have some -- obviously, a transmission bill we have within the context of our current construction plan reflects the expectation we have relative to -- out to the 2.5%, 2.25% sales growth. But to the extent that growth goes beyond that, which, again, given what we're seeing we view as a possibility, there could be transmission to connect those load pockets, and we could do additional transmission spend associated with that.

Stephen, from a transmission point of view, obviously, the way to think about it is, we've got a plan. The construction plan of the $1.7 billion over the next 3-year period, that would include some of the economic development activity we have in our plan for that timeframe, the 2% to 2.25% load growth. The renaissance, the projects, the $65 billion that's been announced that we were talking about, that goes up to 2019, so that's even farther. To the extent that we pick up more, as Theo mentioned, there's an increment that could show up just in the base business. So you've got the current run rate. You got -- if we could outsize the growth on top of that outside growth, we get more -- against the other 2 buckets also, obviously, exists with the -- you look at the FERC Order 1000 issue MEP, MVP projects that's out there as well that we would anticipate participating in it at some level, certainly, within our service territory. And then there's that opportunity outside of it too, which we're certainly going to consider what we do there as well. So there's -- the transmission part of the business is actually more complicated and more interesting because of it given those different buckets that are all pretty robust at this moment. But the normal load growth in and of itself is pretty good based on what we've already got line of sight on. The incremental piece on that could make that even better if were successful in our strategy to attract and serve that load. And then we've got these other 2 buckets that we're evaluating, and certainly, we're going to have to make sure we do everything we can to do the right thing for our customers and work with our regulators on how we would all work through that. But that's an extremely interesting part of the business for us right now that we get to work through.

That's very helpful, and I just had a very quick factual question just on the EWC business. I assume that the forecast still includes the DOE nuclear waste disposal fee. Is that correct?

Yes. Well, Stephen, there's, as you know, the possibility that, that might not be in there. We sort of factored that into our midpoint, $6.15. If it comes in or I should say goes away sometime in June, it would be about $0.08.

Understood. But in the out year EBITDA numbers, you're still assuming that you still have to pay that fee?

That's correct.

At this time, I'll turn things back over to Ms. Paula Waters for any additional or closing remarks.

Thank you, Vicky, 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 6761108. The telephone replay will be available through noon, Central Time on Thursday, May 1, 2014. This concludes our call. Thank you.

Again, that does conclude today's teleconference. Thank you all for joining.