Filed by Entergy Corporation Pursuant to Rule 425

Under the Securities Act of 1933

Subject Company: Entergy Corporation

Commission File No. 001-11299

The following is the transcript of a Nov. 12, 2013 Entergy webcast at the 48th Edison Electric Institute Financial Conference.

Leo Denault - Entergy - Chairman, CEO

I think we’re ready to go ahead and get started. I want to welcome all of you and thank all of you for coming to listen to our presentation. I want to specifically thank you for your patience. I know it’s been a long couple of days for most of you. And to see this many people actually awake is probably a good thing. I appreciate that and hopefully I won’t change that for you going through the story.

First of all, I do have to tell you that some of what I’m going to say includes forward-looking statements, so you should refer to our website and our SEC disclosures for more information on that. And also I’ll mention the ITC transaction. And if you read slide two of the presentation it will give you an indication of where you can go for filings by ITC and by TransCo related to the transaction that we propose to spin and merge our transmission business with ITC.

Now with that important information out of the way, as you all know, this is the business as it sits today. We have a Utility business in the Gulf South, six different jurisdictions or six different companies, five jurisdictions, four states, and a merchant business primarily in the Northeast with primarily merchant nuclear plants.

The business in the South, the Utility business, has a very interesting growth story. And then we’ll talk about what’s going on in the merchant fleet as well, but I think before we get into the details I want to get to the punch line.

The punch line is that we’ve got a significant opportunity in the near term over the next five years or so to really focus on growth within the Gulf South within our Utility business, given the renaissance that we’ve seen in industries and manufacturing that deal with the worldwide differential between oil and natural gas, as well as the gas-on-gas competition domestically versus internationally. And we’ll talk some more about that, but that has the potential to grow the Utility business and our earnings profile there between ’13 and ’16 about 5% to 7%.

We also have the merchant business that’s challenged in the Northeast. And we’ll talk more about that on a plant-by-plant basis, but certainly our attempt for the time being is to optimize that business, individual asset by individual asset. And we’ll go into more detail later in the presentation about that as well, so a growing Utility business, a challenged merchant business that we’re looking to mitigate and eliminate as much risk there as we can.

The business profile as we stand today together supports investment grade credit ratings, which are important to us as well as the dividend that we see in the business today. So those two things are also focuses of ours and we’ll talk about those as we go through the presentation as well.

And should the transaction with ITC close, which we have every intent to continue to push towards that transaction, everything that we’re talking, getting ready to talk about becomes better. So there’s an enhancement to the strategy of everything that we focus on in the Utility as well as the mitigation of risk associated with the merchant business. None of that changes in terms of our focus should we close on ITC or not. It’s just that if we close on ITC most of the things that we’ll talk about turn out to be better for employees, better for the customers, and better for the communities we serve, and certainly better for shareholders as well.

So our mission as we’ve lined it out at the beginning of the year is to create sustainable value for those core key stakeholders. And everything that we’re going to talk about today is geared towards that, creating value for our customers, our owners, the communities we serve and the employees of the Company.

So let’s start with the core of the business, and that’s the Utility. As I mentioned, we’ve got a significant opportunity related to the Utility as it sits today given the nature of these worldwide commodity phenomenons.

Now our service territory just happens to be fortunate enough to be the hotbed of where this kind of activity is getting ready to occur. It starts with low rates. We have some of the most competitive rates in the United States. On a retail basis and if you look at industrial rates it’s even a better picture. We have some of the lowest industrial rates in the country, some of the lowest industrial rates in the southern part of the United States. And that helps facilitate the kind of growth that we’re seeing over the course of the next several years.

And most of what we do has a real push towards trying to maintain this rate advantage because as long as we can maintain this rate advantage we can be constructive in helping our communities attract the kind of economic development that provides jobs for those communities but also provides a significant opportunity for us as we go forward in terms of load growth and investment. So what does all that mean in terms of load growth?

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If we were to just look at Entergy’s service territory and just natural organic economic development and economic growth in that region, we’d see about 1% to 1.25% growth. And included in that is an impact that we’ve seen in recent years of energy efficiency. Energy efficiency has come about in our regions because of programs that we have at some of the utilities because of just the natural inclination of lighting standard changes and things like that that’s going on worldwide, but also we’ve had some other dynamics that are unique to the Entergy service territory that have to do with things like hurricanes Katrina, Rita, Gustav, Ike, Isaac.

I mentioned to somebody earlier today, for example, when you think about appliance upgrades in the City of New Orleans basically every single house has changed their refrigerator out since 2005 because of what’s happened with hurricanes and things like that. Housing stock has improved. There’s been better insulation, better windows, those sorts of things. So we’ve seen some of that impact on the Gulf South, plus we’ve seen what everybody else is seeing as well. Some of it may have actually been a little bit quicker to come in our service territory because of the dynamics of an accelerated change out in appliances and housing stock.

On top of that, because of what’s going on in the Gulf South today as it relates to those worldwide commodity prices phenomenons that I mentioned earlier, we see in terms of economic development showing up in our service territory about another 1% growth. And that is just in things that we’ve already gone out and either signed contracts and agreements, or we’re really close to and we can really expect that that load is going to show up.

So instead of 1% to 1.25%, what we’re seeing right now and what we’re estimating between now and 2016 is roughly to see about 2% to 2.25% load growth. On top of that, if you look at everything that’s been announced in our region and the kinds of load that could show up because of that that’s another 1% potentially.

If you think about all the projects that have been announced to locate between Houston and New Orleans today because of the phenomenon in the gas-to-oil and gas-on-gas competition, it’s about $65 billion worth of investment. With that comes about 2,000 megawatts of load if it were to all show up.

It’s industrial growth. About 40% of our customer base today is already industrial. It’s heavily geared towards refining marketing chemicals, that kind of infrastructure that supports the kind of thing that we’re seeing at the moment in terms of the real renaissance of the region.

And as I mentioned earlier, what we are looking at that creates that phenomenon and the thing that’s going to keep that going has to do with the fact that natural gas prices because of shale prices in the United States are very, very low. Natural gas prices internationally are very high and compete with oil, which is also very high worldwide.

So if you’re a manufacturing facility, if you’re a gas to liquids facility, if you’re a chlor alkali facility, if you’re the kind of industry that utilizes natural gas as an input or can utilize in the case of the gas to liquids facility trying to take natural gas and create a situation where you get other liquids out of it, and you can compete in an oil market, or if you’re a chemical plant that competes worldwide with people who are burning natural gas or oil in other parts of the world, those people are starting to commit real dollars because of this phenomenon right here.

When they see the difference in gas to oil and the forward supported, and they see the gas-on-gas differential worldwide and the forward supported, not only does that put them in a position to want to commit real dollars to the region, but it also gives the ability to hedge some of that if they need to in terms of to an LNG export facility and be able to hedge out through contracts, if you’re a gas-to-liquids facility to be able to hedge out in the markets in the forwards the capital investments that you need to make in our service territory. As I mentioned earlier, about $65 billion worth of capital investment by third parties announced so far in our service territory over the course of the last 12 to 18 months.

With that, as I mentioned also comes about 2,000 megawatts of load that would theoretically show up if all of this was to come to fruition. If all of it was to come to fruition that would be a good thing for the economy because there’s about 29,000 jobs associated with this. So it’s not only important to us, it’s very important to the communities that we serve that this kind of activity continue, a very, very exciting time and a renaissance that we see for us at the moment.

There are a variety of different industries, as we mentioned, over a time period between now and 2018, again in the investments that have been announced to date. They run the risk from steel mills to chlor alkali facilities, gas and liquid facilities, LNG export terminals, all of the things that utilize two important commodities, natural gas and electricity.

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And that rate schedule that I showed earlier in terms of where our rates sit competitively nationwide, but also in the Gulf South and on an industrial basis has a lot to do with the fact that we ourselves are a big natural gas burner in our generating fleet. So the declining price in natural gas has really helped the Utility price structure as well.

So not only does the phenomenon of the gas to oil and gas-on-gas competition work for them on their natural process. Our participation with our rate structure is also driven by natural gas. And so that’s also helping them as an input.

Again this is an artist’s rendering of some things that you may have seen. If you flew United on your way to Orlando you might have picked up the “Hemisphere’s Magazine.” And there’s a 40-page article on the renaissance in Louisiana associated with exactly what I’m talking about here. Again, people have started to commit real dollars to real important big capital projects, all of those capital projects not only big job producers but very, very heavily intense electric users. And that’s the things we’re talking about.

In the New Orleans paper just last week they outlined not only what was happening but where. Each red dot signifies some of the things that were on the previous slide and where they’re located all up and down the Mississippi River corridor. And again there’s an opportunity not only there, but that extends out into Texas as well. And if you think of that Houston ship channel through Port of New Orleans area that’s the hotbed of this kind of activity.

The capital investment profile that we have today based on what we know in the plan and what we see in our outlook, and even some of what we see in terms of this load growth through this renaissance, over the course of the next several years we should be able to meet this growing load with existing resources. We do have a capital plan over the next three years of $5.8 billion. Depreciation is about $3.2 billion.

That lends itself to some pretty decent rate-based growth. If everything that we talked about on the previous slides were to show up, what we would start to see as we get out towards the latter part of this three-year period is potentially incremental cash capital expenditures in transmission, followed by the potential for incremental capital expenditures in generation.

As I said, given the state of the region that we’re in right now and our transition into MISO for the foreseeable future and the plan that we see, and then that 2% to 2.25% growth rate, we can meet that with existing generation resources. Obviously there would be transmission expenditures that would go along to hook those up that may become bigger than the $1.7 billion in transmission that we’ve got in the three-year plan today, but all of that obviously would provide some upside to what we’re seeing right now in that 2% to 2.25% load growth if all those other things show up.

Right now we have a new CCGT under construction at Ninemile which should go into service in early 2015, plus we do have some environmental expenditures. They’re pretty muted as far as we’re concerned because again we’re a big nuclear and natural gas generator, but we do have some coal. So we do have about $400 million of capital expenditures from that, and visibility issues and things like that in the forecast, as well as modifications because of Fukushima and our regulated fleet. And as well we have those kinds of things in the non-regulated fleet in the nuclear plants going forward too.

So we’ve got a great capital expenditure profile at the Utility. Again if we were to look at all of the things that could happen with that $65 billion or if new projects were to be announced that’s just what’s been announced over the course of the last 12 to 18 months, that could change this as we get out to the latter part of that three-year cycle to where we could see additional capital expenditures to meet what those of us in the utility business have long waited for a renaissance in, and that is to build new things for new load, as opposed to what we have seen over recent years is to build new things to replace old things.

There’s a big difference because when you build new things to replace old things or you build new things because it’s an environmental compliance, it’s a reliability need that improves you from three nines to five nines in terms of the reliability of your system, or if it’s security modification, Fukushima cost, et cetera, those are all required, and they’re all necessarily and they’re all good, but to the extent that they do not provide one new megawatt hour of generation or new — one new megawatt hour of load, they do provide one new dollar of rate increases. Without the load growth to cover those that becomes difficult at some point in time. You start to hit a wall. And nobody really wants to get in that situation.

So building new things for new load is really the way we would like to see the business grow. And fortunately for us because we were smart enough to locate our Utility in the Gulf South, we get the opportunity to do just that.

And as far as the generation footprint, we do have a significant number of facilities that are older. Our gas fleet is 40, 50 years old in large part. So we do see the need between now and 2020 to build potentially another 4,500 megawatts of generation. We also see, as I mentioned, some environmental expenditures, transmission expenditures and then the other public policy things.

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The good news for us, if we can experience the kind of load growth that we’re talking about is we get to spread the fixed costs associated with the replacement, the fixed costs associated with environmental, the fixed costs associated with the things going on in the nuclear fleet over a wider range of megawatt hours if we can see that growth and we can meet that in the foreseeable future with the existing resources we have and with the existing resources in MISO.

That helps keep that rate pressure down, gives us some headroom, but when it really kicks in we have to start to make capital investments on top of that to be able to recover that through the regulatory process, give you a feel for exactly where those generation needs are across our system.

We have them across all jurisdictions, certainly primarily in Louisiana, Texas and Arkansas as we look at that 4,500 megawatts of generation that we need, environmental spending again very limited for us because of the small size of the coal fleet relative to the nuclear generation and gas generation we have, but we do have some across the system that we’re going to have to spend going forward as well. I do want to mention another phenomenon that we are experiencing just like other people in the country.

Some people were surprised yesterday when we mentioned the fact that we have a pretty significant penetration of roof-top solar for example in the City of New Orleans. And it has to do with a significant amount of subsidy that is in Louisiana and the way the rules of the game work, which provided a big incentive for people to actually participate in that such that we’ve got a pretty significant penetration of rooftop solar in the New Orleans jurisdiction.

Obviously it’s not a significant number for Entergy overall, but it does give us something to watch and some experience to live with that most people probably wouldn’t expect. We also have energy efficiency and other programs that are run through the regulatory process in other jurisdictions, New Orleans and Arkansas as well, but these are things that we’re watching.

To the extent that rates are competitive, the threat that occurs because of the emerging technologies, whether it’s energy efficiency, demand side management or distributed generation, certainly managing those rate levels through a combination of cost management and load growth is helpful in pushing off the threat that would occur because of the pure economics of any of things, but certainly something that we have to keep an eye on and something that is motivating us to make sure that we continue down that path of cost management and focusing on growing load over the course of the next several years.

From a regulatory standpoint, another piece of the puzzle in terms of how we are planning to take advantage of what’s happening in our region, we’ve had a pretty good record, and our regulators have had good foresight into how we recover dollars in general and particularly as it relates to the generation fleet. In 2012 for example we put $2 billion worth of projects into rate base without general rate cases through really constructive regulatory mechanisms that handle things like the acquisition of power plants in Mississippi and Arkansas, the upgrade of the facility at Grand Gulf or things like that.

We had very good constructive regulatory constructs between us and our regulators that allow us to put those dollars into service and put those to work for our customers at the same point in time that we get recovery without any regulatory lag. That’s been very constructive and that’s the kind of thing that we want to continue to do going forward as we particularly look at the kinds of investments that might need to be made to meet that demand that we see showing up in the Gulf South.

The other thing I mention is reducing costs. We should see a much more efficient and a much lower cost of delivered energy to our customers when we get into MISO. The MISO entry that we’ll get into December 19th that’s going to provide a much bigger footprint, much more generation, and access for our customers.

We see $1.4 billion of savings to our customers over the course of just the next 10 years, again, making sure that the rate path stays low, making sure that our capital investment profile is rational, and making sure that we can compete to bring that load in, but also if we keep our rates low, and we have to make those investments and we go out to the regulators we don’t hit some arbitrary cap that we might be forced to hit just because rates get too high. All of this is very important for us from a competitive and from an earnings standpoint.

The human capital management program that we’ve been talking about this year, another way to do two things. We’re reorganizing the company to meet the needs of the future while we make ourselves more efficient and lower costs going forward as well. It isn’t just a cost management effort.

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It’s a reorganization of the company with an intention to provide better service to our customers both internally and externally, more efficiency, more accuracy and lower costs, but it has to do with things like in some areas like economic development. We haven’t necessarily gone through and said we’re got to make this organization smaller. We’ve said we’ve got to make it more efficient. So we’ve taken different areas of the company that would be responsible for attracting that load, business development, citing economic development, and actually merge those together in a way that can make us better able to seek out and capture what we’re seeing as an opportunity.

In areas like nuclear oversight we’ve actually added people, not subtracted people. We’ve put resources in places where we think we need more activity. At the same point in time while we’re tried to consolidate entities and look at the work that we’re doing and make sure it’s really needed or not, and reorganize the organization so that we can get the spans of control right, get leveling of jobs right, etc. It’s not just about cost. It’s about making ourselves more efficient, more competitive and better able to attract and do the things we need to do into the future.

It doesn’t end at the end of 2013 and into 2014. It’s things like creating a shared services organization where we take end-to-end processes out of the multiple silos that they sit within the company, and again strip those out, make them, those transactions-based entities more cost efficient, more accurate and lower costs going forward as well, just like things like supply chain and others where we’re trying to take those out of the organization and put them into a more efficient structure.

It’s all geared towards keeping costs low, making us more efficient, but preparing us for the needs of the future as well, not just about costs, although there is a significant cost advantage about $200 million to $250 million that we have a good line of sight on that we should see taken out of our cost structure between now and 2016 with the majority of that showing up in 2014.

And a significant amount of that is at the Utility. And at the Utility what that will do is provide us the opportunity not only to earn our rates of return, it will provide us the opportunity again to keep our rates low, to be more competitive and to be able to attract and retain the kinds of loads that we see for us.

Another piece of the puzzle in terms of creating growth is the regulatory process and where we sit. If you look at and where we sit right now in terms of the last 12 months ending in September, certainly we’re earning below our allowed rates of return. The first step in improvement and growth is going to be to get ourselves back into a range of rates of return that we are allowed.

We’re in rate cases with a significant amount of our customer base through 2013 with about 80% of our customer base went through rate hearings and rate cases this year. We’ve gotten through that in Mississippi. We should get an order in Arkansas by the end of this year. And we’re in the process of settlement negotiations with Louisiana to see where that may come out. Once we get through that it will go a significant way towards getting us above this 8.5% range in terms of ROE for the majority of our service territory.

What does this all mean in terms of earnings growth at the Utility? We see 5% to 7% earnings growth between 2013 and 2016. There’s a step change of that because we get from that 8.4% - 8.5% ROE into a more normal range above 10%, between 10% - 10.5% ROE. There’s also load growth that goes through that. Human capital management goes towards that. All of that goes to get us up to that 5% to 7%.

2013 there’s some tax benefits associated with the Utility earnings in that year. One of the things that kinds of mutes that growth to five to seven is when you look out in 2016. And we’re talking about a statutory tax rate.

So there’s a negative in that growth that has to do with tax rates going up. That doesn’t mean we’ve given up on the idea that keeping tax rates low, keeping our tax payments low is a good idea. It’s just at this point we haven’t provided any line of sight to what that might be in terms of levers that we have to pull when we get between 2013 and 2016.

Also again going back to the story line of economic development, what we’re seeing here is predominantly those economic development projects that we’ve got really good line of sight on. We potentially signed a contract with them already, or we’ve got a really, really good line of sight that it’s really going to show up. It doesn’t include about 1,000 to 1,500 megawatts of that load that we haven’t actually seen that kind of line of sight, but it’s been announced and it’s in those red dots you saw on that map page earlier.

So it’s a pretty good story in terms of with load growth, low rates, decent economic development, the ability to keep costs in line and constructive regulation. That provides this opportunity of which we get to springboard, if what we see going forward is more investment in transmission and generation because more of that shows up than what we are looking at right now.

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The ITC transaction just makes all this better. If you like the transmission, the $1.7 billion of transmission infrastructure investment that we’ve got, you’ll like it better if it’s done at ITC. If you think the myriad of economic development opportunities that we have are interesting and could show up in more than $1.7 billion of investment in the transmission system if it’s done at ITC, you’ll like it better.

Our customers will be better off if the ITC transaction occurs because the independent model we truly believe that our customers will see a lower delivered cost of energy because there will be less congestion, higher reliability, access to generation on a regional basis that we ourselves would not necessarily be expected to be looking for, building across the seams between SPP, and MISO and things like that. Those types of activities will provide at a lower delivered cost of energy that will more than overtake the incremental tariff associated with the FERC regulatory construct on the transmission piece, which is the smallest portion of our customer’s bill.

That said, on the shareholder side there is obviously the regulatory construct that provides a greater earnings path for you. So if you like it being done at Entergy you’ll like it better being done at ITC. That said, it’s great at ITC if that happens. It’s not bad if it happens at Entergy.

All that means is Entergy owns the transmission system, the $1.7 billion plus whatever shows up in addition to that is done under the state regulatory construct by us. And you get your value through the Entergy equity as opposed to through ITC. So we’re still committed to trying to get this done, got at a point now where we’re really in the throes of the regulatory process where sometime in the next couple of months we should get some clarity from the regulators as to whether we’re getting a thumbs up or a thumbs down in those jurisdictions.

So let me move quickly on to EWC. EWC is a little bit different story for the exact same reason. Obviously all the benefits that we see for low gas prices at the Utility kind of bites us on this side of the equation. And the merchant business is somewhat challenged for us just like it is for a number of people because of that phenomenon.

Our objective is to optimize this business and mitigate the risk as much as we can from here on out. As always we look at this business and we look at these assets under three scenarios. Does it make sense to hold, and optimize and do the best we can with that asset? Does it make sense to find somebody who can make a better go of it than we can because they have synergies, because they have an operating capability, because it fits into a portfolio, or in the case of some of these assets whether or not it makes sense for us to shut them down?

We’re doing that assessment on a pure economic basis what makes sense in terms of intrinsic value and the option value in each one of those assets. We’ve tried for several years to separate this business from the Utility because we believe that they don’t really match commercially or financially with each other, even though they operate nuclear plants. It would seem like it makes sense, but from a commercial standpoint they are two completely different businesses.

To this point we haven’t been successful and at this point in time it’s very difficult for us to transact around Indian Point. There’s a significant amount of political and regulatory uncertainty around that asset, juxtaposed with a significant amount of value that resides within it because of the size of the unit, the cost structure of the unit, because of the economies of scale, the operating capability of it and the region of the country in which it sits where power prices are reasonably robust.

That is an option that is not only valuable. It’s in the money. 75% of the portfolio value at least resides within Indian Point. Given the fact that we haven’t been able to find a way to transact around it that’s acceptable to us, a counterparty and a myriad of regulatory people and authorities that would have to be involved, we own Indian Point. You own Entergy, you own Indian Point. We’re going to hold and optimize that plant. So the declaration that we have today is Indian Point is on that hold and optimize scenario.

Vermont Yankee is on the other end of the spectrum. We attempted to transact around Vermont Yankee. We’ve attempted to try and mitigate the cost implications of Vermont Yankee. It’s the smallest unit in a tough market and we finally got to the point where the capital and O&M commitments that we had to make to the plant just made it not viable to preserve that option. So we made the decision to shut down Vermont Yankee at the end of this current fuel cycle towards the end of 2014. That is earnings accretive and cash flow accretive to the base plan over the course of the next five years. That’s why we made the decision.

The other assets in the fleet we’re going through the same process because it makes sense to put them on the Indian Point side of the equation. Is there somebody out there that might find that a more attractive asset because it fits into their portfolio, they’re going to have synergies? They may have some cost advantage to us and some other rationale that makes it valuable to them that we could transact. Or do we put it on the spectrum of where we are with Vermont Yankee?

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All the plants are in different markets. All the plants have different characteristics and all the plants will likely come to different solutions, again Indian Point, valuable, great option, most of the value of the portfolio. If you look at Palisades it’s in the worst market actually in MISO. Left alone that would probably be the most challenged facility, but it does have a PPA that supports the cost structure of the plant going forward. So we have until 2022 to preserve that option value that we would see from 2022 and beyond when the contract on that plant runs out.

If you look at the Pilgrim plant there’s a lot of unique characteristics about the New England market. While it’s a tough market today and certainly the plant is a challenged BWR in a tough market, there are some dynamics in New England, both energy and capacity that make that a valuable option going forward. And we need to just continue to monitor and see what we can do with that plant to get the most out of it. And there are some tipping points that may come about as it relates to capacity and markets in the near future to where reserve margins fall. We’ve seen retirements in the New England market like Vermont Yankee that will provide some support for that market. And of course it’s a question of when and whether or not those market dynamics continue to evolve.

The Rhode Island State energy plant it’s a gas plant that we own. It’s valuable in the dispatch of the market and obviously has a little bit different characteristic than the nuclear plants in that it’s able to ramp up, ramp down and follow the market. And it’s obviously based on being gas fired so it doesn’t get out of market wacky one way or the other, but it’s still a valuable asset within that dispatch mix.

And then probably the most challenging of the remaining fleet would be the FitzPatrick plant, Upstate New York. It is bigger than Vermont Yankee. It does have more economies of scale, a better cost structure, etc, but Zone A is a tough market. Upstate New York is tough and we continue to evaluate where we’re going to go with that plant, so again asset by asset decision either some sort of transaction to hold and optimize like we’re going to do with Indian Point, or to go to the other end of the spectrum as a last resort to shut those plants down if it’s the right economic decision.

One of the things we’re doing is to try to help preserve that is to make sure we do whatever we can to help maintain efficient, and reasonable and rational market structures. We’re working through that in both New York and in New England to make sure that we get the rules of the game right, that out of market contracts are handled correctly, that only plants that really can operate are counted as capacity and things like that in both the New England markets and in the New York ISO.

As it relates to Indian Point in terms of the preservation of value there, when we say we’re going to hold and optimize, it’s not just running the plant safely and securely. It’s not just selling the power into the market. It’s not just working on the markets and making sure the Lower Hudson Valley capacity zone gets up and running, and it gets up and running in a rational way.

It’s going through the myriad of regulatory processes that we have to whether it’s water quality, whether it’s CZM, whether it’s the NRC process in making sure that we are diligent about our ability to continue to operate this plant going forward. This plant every day that it runs is a good day. It’s a good day for the customers. It’s a good day for the state. It’s a good day for Entergy and it’s a good day for the owners of the company and its employees as well.

The EBITDA outlook, as I mentioned earlier, for the EWC business is somewhat challenged. You can see a decline. That decline has to do with a lot of things. One it’s the elimination of Vermont Yankee from the mix. While it’s earnings and cash flow positive, obviously the revenues do show up and it’s going to come out of the mix.

We also have declining prices. As our hedges roll off and we get into the forward markets the energy prices do continue to decline. And we do have some drag from Vermont Yankee when we get into the 2015 time frame. You’ve got some one-time cost of severance and litigation keeping CPG processes to get the spent fuel pads and things like that taken care of, as well as a ramp down of costs. You don’t just turn it off and everybody walks away. And you do still have to ramp down the costs until you get into that decommission and that safe store state going forward.

So we do see some declining EBITDA where before it flattened out. Again we’re doing everything we can to improve this. There’s things we need to do with the overhead associated with the company once Vermont Yankee shuts down. There’s nothing in here for that. And certainly we do have a point of view that the power markets are going to come back to some extent, although not significantly enough for example to save something like Vermont Yankee.

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As we kind of sum it all up for the company and what to look at, from a Utility standpoint we think we have a very significant growth story, a very good opportunity, not only with what we’ve got in our current forecast, but what we think could be out there and what’s already been announced or what could be announced over the course of the next several years. That phenomenon is going to continue as long that oil-to-gas ratio and gas-on-gas competition remains.

We’ve got to do our part by having constructive regulatory processes and constructive rate cases. We’ve got to keep our costs low, help us earn our rates of return. We have to make sure that we do all the things we can do to attract that load and to manage the costs of regulatory process to make that happen.

And as you look EWC, we’ve got a number of things that we’ve got to pay attention to, commodity markets, our cost structure, what we do with those facilities, what we do with Lower Hudson Valley capacity zone, what happens in the energy markets in New England, what happens to capacity markets in New England. It’s both our operational activity, but also intervention into the regulatory process to make sure that they get the rules of the game right to be a really constructive market that will actually accomplish the objectives that they really want to accomplish. And that’s to attract enough capacity that the regions actually meet their load.

From a Parent perspective, provided some clarity in terms of those numbers from now out through 2016. Really in the Parent there’s only a couple of items, even though it sometimes seems to be confusing to people. There’s tax benefits that show up from time to time in the Parent. They end up wherever they’re going to end up when we actually had the tax benefits, whether it’s a Utility, the Parent or at EWC.

There’s interest on the Parent debt. And there’s affiliate preferred. The affiliate preferred is associated with securitization that we’ve done post storms. Because of the way we’ve done securitization where the state issues the bonds we have a position that we’ve put in place that has tax advantages that provide lower rates to our customers and higher returns to our shareholders by doing this structure. The preferred itself shows up here and is offset obviously in the utilities. Drew can get into tremendous detail with you on that if you want to talk about it.

Really what’s going to change that number going forward, and when we look between now and 2016, is the combination of interest rates. We’ve got the Parent debt and as interest rates change the interest cost there will change.

If there’s a storm — right now we’ve got securitization going on in ‘14. There will be a partial year and then show up in ‘15 associated with Hurricane Isaac, which we — we’re doing the same Act 55 securitization in Louisiana for Isaac that we did for Katrina, Rita, Gustav and Ike, as well as any tax benefits that may or may not show up that reside at the Parent.

Right now when we talk about the 5% to 7% growth in the Utility and we talk about the $1.05 to the $1.20 range at the Parent, our assumption in 2016 is a statutory tax rate. So as I mentioned earlier, we bounce off of 2013 and ‘14 where there are tax benefits at the Utility, for example. There are none in that 2016 number. So that’s another lever we have to pull just like O&M, HCM, revenues and the like as we look into those years.

The plan itself supports investment grade credit ratings. That’s an important part of the story for us — is to maintain investment grade credit ratings, not only at the utilities, but for the Parent as well, and supports the dividend as we see it right now.

Obviously if we do the ITC transaction there’s a dividend accretion opportunity for shareholders based on the combination of the two dividends. ITC will pay a dividend. Entergy will pay a dividend. If Entergy were to adjust its dividend at some point in time we would anticipate that at the end of the day it would be at least neutral if not positive to you in terms of your ownership of ITC, as well as your ownership of Entergy from that point forward in the combination of those two, even if we adjust the Entergy dividend given the fact that what we’ll be transferring to ITC is part of the Utility, and the Utility is what pays the dividend. So you take those transmission earnings out of our business that could result in the adjustment of our dividend, but in aggregate you’d be better off.

As I mentioned earlier, our mission has been to create sustainable value for the four key stakeholders we have. We believe that the plan that we’ve got in place provides low rates, reliable service to our customers. We believe it provides a great opportunity for our employees in terms of stable, predictable and a challenging employment.

We think that it provides the opportunity for us to be very active in the communities though economic development, philanthropy, et cetera. We obviously believe that it provides an opportunity for growth and a very nice story for all of you as shareholders as well. And the plan itself supports that. And actually we believe we have some opportunity for us to get even above that.

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The last thing I would leave you with is what we’ve been talking about for most of the year. And that is we recognize that as we go down the list of the many things that we have going on, whether it’s MISO, ITC, the system agreement, rate cases with 80% of our customer base, Indian Point, Vermont Yankee, merchant markets, Lower Hudson Valley capacity zone, New England, Vermont, you name it — that there’s a lot going on.

Our objective has been to acknowledge that there’s a lot going on and to make sure that you know that by the time we get to the first part of next year the majority of those items will be resolved. The majority of those items will be behind us. And what we’ll be looking at is growing the Utility business based on this unique economic development opportunity we have in the Gulf South, minimizing the risks we have associated with EWC and optimizing those assets to create as much value as we can.

It really simplifies the story, but it simplifies the story into a path we think going forward is much more growth oriented and a little bit less noise oriented for all of you. And I think that would be appreciated by most people, not only all of you, but all the people back at the Company who are trying to work through all of these items.

And with that, that’s the end of my prepared remarks. I’m told I have no time for questions, but if they’ll give you time I’ll take some. Well, thank you very much. Oh, I’m sorry. Go ahead. Go ahead.

QUESTION AND ANSWER

Unidentified Audience Member

(inaudible question - microphone inaccessible)

Leo Denault - Entergy - Chairman, CEO

Yes, yes. The way we — the question is — I was supposed to wait until you got the mic, but you were so far. I’ll repeat the question. The question is how we got to the 2,000 megawatts of growth. Those $65 billion worth of projects, the estimate of the electricity use of those is about 2,000 megawatts. We don’t have 2,000 of that baked into our forecast into the five to seven or that two to two and a quarter. There could be inside the fence generation associated with that. What we’ve put in our two to two and a quarter is, well, we signed them up.

And so for example we’ve had some customers that are in the ‘we signed them up’ category that came thinking they would cogenerate, but with gas markets where they are with our power, our tariffs where they are, quite honestly, it just didn’t make sense for them to make the investment to cogenerate. So they allowed us to be their supplier. In that other 1,500 megawatt possibility that’s out there, some of it may not show up at all. Some of it may show up and cogenerate.

Our objective would be to make them show up and not cogenerate to the extent that we can make that happen, but it’s really based on the types of — we had a list of what they actually are and we can make an estimate of what kind of electricity you say it would be if it’s an LNG train or if it’s a gas to liquids facility, et cetera.

Unidentified Audience Member

(inaudible question - microphone inaccessible)

Leo Denault - Entergy - Chairman, CEO

Well, our intention would be to work with everybody we can. It’s in everybody’s best interests that this happens, the regulators, the companies, the communities. This has a much broader appeal than just what it does for us — 29,000 jobs associated with that. That’s a big deal.

And so our objective would be to work with the regulators. To the extent we need to do something to make it happen or we need to do something to participate in that so that we can draw it we’re going to do everything we can. And I’m certain

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they will too because it means jobs. It means economic development and stability, the tax base, all the things that you like, about $65 billion worth of new industrial investment in that region, which is a good region. This region is set up for industrial investment. So — anything else?

Well thank you very much. I really appreciate it.

Additional Information and Where to Find It

ITC filed a registration statement on Form S-4 (Registration No. 333-184073) with the SEC registering the offer and sale of shares of ITC common stock to be issued to Entergy shareholders in connection with the proposed transactions. This registration statement was declared effective by the SEC on Feb. 25, 2013. ITC is also expected to file a post-effective amendment to the above registration statement. ITC shareholders are urged to read the prospectus included in the ITC registration statement (and the post-effective amendment to the ITC registration statement, when available) and any other relevant documents because they contain important information about TransCo and the proposed transactions. In addition, on July 24, 2013, Mid South TransCo LLC (“TransCo”) filed a registration statement on Form S-4/S-1 (Registration No. 333-190094) with the SEC registering the offer and sale of TransCo common units to be issued to Entergy shareholders in connection with the proposed transactions. This registration statement includes a prospectus of TransCo related to the proposed transactions. Entergy will file a tender offer statement on Schedule TO with the SEC related to the exchange of shares of Entergy common stock for the TransCo common units. Entergy shareholders are urged to read the prospectuses included in the ITC registration statement (and the post-effective amendment to the ITC registration statement, when available), the TransCo registration statement, the tender offer statement on Schedule TO (when available) and any other relevant documents because they contain important information about ITC, TransCo and the proposed transactions. The registration statements, prospectuses, tender offer statement and other documents relating 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 to Entergy Corporation, Investor Relations, P.O. Box 61000, New Orleans, LA 70161 or by calling Entergy’s Investor Relations information line at 1-888-ENTERGY (368-3749), or from ITC upon written request to ITC Holdings Corp., Investor Relations, 27175 Energy Way, Novi, MI 48377 or by calling 248-946-3000.

Entergy Forward-Looking Information

In this communication, and from time to time, Entergy Corporation makes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in this communication and in: (i) Entergy’s most recent Annual Report on Form 10-K, any subsequent Quarterly Reports on Form 10-Q and (ii) Entergy’s other reports and filings made under the Securities Exchange Act of 1934; (b) uncertainties associated with rate proceedings, formula rate plans and other cost recovery mechanisms; (c) uncertainties associated with efforts to remediate the effects of major storms and recover related restoration costs; (d) nuclear plant relicensing, operating and regulatory risks, including any changes resulting from the nuclear crisis in Japan following its catastrophic earthquake and tsunami; (e) legislative and regulatory actions and risks and uncertainties associated with claims or litigation by or against Entergy and its subsidiaries; (f) conditions in commodity and capital markets during the periods covered by the forward-looking statements, in addition to other factors described elsewhere in this communication and subsequent securities filings and (g) risks inherent in the proposed spin-off and subsequent merger of Entergy’s electric transmission business with a subsidiary of ITC Holdings Corp. Entergy cannot provide any assurances that the spin-off and merger transaction will be completed and cannot give any assurance as to the terms on which such transaction will be consummated. The spin-off and merger transaction is subject to certain conditions precedent, including regulatory approvals and the availability of financing.

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