Michele Lopiccolo – VP, IR Wayne Leonard – Chairman and CEO Leo Denault – EVP and CFO Mark Savoff – EVP, Operations Curt Hebert – EVP, External Affairs

Reza Hatefi – Decade Capital Paul Patterson – Glenrock Associates Dan Eggers – Credit Suisse Michael Lapides – Goldman Sachs Marc DeCroisset – FBR Jonathan Arnold – Deutsche Bank Daniele Seitz – Dudack Research

Good day everyone and welcome to the Entergy Corporation first quarter 2010 earnings conference call. Today's call is being recorded. At this time, for opening comments and introductions, I would like to turn the call over to Michele Lopiccolo of Investor Relations. Please go ahead.

Good morning and thank you for joining us. We'll begin this morning with comments from our Chairman and CEO, Wayne Leonard and then Leo Denault, our CFO will review results. In an effort to accommodate everyone with questions this morning, we request that each person ask no more than two questions. After the Q&A session, I will close with the applicable legal statements. Wayne?

Good morning. As we spoke with you last earlier this month, I'll try to be brief particularly as it pertains to matters in New York – at doctor's orders, not Michele's. Today, some 35 days after the decision, we have yet to receive an order from the New York Public Service Commission. Since the ability to appeal or take legal out action doesn't start until we actually receive an order, any legal recourse is automatically preserved. Consistent with our previously stated intent, we have now begun the process of unwinding the business infrastructure associated with Enexus and EquaGen. Under the direction of Rick Smith and the corporate steering committee, the project management office is aggressively eliminating duplicate functions and infrastructure created for the two new businesses that is no longer needed, while preserving options to restructure the business with consideration to everything we learned during the spin-off process. How the marketplace has changed and what our next step might be to capture the unrealized value of this business. Turning to the utility, during the quarter progress continued on. (inaudible) always active regulatory agenda. With the 2010 hurricane season rapidly approaching, resolution of regulatory proceedings associated with Hurricanes Gustav and Ike from 2008 was essential for Entergy Gulf States Louisiana and Entergy Louisiana. Earlier this month, Louisiana's Public Service Commission approved uncontested stipulated settlements resolving all issues pertaining to storm restoration recovery, the establishment of storm reserves and the plan for financing those costs using the same financing structure used for Katrina and Rita. That is Act 55 of the Louisiana legislature and through the Louisiana Utilities and Restoration Corporation. Efforts are now focused on completing the financing for the balance of the system restoration costs and storm reserves, which is targeted to occur before the peak of the 2010 storm season. Due to the constructive actions of the LPSC both Entergy Gulf States Louisiana and Entergy Louisiana will have as solid a financial standing as reasonably possible to face storms with $290 million of dedicated storm cash reserves in the bank after financing the curves. Total financing proceeds are roughly $700 million. Just as 2005 repeatedly shattered numerous records with 28 tropical and subtropical storms of which a record 15 became hurricanes, 2009 was one of the quietest on record. With nine tropical storms, three becoming hurricanes and only one tropical storm Claudette making landfall in the United States. Nonetheless with a service territory that stretches north and south just over 500 miles, we always seem to have the opportunity to prove our planning and execution process. We prepare for the worst and as a direct result of continuous process improvement, customers can count on Entergy to be there when it matters most. In fact, our pre-hurricane season planning storm drill in 2008 has uncanny similarity to Hurricanes Gustav and Ike. The storm drill scenario predicted a Labor Day category four hurricane strike west of New Orleans followed seven days later by a second strike. In fact, Hurricane Gustav was a Labor Day category two plus hurricane strike Southwest of New Orleans, followed 12 days later by Hurricane Ike. Among other things, Entergy's drill efforts included evacuation of New Orleans, pressure restore major refineries, transition grade instability and idling of generation all of which had unfolded during Gustav and Ike. Likewise, Entergy prepared for events very similar to what unfolded for Hurricanes Katrina and Rita, including the flooding of New Orleans of about 20 feet in our drill event. This year, Entergy was recognized once again with the Edison Electric Institute recovery award for its work restoring power following the destructive ice storm in Arkansas last year. Entergy is the only company to be honored every year since the inception of the EEI recognition, having earned the EEI recovery and/or EEI assistance awards for 12 consecutive years. And you thought all we did was run nuclear plants and sit in regulatory hearings. At least those things seem to dominate our conversations and for good reason. They have a big impact on whether we earn a fair return or not. In fact as a utility, the able to earn mid point or allow returns across all jurisdictions may be the most significant thing we need to do to enhance the utility's operating company's financial prospects and efforts to do so continue during the quarter. In Arkansas remaining testimony was filed in the Entergy Arkansas rate case. The LPSC staff position currently stands at a $49 million rate increase, reflecting an authorized 10.1% return on equity and including an annual revenue requirement of $10 million for the 2009 ice storm. While a clear improvement over the last rate case, we believe the staff position fails to meet the minimum test of the law, that the company has a reasonable opportunity to earn returns consistent with investments of equal revs during the period rates will be in effect. You recall that in the last rate case, we were authorized a 9.9% ROE that actually had the ability to only earn something in the single digits and in many cases below 5%. This acquisition compares to the $168 million rate increase sought by Entergy Arkansas excluding ice storm recovery. Further the LPSC staff summarily recommended that the proposed formula rate plan be rejected. However, in the event it was approved, staff believed Entergy Arkansas' ROE should be reduced further a 9.6%, a return to the absolute bottom of the industry for a vertically integrated utility. The commission has repeatedly expressed its interest in innovative rate making. I guess the staff took that to mean something different than we did. Let's be clear, you cannot have it both ways. Entergy Arkansas is at a crossroads. In 2005, Entergy Arkansas provided its notice that it was exiting the system agreement and that day is rapidly approaching for clearing the path for Entergy Arkansas to exit, without any continuing obligations or fees on the part of Entergy Arkansas or the system. In that regard, in the midst of a critical rate case for Entergy Arkansas's financial viability, the LPSC initiated a Show Cause Order pertaining to the system agreement and the future operation and control of Entergy Arkansas' generation transmission assets. Practically on the basis of the current record and at preceding, we could easily conclude the proceeding is about why Entergy Arkansas should even consider a successor arrangement to the current agreement, understanding that FERC has ordered Entergy to pursue consideration of a successor arrangement. In fact, just a couple of years ago, the LPSC said itself that it wanted Entergy Arkansas to proceed expeditiously with the development of a new acceptable system agreement and ordered Entergy Arkansas to file monthly reports detailing progress toward the development and finalization of a new system agreement. Much like in New York, where one branch of government has said Indian Point is too big to fail, another branch wants to shut the plant down if it cannot build cooling towers, which most likely they can't, because most likely they can't get the permits. In 2013, Entergy Arkansas is going to leave the system agreement. While, it is the primary opinion of the LPSC is establishing Entergy Arkansas as a stand alone utility it may well be the best path out of the current unacceptable regulatory environment resulting from litigation surrounding the Entergy system agreement. The LPSC staff's position is inconsistent with the necessity of ensure that Entergy Arkansas has the financial wherewithal to do exactly what the commission seems to believe is in the best interest of our Arkansas customers. Entergy Arkansas must be able to invest in the business and must be able to operate and standalone. And that's certainly true if they also want to join SPP. Like I said, you can't have it both ways. Nonetheless, after considering the system agreement matter further in early April, Entergy Arkansas and the Entergy Corporation and Entergy operating companies all of them determined in connection with our decision making process, that it is appropriate to agree and commit that no Entergy operating company will enter voluntarily into successor arrangements with the other Entergy operating companies if its regulator finds successor arrangements are not in the public interest of that jurisdiction or that state. On a more constructive front, Entergy Texas was encouraged by the administrative law judge's action to issue an order approving the unanimous settlement regarding some key preliminary matters in the rate case. Specifically, the settlement authorizes an interim rate increase of $17.5 million to begin on May 1, 2010. The settlement also established the rate case schedule, calling for a hearing in July 2010 with a final award to be issued November 1 and more importantly, for permanent rates to take effect back to service rendered and after September 13. In Mississippi, a third fuel law undertaken at the request of the commission once again gave Entergy Mississippi a good report. Let me rephrase that, it gave Entergy Mississippi a report card that any parent would be proud of. On March 30, the McFadden Consulting Group, a Colorado firm with extensive utility auditing experience, covering more than 40 utilities in 15 states presented their report on the management review of Entergy Mississippi's fuel practices and procedures for the two year period October 2007 through September 2009. In the report, McFadden indicated that the fuel and purchase power costs for Mississippi are reasonable and at the lowest cost possible in the operations and design of the Entergy system. More specifically, the McFadden report states that the resulting Entergy RSP process are extensive, well structured and transparent to ensure proper consideration of market resource options. Further McFadden believes Entergy's Mississippi's transmission system is quite robust and adequate to meet current and future needs. Put simply, the system is operated in the best interest of Entergy Mississippi's customers. Further, during the quarter, the Mississippi Public Service Commission approved modification to Entergy's Mississippi's formula rate panel, including, among others aligning it more closely with the other RFPs in Mississippi, eliminating the current $14.5 million our revenue adjustment limit and increasing the 2% of revenue limits to 4%. I think I said RFP, and I meant FRP as I can see I confused you. On March 15, Entergy Mississippi filed its first evaluation under its new FRP for the 2009 test year. The filing reflected a 10.66% ROE. By contrast the Mississippi's standard offers a reasonable opportunity to earn returns to administer with other investment opportunities all of you have. Further in Mississippi the calculated FRP midpoint of 11.92% also reflects the benefit of a 76 basis point performance incentive. The FRP calls for new rates to be implemented in the June billing cycle subject to review and final approval by the Mississippi Public Service Commission. All of the Louisiana utility companies will file formula rate plans in May, with Entergy Louisiana first by May 15 followed by Entergy Gulf States Louisiana and Entergy New Orleans by the end of the month. On a related note, earlier this month, the Louisiana Public Service Commission accepted the joint report of the LPSC staff and Entergy Louisiana indicating an agreement to implement a modest rate reduction and refund totaling less than $225,000 for the 2008 test year formula rate plan filing made late last fall. At Entergy Nuclear, the fleet continued its outstanding performance running at approximately a 94% capacity factor in the first quarter, including 22 days associated with Indian Point 2's refueling outage. Specifically in New York, where our nuclear plants had been singled out as quote – too big to fail, Indian Point 2 was online 99.1% of the time before coming down for its refueling outage beginning in the first quarter. That was a generation record for Indian Point 2. Just as an anecdote, incremental output from the Indian Point energy center as a result of operational improvements under Entergy Nuclear ownership has covered half of the low growth since 1995 in the Hudson Valley and New York City. Meanwhile Fitzpatrick continues its longest continuous run ever, consistent with the superior track record we've delivered since acquiring both Indian Point and Fitzpatrick. In Vermont, where there have been various calls to close Vermont Yankee due to its age and design, the plant completed 532 days of continuous operation before it was taken offline on April 24 to begin its 28 refueling outage, the second longest run in its history. The longest run in its history ended in 2007, following 547 days of continuous operations. And Vermont Yankee remains one of the few liquid discharge plants in the country. Zero liquid discharges, that didn't sound right, did it? Zero liquid discharge plants. To put this in context, Vermont Yankee has had only one unplanned shutdown during the last three operating cycles. With an operating cycle of 18 months that's one unplanned shutdown in four and a half years. Likewise, Pilgrim remains online at nearly 350 consecutive days of safe continuous power operations since the last fueling outage performed in May 2009. And in fact, set a station capacity factor record in 2009 for a year with a refueling outage. Rounding out the fleet, our most recently acquired plant Palisades continues at over 360 days of uninterrupted power operation since returning to service from its last refueling outage in May 2009. It's notable that Palisades completed 2009 with the best electric generation production ever in the plant's history in a refueling outage year. In fact, Palisades generated the most electricity in the past three years of Entergy ownership than in any other three-year period in the plant's entire history. Before turning it over to Leo, I'd like to close by saying we hope to see you in New Orleans exactly one year from today when we will host our next analyst conference. A pre-conference event will take place Thursday evening followed by the conference itself on Friday. While, we will keep you updated over the next year, we intend to explore in far more depth how we will continue to seize opportunities in our utility business and manage the valuable option you own in the non-utility nuclear business. We will host the event at one of the south's grand hotels recently brought back to its past grandeur following an extensive renovation by the Waldorf Astoria, including the legendary Blue Room. The Roosevelt Hotel was a revolving door of the time's most famous names, like Ray Charles, Jack Benny and Bob Hope. The hotel is as much a part of Louisiana legend as is Huey Long, Louie Armstrong or even Hurricane Katrina. We invite you to come and enjoy and be part of the legend that continues to be written today at the Roosevelt. With any luck it may be a super natural experience for somebody. Regardless, it's coincident with the first weekend of Jazz Fest 2011 and outside of Super Bowl 2010 – we're still talking about that down here – you just can't beat that. Details will be forthcoming and we'll remind you frequently to reserve your flights early Jazz Fest continues to draw record crowds every year in New Orleans. Now let me turn the call over to Leo.

Thank you, Wayne. And good morning, everyone. In my remarks today, I will cover quarterly financial results and cash performance followed by our 2010 earnings guidance. And then close with a review of our current longer term financial outlook. Starting with our financial results on slide two, first quarter 2010 earnings were higher than one year ago at both the utility and parent, while they were lower at Entergy Nuclear. Current quarter earnings include a decretion from share repurchases executed in 2009. On an as-reported basis, quarter-over-quarter earnings were down due to the previously announced charge related to the business unwind of Enexus and EquaGen. This reflects the initial charge to write off capitalized costs and certain other costs in the first quarter of 2010, as well as the spin-off dis-synergies and the expenses for outside services to pursue the spin that you've seen in prior quarters. As Wayne said earlier, we have already begun to take the steps necessary for unwinding these businesses to eliminate spin-off dis-synergies as soon as possible. Excluding these special items related to the spin operational earnings were up by 3% compared to the first quarter of 2009. Operational results for the first quarter were better than originally projected due primarily to strong utility sales, which offset the lower results at Entergy Nuclear. Sales increased across all customer classes and included the effect of significantly colder weather. Absent weather, sales were about the level we projected for the quarter. And although, the lower price – power pricing weighed on the non-utility nuclear segment, the fleet once again delivered a great quarter of operational performance, as Wayne just reviewed. Slide three provides more detail on the factors that drove the quarter-on-quarter results. First, that the utility higher net revenue was the primary factor driving the quarterly earnings increase. As you have probably already observed in table four of our investor release, overall utility retail sales grew by 11.7% including over 22% on residential sales. The weather this past quarter ranked as the second coldest in Louisiana and the third coldest in Mississippi in 116 years with Texas and Arkansas not far behind ranking around the top ten coldest of record for January through March. On a weather adjusted basis, utility sales trends continue to provide evidence that an economic recovery is underway in our service territory. Slide four illustrates this point, building on a chart we first showed you on last quarter's earnings call. As a reminder, this chart plots month by month the changing cumulative retail sales for a three month period versus the same three months in the prior year. After excluding the effects of weather and the 2008 hurricanes a trend of improving economic activity in our service territory clearly emerges for all customer classes. For the industrial segment, the blue line sales continue to steadily rebound from the lows experienced in the first half of last year. Industrial sales ended the current quarter with a 7.3% growth rate versus the first quarter of 2009. In contrast, industrial sales were down by 13.2% in the first quarter of last year. Small, midsize and large industrial customers contributed to this growth in 2010. Although overall our industrial sales were strong, weak fundamentals presented opportunities for refineries to take outages to catch up on maintenance. Also the quarterly increase in net revenue from higher industrial sales volume was tempered somewhat by the price effect associated with demand charges that as you'll recall had offset the negative impact of last year's lower volumes. As a final note, FRP rate actions from 2009 at Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Mississippi also contributed to the quarterly variance. Turning back to slide three, partially offsetting the increase in net revenue for the current quarter was higher operation and maintenance expenses and an increase in interest expense from higher debt balances mainly in Entergy Texas and Entergy Louisiana. Moving on to Entergy Nuclear, the quarter-over-quarter decline in operational earnings was due primarily to three factors – lower net revenue on lower energy pricing for sales on both contracted and merchant positions, higher non-fuel operation and maintenance expenses and the effect of a change in tax law due to the recently enacted federal healthcare legislation. As a reminder, we consider effects of changes in tax law as part of our operational results. Higher other income associated with decommissioning trust was partially offsetting given the absence of an impairment on these trust that was recorded in the first quarter of 2009 and higher investment earnings resulting from normal sales of securities held in the trusts as well as rebalancing of the portfolio. Finally, parent and other results improved due primarily to lower interest expense on lower parent debt outstanding. Beginning in 2010, we've begun to report parent and other including the non-nuclear wholesale assets business separately from utility results. Skipping to slide five, Entergy's operating cash flow performance for the first quarter of 2010 reflected an increase of nearly $300 million over the first quarter of last year. The net increase in OC up was driven mainly by three factors, all at the utility. The absence of storm spending that occurred in the first quarter of 2009, higher net revenues on strong quarterly sales, partially offset by lower deferred fuel collections. Slide six details our current 2010 earnings guidance, which ranges from $5.95 to $6.80 per share on an as reported basis and $6.40 to $7.20 per share on an operational basis. The as-reported guidance range was updated earlier this month to reflect the total potential charge for the business unwind of Enexus and EquaGen which will be classified as a special item. The 2010 operational earnings guidance range which is based on the current business structure is not change from what we originally provided last fall. As usual some things have gone for us like utility sales and others have gone against us since we set the earnings guidance in October of 2009. Obviously, pricing on Entergy's Nuclear unsold position is one of those things in the second category, where current power prices for the full year of 2010 have averaged around $16 per megawatt hour below the level assumed in guidance. In addition, there are other key factors incorporated into the 2010 guidance range that have yet to unfold, including rate actions and share repurchases. The comment about share repurchases – each quarter at this time, we provide an update on the progress, if any under our share repurchase programs in the prior three months. As you may have noted we did not make any share repurchases under the $750 million board authorization during the first quarter of 2010. Decisions on whether to buyback stock were made based on a number of factors including current business conditions, our liquidity and financial flexibility to quickly respond to changing conditions and our point of view on the value of our stock. As we've clearly demonstrated before, we can implement our share repurchase programs quickly once we've satisfied all of our requirements to do so. For example, in the third quarter of 2009, we repurchased roughly $600 million worth of shares to close out the previous authorizations at that time. One last point before moving on relates to the quarterly buildup of 2010 earnings, as discussed on slide seven. Factors to be considered in developing quarterly estimates for 2010 include – at the utility, the timing of potential rate actions at Entergy Nuclear, the number and timing of refueling outages in 2010 versus 2009 and the decommissioning impairments taken in the first half of last year, the timing of decretion from past to potential future share repurchases and the fact that tax items are lumpy by nature. Looking beyond 2010, Entergy's current long-term financial outlook is summarized on slide eight. This outlook encompasses three broad inter related categories earnings, capital deployment and credit quality. Over the next five years, we believe the utility has opportunities to deliver compound average annual net income growth of 5 to 6% per year. Drivers include sales growth, improving ROEs consistent with earning at our authorized levels and making the productive investments that benefit customers through our portfolio transformation strategy, including generation and transmission investments. At the same time, we believe Entergy Nuclear represents a valuable option given its low cost base load clean nuclear fleet located in attractive power markets. At Entergy Nuclear, the price of our products – both energy and capacity is the fundamental driver outside of our operational side of the business where our superior operational track record is the bedrock foundation. The chart on slide nine provides daily forward energy prices for 2010 through 2013 since January of 2008, which as you can see have exhibited significant volatility. Slide 10 shows the projected average portfolio prices for 2010 through 2014 on just one day April 5, the day we announced the Enexus unwind. At those forward power prices, the long-term outlook for adjusted EBITDA which showed a decline compared to 2010, the intrinsic value of the option. However the option premium is quite valuable. The option value derives from the potential future effects of the economic rebound, existing and new environmental legislation and/or regulation that could lead to an expansion of market heat rates, higher capacity prices and/or higher natural prices over the longer term. In closing, we believe that Entergy combines a competitive utility investment opportunity plus a valuable option in its one of a kind non-utility nuclear fleet. Despite an increasing investment outlook at the utility and depressed commodity prices at Entergy Nuclear, we continue to see opportunities to increase the return of cash to our owners. A second quarter dividend increase to $3.32 per share on an annual basis and a $750 million stock buyback program are just the most recent actions. Even in today's business environment and under Entergy's current structure we forecast that the combination of dividends and/or share repurchases could total as much as $5 billion over the next five years, absent other attractive investment opportunities. We aspire to fund our capital investment requirements without issuing traditional common equity. We can assure you that we will address the risks and the opportunities today and in the future in the same disciplined manner, based on an analytically based point of view but with the same attention to liquidity and credit quality that we have always done in order to create sustainable value for our stakeholders. And now the Entergy senior team is available for your questions.

(Operator Instructions) Our first question is from Reza Hatefi from Decade Capital. Reza Hatefi – Decade Capital: Thank you. I was reading in your 10-K that just came out and I guess, in the tax footnotes there's a section talking about you guys receiving about $3 billion of cash benefits over the next six years. Is that – does that come evenly over the next six years or is that lumpy or how does that exactly work?

Reza, utilization of the NOL is based on a variety of factors. One is taxable income over that time period, so it's going to be dependent upon what cash taxes we would ordinarily be looking at based on the net income to taxable income over that period. Also we utilized it effectively based on, excuse me, deposits against it, alternative minimum tax things like that. So under normal circumstances, that's – with normal income, no hurricanes, no significant events kind of six-year time frame based on what we would be looking at for net income is probably the best way to estimate that. Reza Hatefi – Decade Capital: Okay. Okay. Great. Thank you very much.

Moving on, we'll take a question from Paul Patterson from Glenrock Associates. Paul Patterson – Glenrock Associates: Just to follow-up on that. Does that $3 billion include the $5.7 billion that you guys had elected in the fourth quarter under the Section 263A?

Yes. It does. Paul Patterson – Glenrock Associates: Okay. And do we have to wait for the IRS to approve that application or is that sort of a done deal?

Well, we took the deduction on our tax return. As far as a done deal, things that happen in the process you go through from the time you take a deduction to the time it's fully resolved with the IRS, Paul, as you know can go on for a number of years. Typically, it's going to be several years before that year comes under audit and then there's going to be a determination of where the IRS and the company think it would go and then it would be ongoing issues that we have that could stretch it out anywhere from five to ten years. Typically you don't resolve the years in audit for seven to ten years after you've filed that return. So a done deal is a long-term process. The way those work is you take a tax deduction, you have a case – that obviously we believe it's a good deduction and we'll deposit against that, we reserve against those on our earnings going forward and it will get resolved in due course as we work through the process with service. Paul Patterson – Glenrock Associates: Okay. Sure. And that's included in the $5 billion capital redeployment numbers that you guys gave as well or is that in addition to it?

Yeah. That net of deposits and the like. And realize these are timing differences. Paul Patterson – Glenrock Associates: Okay.

So… Paul Patterson – Glenrock Associates: And then just finally the nuclear decommissioning benefit, I guess sort of that's part of the other income benefit that I guess you guys are seeing in the nuclear business. I wasn't sure exactly – was that about $0.10? I wasn't – I couldn't completely figure it out in the release, I wasn't quick enough I guess.

Versus last year, that's about right, yeah. Paul Patterson – Glenrock Associates: Okay. And that's part of the $0.20 that we're seeing going forward? Is that part of the other income benefit?

I'm sorry, the... Paul Patterson – Glenrock Associates: Well, there's in other income in 2010's guidance, you guys have a $0.20 operational benefit associated with other income. How much of that is I guess – could you just break that out a little bit?

Yeah. That's part of it and that includes obviously the benefit of vis-a-vis last year where we actually had $0.24 of impairment to (inaudible) the decommissioning trusts as well. Paul Patterson – Glenrock Associates: Okay. And the tax thing that – the healthcare tax, is that a one timer?

Yes. Paul Patterson – Glenrock Associates: Okay. Thanks so much.

Moving on, we'll take our next question from Dan Eggers from Credit Suisse. Dan Eggers – Credit Suisse: Hi, good morning. Just a clarification question on the $5 billion of cash available for redeployment to shareholders, that is based on kind of some sort of mark-to-market expectations around nuclear earnings contributions and then also sustaining the 5 to 6% utility growth?

That's correct. Dan Eggers – Credit Suisse: Okay. So if utility were – if you were to think about redeploying capital elsewhere, it would be either buying generation assets or the utility spending more capital and what would be necessary to support 5 to 6%?

I'm sorry. I didn't quite get the last part, David, but yeah. If the cash would be available if we – if things turned out the way we have them – if we invest more in generation or invest more in the utility than what we have in the plan, certainly that would utilize some of that $5 billion, but the $5 billion is an outgrowth of the 5 to 6% if that's what your last. Dan Eggers – Credit Suisse: Okay. And I guess is do you have one other question, it's still too early, because you're waiting on the order, but as it relates to New York right now. We saw the commissioners recently in a forum and they were saying the generation assets in their mind are still regulated assets. They've been lightly regulated but they could become more regulated. How do you guys see that interplay working and is there some sort of legal standard rationally that you can challenge as far as their insertion into the business?

I will say we disagree with that. And there are many legal standards that we will challenge that under – that's their point of view. Dan Eggers – Credit Suisse: Okay. Thank you.

Our next question comes from Michael Lapides from Goldman Sachs. Michael Lapides – Goldman Sachs: Hi, guys. Two questions. One, can you give an update on – at the Louisiana subsidiary, the RSP process and potentially looking at self-billed options. And then two at Nuclear, can you talk now that you're not like likely spinning off those assets, whether that's having any impact on your views about hedging going forward over the next three to four years, especially with power prices as low as they are?

Michael, it's Leo. I'll start with hedging and then and then Gary can handle the Louisiana FRP. As far as hedging goes we – as part of Entergy, we haven't changed the hedging standards or the hedging limits around the nuclear business. And we never did change them specifically to match what the Enexus hedging policies may have been. We had a view of what the hedging standards with limit would be given the different financial policies and dividend profile and balance sheet and liquidities on Enexus. But we didn't institute that as part of Entergy. As part of Entergy, we have continued to manage those assets from a risk management perspective – the same as we always have. With just the acknowledgement that we tried not to lock ourselves into something that would prohibit executing on the Enexus point of view and the Enexus risk limits going forward. And so it hasn't changed and now it won't change versus what we've done in the past. Market activity could dictate changes in our limits. Our point of view could dictate selling more than the limits would say or less than the limits would say, based on the point of view that matches up to not only what's going on in the market. But then also keeping in mind that we still own some stilly subsidiaries, we still pay a dividend. We still have liquidities on both sides of the business. So the things that would change it are the same things that would have in the past. But we haven't made any changes prior to now and we aren't planning on any big changes right now. Michael Lapides – Goldman Sachs: Okay. And on the utility side, in terms of self-build options and meeting the gap which we – the couple of gigawatt gap between what you need to serve your lists?

Mark Savoff will answer that.

Okay. Thanks. Right now, we have one RFP that's in process. That's the 2009 summer RFP. We're looking for 1000 megawatts of longer term resources – longer term being greater than five years and we expect that to go into production – those resources to go into production in the summer of 2011. We're also looking for 550 megawatts of so megawatts combined cycle capacity in the New Orleans area to go online in 2015. We've already reviewed all of the submittals. We're going to issue the preliminary notifications in July and we expect to strike on definitive agreements by the fourth quarter – by December of this year. That will give us the capacity and generation that we need moving forward. Michael Lapides – Goldman Sachs: Do those RFPs consider the combination of self-build or asset purchase into rate base or do either of them exclude that option?

No. They have. They would be – we have a self-build option that's included in there as well as power purchases and potential asset purchases. Michael Lapides – Goldman Sachs: Got it. Leo, just on the hedging piece, you guys have very consistently over the last 12 years stated your points of view and acted on them. Just curious, when you look at power prices in the northeast and really the influx of a lot of new natural gas in the northeast, are power prices dramatically different in the forward markets from your point of view?

Well, there's a lot of things that can move power prices other than just the price of gas. Certainly things like the Marcellus shale and other (inaudible) terminals and the like particularly with shale gas – obviously is having a big impact on the price of power in the near-term. And the basis differentials between the hub and the northeast have changed significantly because of that. But the other things that are going to have impact on the northeast particularly as it relates to heat rate. I think those have a lot of issues that just potentially haven't been built into the market. Whether it's existing environmental regulations and legislation on existing things, like mercury and SOx and NOx or whether it's CO2. Also if you look at what's gone on with the demand side management in those regions. There's a significant amount of demand side management that's projected to show up in both New England and in New York as well as thousands of megawatts of wind development, of which not a lot of it is there yet and we're seeing some headwinds against some of that. So really the gas price side of it is one that's difficult to predict – difficult to predict where it's going to happen with shale, difficult to predict what the marginal cost of that's going to be. But I think there is a lot of people looking at that and the market has a lot of that information built into it. I think where you're going to find most of the information lacking in the market and where we'd probably be more bullish than on gas is on the heat rate side of the equation as it relates to what's going to happen with wind, what's going to happen transmission, what's going to happen with demand side programs, what's going to happen with coal retirements and what's going to happen in nonpayment areas. Michael Lapides – Goldman Sachs: Okay. Thank you.

Our next question today is from Marc DeCroisset from FBR. Marc DeCroisset – FBR: Thank you. Just a quick follow-up on the tax question. You mentioned in the press release that there was a tax law. You mentioned the tax law associated with the recently enacted federal healthcare legislation. Can you expand on the impact it had on you? And it sounds like it had an impact on the merchant utility, but not on the regulated utilities, is that correct?

That's correct, Marc. And it's – there's – in the regulated world to set up the – a regulatory asset associated with the recovery of the change in the tax law. So the fact that it's no longer a tax benefit associated with the Medicare Part D. We'll be able to recover that through rates in the normal course so that is set up as regulatory asset. Given that we're not rate regulated on the merchant side of the business, we don't have that capability. So we had about a $16 million charge. Not quite the $1 billion that AT&T was looking at but it's the same issue. Marc DeCroisset – FBR: When you booked that contract expense or however it is you did it. Did you have to approach regulators to get approval for that?

No. It's a normal course expense and it will get recovered in normal course rate making going forward. Marc DeCroisset – FBR: Wonderful. Thank you very much.

(Operator Instructions) We'll take our next question from Jonathan Arnold from Deutsche Bank. Jonathan Arnold – Deutsche Bank: Hey, good morning.

Good morning, Jonathan. Jonathan Arnold – Deutsche Bank: A quick question. If you look at yourselves in the utility and how they tracked in the first quarter, it seemed to be above the target rates of the year. Are you – would you say you're ahead of where you thought you would be in Q1 or is this – did you expect a slightly better growth rate in the first quarter given you're coming off the tough year ago comps and just a sense of where the Q1 number is versus planned?

On a weather adjusted basis, the sales were about what we expected. Certainly, there was a significant amount of upside in the cold weather that we had in the first quarter. Jonathan Arnold – Deutsche Bank: But weather adjusted, it's about consistent with your guidance?

That's correct. Jonathan Arnold – Deutsche Bank: Okay. And then I had more of a strategy question. As the dust settles after the spin cancellation, any sense of – and your business mix clearly having settled out in a regulated and smaller piece of less regulated generation exposure. Any longer term sense of would you see that evolving in one direction or the other, at this stage or maybe Wayne can speak to that?

I'm not sure. I totally got the question, Jonathan. Jonathan Arnold – Deutsche Bank: Are you comfortable with business mix post spin where it sits today or if you would have shifted in one direction or another is there more interest in it shifting more into the regulated side of things given where the markets are or whether you'd be more interested in growing on the non-reg side?

Yeah. I really don't have a preference on that. We had an obviously – we had an obligation to serve on the regulatory side and we're going to meet that obligation to serve. In some places where we're not allowed a fair return on the business, we have to be very careful on how we make those investments and how much we spend. Because we obviously have a fiduciary obligation to all of you and we have to do and we have – as part of our obligations, we need to take self-help measures to make sure we don't bankrupt the company even though we have an obligation to serve. So that may mean some impacts on service in order to meet our other obligations to maintain financial viability. Where we are getting a fair returns and timely returns then obviously we're going to err on the side like we've indicated of trying to comply to the best possible way with our regulators own desires and interests in how much transition we build and what type of resources we have – whether it's renewable or whether its something else or how much our portfolio looks like, whether we rely upon gas or whether we use other sources. We've got a lot of flexibility to do those things consistent with public policy and which is what we much prefer to do. On the unregulated side, it's a lot more tricky because we're looking at these issues that you've all discussed and you're all concerned with, in terms of what the pipe is going to be, given the amount of uncertainty that we have here and that's much harder to predict. As hard as it is to predict regulatory actions they are at least bound by the law in many respects on the returns you're going to get. And when you're in the marketplace, as particularly for environmental regulations today and with some of the new entrants in the market, like Leo mentioned the shale gas, that become much difficult. I won’t say that we are – we obviously have a point of view that environmental regulations are going to get tougher. Whatever it is – it's going to get tougher. So we're very conscious of that and we do any analysis of adding to the portfolio in the northeast. But we do believe that the portfolio is valuable whether it's perfectly clean as it is today with all nuclear or whether it's added other resources to that it are almost clean. They're almost perfectly clean. So we continue to look at all options. There's a lot of assets still out there. Seems like there isn't, but there are in terms of consolidation, in terms of ideas on joint operation and in terms of ways to maximize the value of everyone's portfolio. And we're taking a hard look at those things. Obviously, the rating agencies concerns in that regard mean something to us, but they're not going to be controlling the decisions that we make if they're in the best interest of our shareholders and we believe – and the market believes we're still on sound financial footing with whatever we do. Jonathan Arnold – Deutsche Bank: And you just announced an analyst meeting from a year from now. Is that – hopefully that's not an indication of how long we may wait for some kind of strategic update.

Well, hopefully you'll get them as things sort themselves out. Sometimes the opportunity shows up on your doorstep when you least expect it. So that may happen before now and next year, but certainly between now and next year, as things proceed particularly with climate legislation and things of that nature and some of the other environmental issues – we'll be able to give you a clearer picture of what it is we'd like to do if it's not something we've already done. Jonathan Arnold – Deutsche Bank: Okay. Thank you, Wayne.

Thanks.

We'll take our next question from Daniele Seitz from Dudack Research. Daniele Seitz – Dudack Research: Thank you. I just was wondering if EC tritium issue completely resolved in Vermont and what is the next step there?

Mark, you want to address that?

Well, we're continuing to be – well first off, the plant's at an outage right now. And we shut down last Saturday and during that outage, there's some additional work that's going to be completed to reroute some of the pipes that were actually leaking. We're in the middle of pumping the ground water out and treating the ground water and recycling the ground water to the plant. And we just completed, this week the additional shoring to ensure that we can remove the soil that was contaminated in a very safe manner. And that will actually take place beginning next week – the removal of approximately 150 cubic feet of that soil. So we've identified what the problem is. We know how to resolve the problem and we're continuing to go ahead and complete all of the action items that we have on our punch list to finish that problem. In addition to that, we're continuing with our fleet wide initiative to pay the industry leader in tritium mitigation and that is well in progress. We're continuing with our six-step program – to implement our six-step program on that. So we're moving along on that. Daniele Seitz – Dudack Research: Can you anticipate the cost to stretch out through the year for that program?

Right now, just at Vermont Yankee, it's probably – at this time, we spent about $5 million and we anticipate to spend a couple more million dollars on that. And then to implement our fleet wide program, the initial seed money is about $1 million on that. Daniele Seitz – Dudack Research: Thanks. And in terms of the review, do you anticipate that post election? When do you think is a likely timing for that? In terms of the plants being reviewed again?

Daniele, are you referring to relicensing or... Daniele Seitz – Dudack Research: Yes. Yes or at least some discussion again after the repairs have been made?

Okay. Curt is sitting down there looking like he wants to say something.

Daniele, what we're doing at this point which we're moving forward with the process of making certain that we are properly communicating everything that's going on at the plant. That's everyone from the governor's office to the legislature and anyone else involved. Through that process, we are moving forward as well with the Vermont Public Service Board and the Department of Public Service with everything they need. Currently we have the reliability audit that we are following up and we will have a detailed conclusion here hopefully soon. We are also following up with the investigation. All of that's been turned over hopefully we'll see conclusion of that soon. Once we get that behind us, the legislature as well. We'll be going out of session pretty quickly. As you know, the house side of the legislature has decided not to act as the senate did. There seems to be support that Vermont Yankee, especially giving a joint study that was recently handed out by the legislature that was asked for by the house and the senate. And in fact, paid for by the utilities, not asked for by Entergy. But that study, which set up different scenarios, specifically with regard to reliability energy costs and environmental showed under all four scenarios that Vermont Yankee was the clear winner and needed to be there. So having said that and moving forward with discussions that Rick Smith is involved in on the PPAs, we have every reason to believe that we will move forward with a certificate of public good, get the license renewed at the NRC hopefully in the near-term. So that's where we are. Daniele Seitz – Dudack Research: Thank you very much.

Thank you.

And we'll take our final question today and that will come from Dan Eggers from Credit Suisse. Dan Eggers – Credit Suisse: Hi, just a couple of follow-ups. On the share buyback kind of why you guys weren't active in the first quarter and thought process of how you plan to redeploy the capital particularly as it pertains to your earnings guidance and getting the share count down for the year?

The – as far as the first quarter goes, given where we were in the regulatory process around the spin, Dan, that's really what it all boils down to. And as you'll recall, the $750 million was an authorization that was designed to capture what we believed that the business model in the current structure could support over the course of the next year, but it would also be part of the authorization we get ultimately in the spin-off when we did that. So it was going to show up in one form or the other either as part of the big recapitalization in the spin-off or as part of the current business structure over the course of the year. And so in both cases it just when we were in the spin discussions, the program just didn't get implemented in the first quarter.

Dan, this is Wayne. As you recall, we talked a lot about our board retreat and that was held right at the very last week of March. And given that the somewhat the surprise nature of the turn of events in New York over that last three or four months. We kept our board up to date with various telephonic calls and things of that nature. But we really believed that it was important face to face with them, where we had a week to put the numbers in front of them under various scenarios and strategies. And just get a sense that they believe that our financial situation was as robust as we did to continue with the buyback. And we felt like it was a prudent thing to do and that's one of the reasons. Dan Eggers – Credit Suisse: Okay. And I guess one last question. In the four power markets that you are looking at, has there been any change in kind of hedging value or forward sale value for New England Power, if you sell full requirements versus selling as available?

We haven't ventured into – given the nature of our plants, Dan, any kind of shape or full requirements type of transactions associated with that. We're still by and large still on a blocks powered, base load, on a unit contingent basis out of those plants going forward. The strategic issues that Wayne talked about a little bit ago, part of the thinking around those always does gravitate back to is there a way that you could provide different products and service firmer products or shaped products with complementary assets or what have you. But currently, with the existing fleet it's on the same basis it has been. Dan Eggers – Credit Suisse: But I guess I was trying to revert back into that question, which was how much pricing power do you see or how much pricing advantage will you see if you get offered a shape product relative to what you are selling today?

At the moment, we don't see enough to have justified any of the investments we have to make to be able to provide that product. So I guess that's the way we would look at it is – up against an investment in a different asset or construction of a combustion turbine or acquisition of power at a price that would allow us to do that. And how to pay off at the rate of return we haven't seen any of those opportunities yet, but we continue to look at them. As Wayne said, there's a lot of them out there and actually, the flow of that kind of activity has picked up over the course of the last, I'd say, six months or so. Dan Eggers – Credit Suisse: Okay. Thank you, guys.

Thanks.

And that does conclude our question-and-answer session today. Ms. Lopiccolo, I'll turn the conference back over to you for additional or closing remarks.

Thank you, operator. And thanks to you 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 for the next seven days by dialing 719-457-0820, replay code 3884569. This concludes our call. Thank you.

That concludes our conference call today. Thank you all for your participation.