Wayne Leonard - Chairman and Chief Executive Officer Leo Denault - Chief Financial Officer Paula Waters - Investor Relations

Steve Fleishman – Bank of America/Merrill Lynch Jonathan Arnold – Deutsche Bank Paul Patterson – Glenrock Associates Vedula Murti - CDP US Marc De Croisset - FBR Capital Markets Rudy Tolentino – Morgan Stanley Ashar Khan – Visium Asset Management Paul Ridzon – Keybanc Tom O’Neil – Unidentified Company

Good day everyone and welcome to the Entergy Corporation Third Quarter 2010 Earnings Conference Call. Today’s call is being recorded. At this time for openings and introductions, I would like to turn the call over to Ms. Paula Waters of Investor Relations, please go ahead.

Good morning and thank you for joining us. We’ll begin this morning with comments from Entergy’s Chairman and CEO, Wayne Leonard, and then Leo Denault, Entergy’s CFO, will review result. 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 statement. Wayne?

Thanks Paula. Good morning everybody. With the EEI Financial conference just over a week away, our earnings release and our comments today will be limited to significant briefs and events in 2010 financial performance. We will provide you with an update on our longer term financial outlook with EEI. Starting with Utility, the Public Utility Commission of Texas is scheduled to discuss Entergy Texas rate case at its next open meeting on November 10, 2010. At that meeting, the commission will review the ALJ recommendation regarding the competitive generation service or CGS tariff and the unopposed stipulation settlement agreement addressing all other matters in the case. To recap how we got here, in October the ALJ issued a proposal for decision recommending that the CGS tariff we rejected due to the potential for a substantial shift in cost from a limited class of eligible and participating customers to remaining customers, thus violating the basic principle of cost-causation. As a reminder, legislation initially enacted in 2005 and modified in 2009 required Entergy Texas to propose a tariff and offer eligible customers the ability to contract for competitive generation. As proposed by Entergy Texas, eligible customers will be limited to those with a minimum of 2500 kilowatts of demand. In the proposed decision, the ALJ recognized that the law is clear, that Entergy Texas be made whole for program costs and any loss of revenues from participating customers. The decision whether to proceed with a CGS tariff, and if so under what terms is now before the commission to complete it’s review as required by the Texas legislation, and then to approve, reject or modify it. The unopposed rate case settlement filed in early August reflected a $68 million rate increase and 10.125% allowed return on equity. An initial $59 million rate increase was implemented effective August 15 that is a refund, up from the $17.5 million increase implemented at the beginnings of May. If approved, the final step-up to achieve the full $58 million increase will take effect the first billing cycle in May 2011. As part of the unopposed settlement, the parties also stipulated to the current level of transmission of investment of $464 million that will serve as the baseline for future annual filings for a transmission rider. That includes full return of and on additional investment above that level. : Consistent with that reality, Entergy Texas filed a petition on September 17. This is generally supported by the other non-ERCOT utilities to initiate a rulemaking allowing for a purchase power capacity rider to address regulatory lag by recovery of those costs outside continuous filings of base rate cases. The PUCT has 60 days to decide whether or not to pursue the proposed rulemaking, Entergy elects to proceed, must reach a decision within six months of publishing the rule. In New Orleans, the City’s Advisors reached a settlement with Entergy New Orleans on the 2009 formula rate plan filing providing for an $18 million electric rate decrease, retroactive to the first billing cycle of October 2010, and no change in gas rates. This outcome resulted largely from a continued increase in the New Orleans customer base as rebuilding the neighborhood in the aftermath of Katrina and return of customers continue to see projections. : For the 10-year period starting 2013, the study projects the Entergy region including the Entergy’s outside the Entergy operating companies would realize anywhere from a net cost of $438 million to a net benefit of $387 million, primarily depending upon transmission cost allocation issues. There is addendum cost-benefit study also being conducted by Charles River’s including the Entergy system joining the Midwest ISO and standalone studies for Entergy Arkansas joining the SPP RTO or Midwest ISO are expected to be completed before the end of the first quarter 2011. With the initial full-year term of the Independent Coordinator of Transmission arrangement expiring next month, Utility Operating Companies have filed with request to extend the ICT arrangement with certain modifications by up to two years. This will help provide sufficient time for analysis and implementation of other alternatives to the current structure. : : First of all, this is a civil investigation and not a complaint. The DOJ is exploring questions and issues on a confidential basis such as the vertical integration of utility and practices and policies of the Entergy utility companies related to generation procurement, dispatch and transmission. Investigation is just beginning and of course utilities are fully cooperating with the DOJ. : As noted in our announcement, Entergy became aware of the investigation during the required Hart-Scott-Rodino review of the utilities proposed acquisition of the 580 megawatt Acadia Unit 2. : : : Also during the quarter, the NRC staff issued a positive report on its audit of Vermont Yankee’s license renewal application conducted in response to the [Inaudible] earlier this year. The staffs report raised three issues, Entergy or Vermont Yankee has addressed these three issues in an application supplement submitted to the NRC in mid-October, which was prepared in coordination with a similar application submitted for Pilgrim. The next milestone in the Indian Point license renewal process is the issuance by the NRC staff of the final supplemental environmental impact statement currently expected next month. Reports released during the quarter by the Independent System Operators in New York, in New England strongly support the criticality of using the system reliability and their reach. In New York, findings in the ISO’s 2010 Reliability Needs Assessment indicated the unexpected retirement of the Indian Point units for causing immediate violation of reliability standard even considering aggressive assumptions for energy conservation in the region. In the base case load forecast, the probability of an involuntary interruption of load was 3.8 times higher than the reliability standard in 2020. The power ability estimate decline from 40 times since the beginning of filing period in 2009 report, due to the combination of economic slowdown and the safe and business demand side management target. However sensitivity analysis usually what we believe in more realistic assumptions indicated the probability of a liability violations are much closer to the conclusion in the 2009 report, if you take out both the point units. Further the New York ISO assessment found as New York Department of Environmental Conservation best available technology program as defined under proposed rule issued in March creates the greatest risk of premature retirements and for unacceptable reliability risk. The New York ISO’s President and CEO summed it up succinctly indicated the need to carefully balance environmental policy objectives with the reliability requirement of electric systems. Further in early August, The New England ISO denied Vermont Yankee request to de-list from 2013 to 2014 for it’s capacity options given studies completed today. In other words, without Vermont Yankee services there are liability issues which will adversely effect neighboring areas. The ISO went on to point out of the any alternatives to Vermont Yankee sounds that are additional, and we might had a necessary cost, of course reliability and safety concerns go hand in hand, no one takes safety more seriously than we do. On that subject local concerns resurface in Vermont following a recent finding a trace amounts of tritium in a water sample taken from rock fishers beneath the plan. It’s important to note that the water sample test does not indicate any new tritium leak over Vermont Yankee. The test result confirmed the migration of water released from the precious leak, which was identified seal and repaired earlier this year within 49 days of detection. Moving forward we remain committed to pursue greater prevention and order detection as part of the Exelon, Entergy industry leading initiatives on tritium. At the same time, we have upgraded our sampling process and our communications with stakeholders. Turning to our recent price hedging activity, it’s clear that the commodity markets for power, natural gas are having a tough hurdle for non-utility business and will likely continue to prove challenging for the next couple of years. Forward, energy prices for 2011 and 2012 in New York and New England declined by an average of 10% since the end of the second quarter and dropped by over 25% since the 2009 EEI Financial Conference, consistent with past practice we have been layering in hedges over the past year. Although, we have been more aggressive and accelerating this hedging activity, based on our proprietary point of view of these markets, as a result forward energy sold is down 95% in 2011 and 76% in 2012, a contract basis in the money by around $630 million for EWC’s differed portfolio. Despite these challenging times and with the help near records warm temperatures Entergy’s third quarter earnings per share were the highest at any quarterly period in company history. For the full year we remain on-track for a fixed consecutive year of delivering record operational earnings per share. But we’re now in a transitional period. On the one hand we have an uncertain economic climate, challenging commodity markets, and critical nuclear license renewal activities at EWC. On the other hand there are numerous corporate development opportunities including the potential acquisitions identified in the recent long term RFP process an alternative structures for system agreement and transmission operations at the utility. We also continue to evaluate and consider available options at EWC to create and return value to our owners. Many of you have asked, if there will be a significant strategic announcement EEI has, has been the case at various times in the past. Given the fact that EEI is just about 10 days a way, I can tell you that we don’t have any major events right for announcements this time, but we will update you on our longer term outlook and discuss our strategies and opportunities in more detail. While the world’s economic prospects are not as bright as they once were or what we would hope for, we remain grounded in the reality that it is what it is. We’re committed to sound rich management and we are still think about what might have been and cannot cloud our judgment and our processes. We will not leave large positions opened on the basis of look back models, nor we’ll substantially increased our risk by selling firm products that we can’t backup. I can assure you, we are committed to executing the everyday on the things we can control, taking decisive action consistence with our proprietary point of view, maintaining financial headroom for unexpected opportunity to address, while being even tentative to the amount of risk and type of risk that we are warehousing. In closing I am pleased to report that Entergy was named to the prestigious Dow Jones Sustainability World Index for the ninth year in a row and since its held by no other US utility. Key area for Entergy for its rank best or among the best for its safety, environmental policy and climate change, corporate government and price risk management where we see the best score. Our commitment to excellent in al these areas as well as out overall chief financial aspirations topped total shareholder return remain unchanged. Now I will turn the call over to Leo.

Thank you, Wayne, and good morning everyone. In my remarks today, I will cover third quarter results and cash flow performance powered by an update of our share repurchases activity and a recap of 2010 earnings guidance. I will also point out some highlights on financing activity over the past few months and close with a few preliminary thoughts on 2011 drivers that will be discussing with you further at the upcoming EEI conference. Starting with our financial results on slide two, third quarter 2010 earnings were higher than one year ago as both the utility comparing another while there were lower nuclear. Third quarter earnings included accretion from share repurchases from both the 2009 and 2010 programs. Once again this quarter as reported resulted included charge associated with spin-off to synergies, and the expenses for outside services that are now focused on the spin unwind process. As we’ve previously committed, we have been aggressively working through the process of unwinding the spin infrastructure, these unwind efforts were largely completed in the third quarter. Excluding the special item related to the spin, operational earnings were up 15% compared to the third quarter 2009. The factors driving quarter-on-quarter results turn to slide three. First with the utility higher net revenue was the primary factor driving the quarterly earnings increase. Utility sales once again increased across all the customer classes including the effects of significantly warmer than normal weather throughout our service territory. Even excluding the effect of weather each jurisdiction had positive retail sales growth. Overall utility retail sales grew by 8.5%, that’s by double-digit performance in the residential sector. And for the third consecutive quarter weather was a significant factor in residential sales growth. After a record setting cold winter, temperature across our service territory reached near record levels for the second consecutive quarter, our regions temperatures make13 hottest of the 116 years of available data in the third quarter. Louisiana, Mississippi and Arkansas temperatures were especially warm when compared to seventh and tenth respectively. In addition, Texas experienced record usage for four straight weeks picking at 645.7 gigawatts on August 30. Turning to the industrial sector, we continue to see the positive effects of the economic rebound and facility expansions, strong industrial growth continued in the third quarter, but at a lower level than in the second quarter adjusting economic recovery maybe leveling off. Looking at specific industrial segments, the results were mixed; chemicals, refining and miscellaneous manufacturing had been our strongest sectors while wood products and pipelines have been weak points. Primary metals were stronger earlier in the year, but soften some during the most recent quarter due to week construction markets and lower demand from China. As we noted in the past two quarters there are some tempering effects including in our industrial sales result this quarter, the increase in net revenue from higher industrial sales volume was somewhat offset by the price effect associated with demand charges. We recall that last year, we had reverse situation when the demand charges that offset the negative impacts of lower volume. You can take away from all of this, is that are weather adjusted sales results today aligned well with the assumptions we use in our full year guidance numbers. Regulatory actions also contributed to net revenue in the current quarter. Results reflect the rate cases that Entergy Arkansas and Entergy Taxes as well as formula rate planning activity at Entergy Gulf States for Louisiana and Entergy Louisiana. The absence of a refund reserve from the Louisiana utility companies recorded in the third quarter of 2009 also contributed, partially offsetting the possible effects of higher net revenue with higher non-fuel operation and maintenance expense and income tax expense. The increase in non-fuel operation and maintenance expense is due primarily to higher compensation related expenses and higher outage costs at generating units. Higher income tax expense was partly due to the net effect of consolidated tax adjustments, which are made across the Entergy companies and net to zero on a consolidated basis. Other drivers at the utility were largely offsetting. Moving onto Entergy nuclear, this year’s third quarter results declined versus 2009 primarily due to decreased net revenue associated with lower generation, attributable were both planned and unplanned outage days and higher non-fuel operation and maintenance expense. The third quarter of 2010 included a portion of the scheduled refueling outage at FitzPatrick, which started on September 12 and ended in the fourth quarter. There were no scheduled outages in the fall of 2009. There were also approximately 21 additional unplanned outage days compared to differed quarter last year, primarily at the Indian point units in Palisades. Conversely the non-utility nuclear fleet ran at a 100% capacity factor in the third quarter of last year. On a positive note, the realize price in the current quarter was essentially flat to the third quarter of last year, while the average contract price decreased year-over-year and market prices on the unsold Entergy average nearly $25 and megawatt-hour higher largely due to higher natural gas prices and warmer weather driving stronger demand. Similar to the utility business, Entergy Nuclear’s third quarter non-fuel operation and maintenance expense was also higher than a year ago; this increase was due primarily to higher compensation related expenses. Partially offsetting these factors was a lower effective tax rate in Entergy Nuclear driven by a reversal of a tax reserve as well as net effects that consolidated tax adjustments discussed earlier. Finally third quarter Parent and other results were higher than a year ago due primarily to lower income tax expense. The income tax expense decreased, resulted in part from a favorable tax court decision, and net effect of consolidated tax adjustment also contributed to the income tax benefit at parent and other. Moving now to slide four, we continue to have very strong operating cash flow performance. Third quarter 2010 OCF was approximately $700 million higher than the third quarter of last year. We see the storm financing proceeds from Louisiana was the primary driver. Other factors both at utility include higher net revenues personally offset by higher working capital requirements. At the end of the third quarter, Entergy’s consolidated gross liquidity stood at over $4.1 billion comprised of 1.9 billion in cash and cash equivalents and 2.2 billion in uncapped revolver capacity. One reason for the strong liquidity was the Parent notes financing completed last month, with the very favorable interest rate environment we initiated and closed $1 billion of permanent debt at the parent company was approximately half during five years and the balance in ‘10. We use the proceeds to pay down a portion of the borrowings under the parent’s revolving credit facility, which expires in 2012. We also took advantage of attracted capital markets to reduce the interest cost for our customers. In the past five weeks we executed more than $900 million of economic re-financings and average coupon of 4.7% compare to 5.6% of the debt that was retired. We’ll continue to evaluate additional financing opportunities at both the utility operating companies and the parent. I’ll now turn to the update on our share repurchase program summarized on slide five. During the third quarter, we completed roughly $528 million of share repurchases buying 6.8 million shares at an average price of $78 a share. Of the repurchases during the quarter, 466 million were made through the existing $750 million board authorization program. The balance was repurchased to offset the diluted effects of stock option exercises. As we have noted previously we expect to complete repurchases under the current $750 million program by year-end. Execution is subject to our ongoing evaluation of business and financial conditions and our point of view on stock price. 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 and operational guidance ranges remained unchanged from the numbers we shared with you on our second quarter earnings call. As we assess our earnings performance today, we believe we are well positioned relative to our full year guidance range. With $0.55 per share of weather on a year-to-date basis, I know many of you are wondering why we did not revise our guidance range. It is simply due to our guidance practice to maintain a range unless factors move us out of that range. We instead provide inside on how the major drivers are performing relative to the original guidance assumptions. It is not meant as an indication of significant risk to our guidance range though we’ve not discussed with you. In fact, at this point of the year, we will know indications are that will end above the midpoint of $6.80 of operational earnings per share. In closing, as Wayne said, we plan to update a longer-term outlook at the upcoming EEI conference, which starts on October 31. At that time, we plan to initiate 2011 guidance with all the typical details when key drivers your used to receiving. We also plan to provide the usual preliminary the roll forward of our three year capital plan for 2011 through 2013 as well as an update of our long-term financial outlook. In advance with that, turning to slide seven, we wanted to provide a few preliminary thoughts on 2011 earnings drivers. For example, we know that the utility’s 2010 sales growth has been very strong and include significantly positive effects from weather and economic recovery. On the other hand, we also know that we’ve already achieved positive results in the regulatory arena, which will benefit next year. For Entergy Nuclear, we have observed declining price turns. However, we have only three refueling outages planed for 2011 compared to four for 2010. We also have the $750 million share repurchase program that we expect to complete by year end with the full share effect realized in 2011. We’re looking forward to seeing you at EEI to discover more details of our financial outlook strategies and opportunities. And now, Entergy Senior team is available for your questions.

(Operator Instructions). And we will take our first question from Steve Fleishman with Bank of America/Merrill Lynch. Steve Fleishman – Bank of America/Merrill Lynch: Hi guys, this is Steve. When you look at the new hedges that you added, it appears on the surface that the pricing of those new hedges was quite low versus where market is. Even considering due to contingent hedging, and the only thing I can think that could explain that would be maybe a hedge mainly in your low priced regions, like upstate New York. Does that explain it or are we just calculating it wrong?

Leo?

Steve, that, I don’t really want to get in to your plant by plant. We’re hedging out, but certainly there is some significant differences between zones or some significant difference between plants just as you mentioned. And so, obviously the average price of those sales are going to be driven by where we did the hedging as well as what type of hedging we’ve done. Steve Fleishman – Bank of America Merrill Lynch: Okay. So it’s possible that, is there any other –?

It’s possible. Steve Fleishman – Bank of America Merrill Lynch: Other possible explanation, why the hedging would be below market?

I guess, I would just say that the hedging isn’t being done below market. So I guess I’m saying that you are pretty close in your estimation of why. Steve Fleishman – Bank of America Merrill Lynch: Okay. And then the other question I have is just from the drivers for 2011; you mentioned the benefits of the current buyback flowing through. Is there anything we should read in terms of thereon, in terms of whether you do an additional buyback or not? Would that just be something you would update at EEI, either way?

Yeah, we’ll update that at EEI. We have a lot of internal discussions to take place before that time period. We have board meeting next week and, we will do our financials with them first, so we are not prepared to make any predictions about that at this time. Steve Fleishman – Bank of America Merrill Lynch: :

And we’ll take our next question from Jonathan Arnold with Deutsche Bank. Jonathan Arnold – Deutsche Bank: Good morning guys.

Good morning. Jonathan Arnold – Deutsche Bank: My question is also just on hedging. You mentioned that your hedging in the quarter had to do with point of view. Did it also have something to do with the new EWC structure and the kind of rethink around the whole commercial organization you talked about on the last quarterly call or is that still a sort of work in progress?

John, as far as the hedging goes, it’s primarily driven by point of view. As it relates to organizational structure, certainly the kinds of things we do over changing. So, in large part your activity, you will notice a big change as I’ve mentioned before. We did organizational shift, but it’s around the way we approach things. The analytics we have, all of that is going to be improved, but that may help shape our point of view if we get better data than maybe we had in the past, but certainly it’s point of view based. Jonathan Arnold – Deutsche Bank: Okay. Thank you. And then if I could just on a second topic you had – we’re looking at the quarterly cash flow statement, there was this estimated losses in reserves inflow of the best part of 300 million. Can you shed some light on to what that might be?

I’m sorry, can you say that again? Jonathan Arnold – Deutsche Bank: On the quarterly cash flow statement, does that quarter – tag [ph] $289 million of inflow for provisions for estimated losses in reserves was that something over a collection of items that you could shed some light on to what’s in that?

I think that’s something I will have to Michele get back to you on Jonathan. Jonathan Arnold – Deutsche Bank: Okay, thank you.

Or Paula rather, I’m sorry.

And we will take our next question from Paul Patterson with Glenrock Associates. Paul Patterson – Glenrock Associates: Good morning guys.

Hi Paul. Paul Patterson – Glenrock Associates: Hi, couple of things, the uprate write-off, what was causing that and what was the reason for that, I’m sorry if I missed that?

We had planned a -- we have been working on the potential uprate at one of our non-utility nuclear plant. And just with conditions where they are in the markets and things like that, we just – isn’t something that we think we’re going to pursue at this time. Paul Patterson – Glenrock Associates: And how much was that I guess?

I don’t know that we disclosed it. Paul Patterson – Glenrock Associates: Okay, I was just wondering, so it means but it’s market base so.

Pardon me. Paul Patterson – Glenrock Associates: It’s market base, basically because the power prices just don’t support it well.

Well, we didn’t do it. It’s about $10 million, that’s .. Paul Patterson – Glenrock Associates: Okay and the longer term outlook and stuff, is that going to be provided at EEI, is that why we don’t see at this time in the release?

Yes, that’s right. Paul Patterson – Glenrock Associates: Okay and just finally, the FERC [Inaudible] for DR, demand response, any thoughts about what we might be seeing in terms of the impact on pricing, if that’s approved, is it – was filed and I guess is being discussed I guess as [Inaudible] marginal price? Any thoughts about how that might impact markets or do you see any effect of that potentially happening already or..?

No, I mean -- I don’t think we really have a point of view on that right now. Paul Patterson – Glenrock Associates: Okay

I don’t think, we do, sorry. Paul Patterson – Glenrock Associates: Okay, thank you so much.

We will take our next question from Vedula Murti with CDP US. Vedula Murti - CDP US: Good morning.

Good morning. Vedula Murti - CDP US: Couple of things and I apologize if you addressed this Wayne in your earlier comments, I came in twitcher [ph] tail end. One, can you in terms of strategic initiatives or possibilities, can you talk at all about any interest you may have in the Unistar situation with EDF and what’s going on with Calvert Cliff and Constellation, whether it’s part of Entergy Nuclear efforts there and then I have a second unrelated question.

Comment on specific transactions. The –it’s something we’re aware of various things that are going on in the industry, but we did stick with our historical policy really not to comment on things of that nature. Vedula Murti - CDP US: Alright, and secondarily can you update us all in terms of, again I apologize if I missed it, in terms of the system agreement issues with Arkansas and Louisiana, the companies wanting to are leaving the agreement and what types of financial consequences at this point you are seeing?

Gary.

Good morning. When you look at it what we’re preparing for is under the – where we are today is Entergy Arkansas gave a notice and as of December 2013, they would leave the system agreement as well as Mississippi following up in 2015. We have done several things and the first thing and is most recently, we have laid out a structure Wayne talked about it in his comments called the CODA, which would give us an opportunity to propose some changes, and we are sharing that with each of the regulators. But they also, for that specific have a decision to make whether or not if they are in agreement with and if they are not we would not pursue that. In addition to that, we have to be prepared for Entergy Arkansas being a standalone position and several things are dealing with that. We are basically in the process of looking at what is actually going to put that into a standalone condition as we are for Mississippi. And we are looking from a transmission point of view, there are a couple of activities, one is where would they get transmission services from, and there are some studies that are being done. One is this, whether or not they join an RTO like SPP or whether or not they join an RTO like MISO, part of that study has come out just this week. And Wayne talked about it, because we are also looking at it from a system perspective under FERC study, which basically has a range of possibilities depending on benefits from negative deposit, depending on transmission allocation. So pretty much, we’re pursuing both paths, the first to be to get an alternative that preserves the value of a system, and second then also to be prepared for Entergy Arkansas and subsequently Entergy Mississippi to leave the system agreement. Vedula Murti - CDP US: And I guess my last follow-up there, if I recall properly of the operating companies, one that in terms of the imbalances or its perceived imbalances, the one that benefit the most right now that would then have to fill in the gap would be Louisiana. So is there a possibility then that there would have to be a material cost increase to Louisiana’s part of the reshuffle here?

As we look forward to it, I don’t see that at this point. But clearly, we’ve been playing for the system and you see that through the RFP that we put out as far as assets that we’re bringing into meet those needs as the system changes. But in a low gas market benefit, it’s a little bit different today than it was when there was high imbalances between the systems between Arkansas and Mississippi. So as long as we continue to see those low gas prices that imbalances it it’s not anywhere near. And I think you can see that in the RPC [ph] payment. This past year was a, from $41 million from Arkansas as opposed to the $390 million toward the previous year. Vedula Murti - CDP US: Okay, thank you.

Our next question comes from Marc De Croisset with FBR Capital Markets. Marc De Croisset - FBR Capital Markets: Hi, thank you. Good morning. Just two very quick questions, the first is very specific on your production cost per megawatt hour. And I see that they’ve trended up, is it about 23% quarter-to-quarter from say, 22 to 28 or so, it looks like you’re kind of within guidance year-to-date, but can you give us any color on what’s impacting that?

Hey Leo.

Sure that’s driven by a number of things, part of it’s refueling outage amortization, part of it’s fuel cost, and then the production cost would also include that charge that we talked about for the uprate. That flows through in as well as the compensation related expenses. Marc De Croisset – FBR Capital Markets: Great. And a quick second question; I didn’t see a CapEx schedule in the press release, maybe I missed it. Is this something that you’re updating at EEI? Is it now in a state of flux?

Yes, that’s – we’ll be updating that at EEI, we will go forward of three-year CapEx. Marc De Croisset - FBR Capital Markets: Okay. Thank you very much.

We’ll take our next question from Rudy Tolentino with Morgan Stanley. Rudy Tolentino – Morgan Stanley: Hi, I know you’ve referred to the asset purchases under the 2009 RFP. Can you just give me an update about, where those stand and what kind of guideline you have for implementing those?

Yes, I mean, right now it’s been pursued as far as looking at what deal we can negotiate with the people that respond in RFP and we would expect probably the later part of this quarter to really try more likely the first part of next quarter to be able to announce those. And then once we do that, then we will go to the regulatory process that comes out with the results of that either through interim PPAs and tolling agreements and for ultimate purchase of assets as well as the Nine Mile self-build that is being pursued inexplicably, I think it’s the third quarter of 2014. Rudy Tolentino – Morgan Stanley: And how long will the regulatory process take, when to announce the transition?

Typically if you are looking at in the past, we’ve been somewhere between one to two years in that kind of timeframe depending on the complexity. Rudy Tolentino – Morgan Stanley: Okay. And then you also and Jonathan asked about the EWC structures, and you mentioned that you are going to do different kinds of things under that structure. Can you just kind of give a little bit more color of what kind of things that you are going to be doing different, I mean are you going to offer, you talked about data, but are you going to offer like different products or expand your services?

Rick, you want to answer that.

Yes, I mean we are looking at all these different things Rudy, but I mean really right now our objective is cannot protect the assets we got. We look at assets that come on the market and we are always kind of looking out for new assets, and we have been as you can kind of see in the [Inaudible] table, then offering a little different product in the market with our commodity sales. So, we will continue to kind of plough that ground over the next six to 12 months. Rudy Tolentino – Morgan Stanley: Okay. I guess I will look forward to explain it with you further in a couple of weeks’ time.

Okay. Rudy Tolentino – Morgan Stanley: Alright, thank you.

Our next question comes from Ashar Khan with Visium Asset Management. Ashar Khan – Visium Asset Management: Good morning. Leo, Can I just over, you said the guidance for just looking what’s happened in the first nine months. The weather was up like $0.55 or so. So that would kind of like put you above your top end of your range. What were the negative factors? I guess, one is the nuclear pricing, but are there other negative factors which have happened in the nine months, why you wouldn’t be like at the top end of the range of surpassing it?

There are a number of things, there is financing that we are going to compare versus what we have obtained for the revolver. It’s kind of a long-term versus short-term decision in terms of where we would go with that. We also had some of the O&M issues that I talked about that are driving more of a, some of those are non-recurring type of things, the payroll related expenses. We’ve got the write-off of the uprate. We talked about we had some pressures from pension cost because the discount rates, those sorts of things that have rolled through as well. So all of that goes to kind of pushing us again. We are kind of, right now indicating we are above the mid point but not outside the range. Ashar Khan – Visium Asset Management: Okay. And then if I can just based on the data that you provided, I guess this year the pricing is going to come up, the factors that you kind of mentioned, the pricing for this year is going to be like somewhere in the 59 average on the nuclear, and based on hedges that you provided, I guess it’s 55. So what we are looking for is really like a $4 decrement, is that correct? But we will have like – it will be offset somewhat with an extra terawatt hour of generation, is that the right way to look at from the data that you provided?

For next year? Ashar Khan – Visium Asset Management: For next year.

Yeah, I mean we are going to end up with a little more generation, but certainly the market prices have changed and hence while we hedged out so much. Ashar Khan – Visium Asset Management: Okay. Thank you.

We will take the next question from Paul Ridzon with Keybanc. Paul Ridzon - Keybanc: Could you just give an update on the PPA discussions in Vermont and where those stand?

Rick.

They are still progressing and I mean it’s a slow process with them, I mean we are – lot of terms and conditions, so we are going back and forth, like I said it’s some of the investor conferences I expect that we will get that wrapped up by the end of the year. Paul Ridzon – Keybanc: And then could you just, you have a $0.30 swing at Parent, can you kind of [Inaudible] out the bigger pieces of that?

Well, the biggest piece of that has to do with taxes and a favorable tax court ruling that we have associated with just in the scheme of how these things play themselves through the 1998 issue. Paul Ridzon – Keybanc: You can quantify that?

That’s about $0.25. Paul Ridzon – Keybanc: And then just on the 2011 [Inaudible], how much floating is going to be had or has been swapped into fixed?

I am sorry, what you are referring to? Paul Ridzon – Keybanc: As your 2011 [Inaudible], you mentioned financing cost getting out of the revolver, how much notion was there?

We have got a $1 billion of term debt. Paul Ridzon – Keybanc: Is there more coming?

It’s possible. We are looking at given today’s interest rate environment, we are looking at, again we did over 900 million at the Utilities as well. So we are looking at both the Utilities and the Parent for more opportunities there. Paul Ridzon – Keybanc: Thank you very much.

Thank you.

And we have time for one more question. We will take it from Tom O’Neil from [Inaudible] Tom O’Neil – Unidentified Company: : Good morning, it’s actually Tom O’Neil. How are you doing?

Hi Tom. Tom O’Neil – Unidentified Company: Just have a quick question for you on the revolver, in the past limitations on the buyback I think for the debt-to-cap ratio and just curious how you are thinking about that, what limitations you are facing with regard to that debt as you are coming out?

As far as it relates to the revolver, anything that we have with covenants and those that may or may not be an issue, certainly not an issue at the moment. As far as the revolver comes due in 2012, we’ll continue to look at what the right timing and structure for that going forward. And as far as it relates to buyback it’s really more than overall issues not related specifically to revolver in anyway Tom, it’s more related to a combination of business mix of cash flow production and credit ratings all mixed into one, making sure we have the right liquidity profile, et cetera. So, it’s not specifically related to the revolver in terms of what we may or may not do with repurchases. I will say that as it relates to the financing that we done, currently the longer time financing, we did had some longer term debt that was in place between 2002 and 2005 timeframe that matured during the tendency of the spin and as that matured rather than replace it, we were looking at re-capitalization coming out of the spin, so we didn’t take advantage of anything at that point in time. So, nearly the billion – there is about a billion for that debt at the Parent level at that time. So, we’ve got a $1 billion of longer term debt now, we can necessarily say that it’s anything different than where we stood before we started the spin-off process, not really turning out the revolver, it’s just really re-capitalizing the way we were already beforehand. And at this point, we don’t have any plans that any incremental debt that we will do at the Parent or any more financing we will do at the Parent, we wouldn’t intend that currently to be incremental debt. Again, it’s all function of our liquidity profile and cash flow metrics on what’s going on in non-utility business and what our credit ratings are, they’re all part and parcel to that decision. Tom O’Neil – Unidentified Company: Got it. Thank you.

And that concludes our question-and-answer session. I would like to turn the call back over to our presenters for any additional and closing remarks.

Thank you, operator, and thanks to all for participating this morning. Before we close, we remind you to refer to our release in 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 5590047. This concludes our call. Thank you.

This does conclude today’s call, thank you all for your participation.