Gary Taylor - President of Utility Operations J. Leonard - Chairman, Chief Executive Officer and Chairman of Executive Committee Michael Kansler - Roderick West - Chief Administrative Officer, Executive Vice President and Chairman of Entergy New Orleans Inc Charles Rice - Chief Executive Officer of Entergy New Orleans and President of Entergy New Orleans Leo Denault - Chief Financial Officer and Executive Vice President Paula Waters - Vice President of Investor Relations

Michael Lapides - Goldman Sachs Group Inc. Dan Eggers - Crédit Suisse AG Paul Patterson - Glenrock Associates Ashar Khan - SAC Capital Julien Dumoulin-Smith - UBS Investment Bank Steven Fleishman - BofA Merrill Lynch

Good day, everyone, and welcome to the Entergy Corporation Second Quarter 2011 Earnings Release Conference Call. Today's call is being recorded. At this time, for introductions and opening comments, I would like to turn the call over to the Vice President of Investor Relations, Ms. Paula Waters. Please go ahead, ma'am.

Good morning, and thank you for joining us. We'll begin this morning with comments from Entergy's Chairman and CEO, Wayne Leonard; and Leo Denault, our CFO, will review results. [Operator Instructions] After the Q&A session, I will close with the applicable legal statements. Wayne? J. Leonard: Good morning, everyone. I'm pleased to report another quarter of solid financial performance, which Leo will review with you in a moment. Quarterly operational earnings per share topped the second quarter records set just 1 year ago, despite the effect of the depressed power pricing on the wholesale business, the power price contracts roll off. We continue to pursue a full agenda of strategic initiatives that will take some time to fully play out. In the meantime, the commodity markets, which are showing some signs of long-term recovery, will continue to be a drag on earnings for at least the next couple of years. I'll begin today by providing an update on the progress that we've made on some of those key initiatives. Starting at the utility. Our utility companies have worked hard for a long time to secure regulatory structures and mechanisms that allow a real opportunity to earn returns commensurate with investment alternatives at comparable risk. You will see that these efforts are coming to fruition, as you review the financial results. For example, since the end of 2001, average residential rates have increased a little over 0.5% per year over the near 10-year period or almost flat for 10 years, while utility operational earnings per share at the midpoint of the 2011 guidance is nearly double the operational results 10 years ago. At the same time, our operational and our safety performance and our environmental record continues to set new company standards. Our voluntary CO2 emissions reductions put us over 20% below the year 2000 level. Formula rate plan filing for 2010 reflects earnings consistent with each company's bandwidth ranges in Louisiana and Mississippi, and we are above the range in New Orleans. Unseasonable weather in 2010, both a warm summer and a cold winter, contributed to these results, with industry Gulf States Louisiana -- Entergy Louisiana and Entergy New Orleans, near the top end or above the range. In total, the New Orleans 2010 FRP filing reflected a $7.6 million decrease in electric and gas rates. Also included in the Entergy New Orleans May filing was the request to increase storm funding by about $20 million to replace the cash storm reserve after expenditures for hurricanes Gustav and Ike, allowing the cash storm reserve to reach the approved $75 million level on schedule by 2017. The electric and gas rate changes are expected to be effective in October. Turning to Texas. Legislation was enacted in May, allowing for a special rider to periodically adjust rates for changes in distribution estimate. The Public Utility Commission of Texas is now in the process of repairing the rule-making and rate filing package to be completed by late September. Entergy Texas also continues efforts to achieve a purchased power capacity rider after the PUCT reopened a rule-making earlier this year. The introduction of a distribution rider and a purchased power capacity rider, coupled with the transmission rider, already authorized, would provide industry Texas' additional tools similar to those in place in other jurisdictions that efficiently and effectively promote the public interest and align shareholder and customer economic interests. If final rules are adopted, ETI has the opportunity to file for 1 or more of the 3 riders in 2012, depending on circumstances related to a more complete review of overall cost. The utility also continued to execute its capital investment commitments related to last year's resource selections in the summer 2009 long-term request for proposal. In June, Entergy Louisiana filed a request seeking Louisiana Public Service Commission approval to construct the 550-megawatt Ninemile 6 combined-cycle plant. The total project cost is estimated at $721 million, excluding interconnection and transmission upgrades. Under the current proposed structure, Entergy Louisiana would own the plant, retain 55% of the energy and capacity, and sell the balance under a life-of-the-unit power purchase agreement to Entergy Gulf States Louisiana and Entergy New Orleans. The June LPSC filing also requested approval for Entergy Gulf States Louisiana to enter into the PPA for its 25% share of the output of Ninemile 6. Entergy New Orleans also filed with the City Council seeking authorization to purchase 20% under its life-of-unit PPA with Entergy Louisiana. LPSC approval was requested by January 2012 in order to issue full notice to proceed and maintain the construction scheduled for a targeted commercial operations date by the summer of 2015. Regulatory filings were also submitted, seeking acquisition approval and rider recovery upon transaction closing, for the 620 megawatt Hot Spring power plant in Arkansas and a 450-megawatt Hinds power plant in Mississippi. Closing on both acquisitions is targeted for mid-2012, subject to receive federal and state approvals and other closing conditions. In transmission, on May 12, utility operating companies each filed reports detailing the rationale for joining the Midwest ISO. Total net production cost savings range from $1.1 billion to $1.4 billion compared to $0.8 billion to $1.1 billion by joining the Southwest Power Pool over the 10-year period from 2013 to 2022, compared to the status quo. Production cost savings are projected to be realized for customers in all operating companies. The reports emphasized the known benefits to our customers that a mature, functioning, large Day 2 market. Then on July 1, FERC issued an order on the joint operating agreement between SPP and MISO, that confirmed additional power flow between MISO and Entergy would be available over and above the 1,000-megawatt interconnection assumed in the cost benefit analysis. That's the amortized [ph] that you often hear about. At issue was whether the joint operating agreement, allowed sharing of available transmission capacity often called loop flows, between MISO, SPP and Entergy Arkansas in the event Entergy Arkansas joins MISO. FERC found, consistent with past FERC policy, that if Entergy Arkansas joins MISO, the joint operating agreement will allow market flows between MISO and the Entergy system across the interconnected SPP member facilities or the shared flow gate. While additional details may be resolved between MISO and SPP on compensation matters, FERC's decision on the JOA and the ability to utilize surrounding transmission lines above the 1000-megawatt interconnection previously assumed for purposes of a conservative analysis, will only serve to increase the potential benefit for joining MISO. Beyond the clear economic benefits of MISO, other factors favored MISO over the alternatives. It's mature operating Day 2 market, larger geography, load and generation resources, scale and diversity, and transition cost allocation policies that are better aligned with our principles on cost causation. For years, we have advocated the efficiency of the cost causation principle, despite -- what we'd often call participant funding, despite pressures to move to a more cost allocation based tariff or what others call rolled-in rates. Speaking about FERC order 1000, after its July 1 issuance, FERC Chairman Wellinghof stated that a fundamental principle of the new rule is that if there are no benefits, there will be no cost allocated. FERC's policy, deploying cost allocation to be roughly commensurate with the benefits is more aligned with the efficiency and equity of cost causation principles and should provide the protection for our customers similar to those that we have long fought for. However, the effectiveness of the new rule will depend on how it is implemented in the various regions. Since the May 12 filings, utilities have continued to participate in technical conferences and meetings, and have provided additional details on the analysis as requested by regulators. The Arkansas Public Service Commission has a hearing scheduled for September, and the docket addressing the system agreement and MISO. Joining MISO marks a significant transformation of the Entergy system, providing greater independence, transparencies and efficiencies, addressing the exit of Entergy Arkansas and Entergy Mississippi from the system agreement, as well as providing substantial benefits to our customers, contributing to the ability to maintain affordable rates for Entergy's utility customers. Utility continues to target a system wide cut over to MISO by December 2013. Moving on to Entergy wholesale commodities. Starting with Vermont Yankee. Last Monday, we announced that Entergy's Board of Directors voted to proceed with the October refueling outage. This decision followed the board's careful deliberation on the merits of the case we filed and the arguments put forth by all parties at the preliminary injunction hearing conducted in June. The court has put this case on an accelerated schedule for a mid-September trial on the merits of the case. Given that we are in litigation, that's about all we can say about that for the time being. However, even with this expedited trial schedule, this litigation could well continue for an extended period of time, given the potential for appeals to the Second Circuit and a writ to the U.S. Supreme Court, as many have speculated where this will all ultimately end. Turning to matters in New York. Progress continues on the regulatory front related to license renewal. The Atomic Safety and Licensing Board issued rulings in July, continuing its work to determine the issues that will be the subject of hearings and the NRC staff determined that a supplement to the safety evaluation report is wanted to document their updated safety reviews. As a result, hearings at the ASLB likely will not occur earlier than mid-2012, with further delays possible, given the complexity of the issues and the number of parties involved. In June, we filed notice with the NRC that the New York State Department of Environmental Conservation had not issued a final decision on our water quality certificate application within the 1-year timeframe required by law. The significance of this is simply that if the NRC agrees that a waiver has occurred, then a new water quality certification is not a requirement for the NRC's issuance at Indian Point's renewed license, but it does not change the need to comply with the New York State water quality standards, which are already subject to proceeding on the State Pollutant Discharge Elimination System permit or SPDES, where the cooling tower versus sludge water screen issues are being addressed. Although the SPDES process protects water quality, it is not linked to the NRC license renewal process like the water quality certificate process did. The ALJ's plan to move forward with the joint preceding for both the water quality certificate and SPDES, pending the waiver by the NRC, hearing some several issues are now expected to begin in the fourth quarter of 2011. Written testimony on the first round of issues was filed July 22, so that process is underway. Final decisions by the EEC on these trial matters representing a subset of issues in the SPDES proceedings are estimated up to be 2 years away and it could go beyond that. Like the likely extended timeframe to resolve issues on the Indian Point's license renewal effort, yesterday, we signed a contract extension with Con Ed for a 500 megawatts of capacity in Entergy out of Indian Point units 2 and 3. The terms of the PPA prevent us from sharing all the details. However, we can tell you, date of the contract is in the contingent, and contingent on license renewal for a 5-year term extending through 2017 and contains market-based pricing mechanisms within a predetermined range, committing low-cost energy to Westchester in New York City while allowing Entergy to meet its goals of hedging energy volumes in periods after license, current license expirations. The vital role of Indian Point in the region was clear in a draft report prepared by the Charles Rivers Associates for the New York City Department of Environmental Protection. Key findings of scenarios without the Indian Point included: Higher wholesale electric cost to consumers beginning at $1.5 billion each year and after consideration of subsidies for uneconomic replacements and likely higher -- lower carbon levels, higher costs quickly rise to over $2 billion per year. The loss of 1,100 direct jobs and associated ancillary jobs supporting the plant, substantial grid reliability issues and increased air pollution estimated at 15%, more carbon emissions and 7% to 8% more NOx. Underscoring these results was released by the EPA in early July of its final rule on cost state air pollution. While we cannot say that we completely understand how EPA did its modeling and believe me, we've tried, or that we agree with the results, or the challenges are not likely by a number of parties, this rule is now final. However, based upon where we stand today in our reading of the rule, New York will need to reduce its summer season NOx emissions by at least 44%, assuming purchase of emission offsets in other states, and by 54% without those offset purchases. This summer, ozone fees [ph] in 2010, Indian Point provided over 7 million-megawatt hours of NOx-free generation. New York will also have to reduce its annual NOx and SO2 emissions. Any emissions in excess of allowed amounts in the state could expose the generators to maximum penalties of $37,500 per ton, per day. And I would emphasize that's per ton per day, and that's a big number. And the end [ph] requirements to submit extra penalty emission allowances under the Clean Air Act. We expect the generators will reflect the cost of NOx and SO2 emissions in their bids and also, market prices will increase as a result. Now, summing it up for New York. I know the Indian Point license renewal is of significant interest to everybody. It is certainly to us. We believe the arguments for license renewal are very strong, and are supported by the facts, as evidenced by the water quality certificate filing at the New York State EEC and NRC filing for license renewal. The NRC process also requires that Indian Point obtains a consistency determination in the New York Department of State under the Federal Coastal Zone Management Act. Indian Point will file this application in due course, and we believe the factual case supports, obtaining the CZM consistency determination, especially since Indian Point is an existing facility, not a new one, and since the plant is not seeking permission to change its operations in the coastal zone. Now perhaps because of the significance of Indian Point or maybe because of the proximity of the plant to many of you that conduct business that reside in New York, there have already been considerable rumors, speculations and questions that we typically refer to as kind of inside baseball stuff. There is an unusual amount of digging on questions that typically don't come up until they're much further into the regulatory process when a public record is starting to emerge. Specifically, speculations on the probability of some sort of settlement of the issues that would provide needed direction to both Entergy in operating the plant and the state for long-term energy planning. We agree that it would make a lot of sense for everyone, given the importance of Indian Point to the energy environmental needs of New York and the surrounding areas. As a point-of-view company, we always had a position on the various issues individually or in total and an economic valuation of what makes sense for our stakeholders at any point in time. Protracted litigation is always an option, but due to the inherent uncertainty and the cost, the certainty equivalent between a settlement and protracted litigation produce different results in our analysis, utilizing sophisticated decision risk analysis and statistical techniques and the best judgments of experts in each area. In other words, some sort of commercial agreement among all the parties is always the preferred option. On the other hand, when the parties cannot find common ground, then we are always prepared to not only rely on the regulatory review process to make our case but exhaust court appeals as necessary to secure a fair or reasonable outcome. In Vermont, we went down various paths to achieve a fair and reasonable outcome, but the nonnegotiable demand from the state to shut down the plant in March 2012 despite the NRC license renewal until 2032 gave us no choice but to seek relief in Federal Court. In New York, it is well known, and we disclosed the fact that it's been our process that we offered a number of options to the state in order to meet their objectives and still achieve our business objectives including a more efficient structure to own the non-utility nuclear assets. In the end, the states' demands on Entergy would have been a step backward in terms of our economic efficiency goals compared to the structure we already have in place. We relied on the regulatory process, and as you know, we did not succeed. And we chose not to appeal to the courts in that instance. In other words, our record supports the fact we practice what we preach. We are a dynamic, emphasis on dynamic, point-of-view company and essentially everything has a price, that is everything except our ethics in plating gray areas of the wall like disclosure issues. Having said that, it is neither appropriate nor advisable to discuss any issue related to any dialogue or any what if that is not part of the public record in the various regulatory processes. We will not answer questions on things like whether we have talked to a certain party, the positions of the company on various issues or whether they are negotiable or speculate on other positions or disclose those positions we think we [ph] might become aware of them. Or any other question that could fuel speculation or create mistrust or otherwise interfere with the regulatory process. Like I said, there have already been a lot of questions or observations, that start to feel like almost reverse psychology in order to solicit responses in areas where we have had a long-held policy of not speculating on. I know there will be a lot more misinformation or rumors with the renewal process duration, but to selectively respond to anyone in particular, despite how much we might want to, given the nature of the rumor is a slippery slope that we are determined to stay off. So you're going to get a lot of no-comments on questions in that area. Our no-comment will not stop others from speculating, but it will not fuel those rumors. I just ask that you trust that we always have your best interest clearly in focus, and we have an open mind on how to best protect and promote that. You all love certainly, who doesn't, with the exception of maybe some option traders out there. But unfortunately, we cannot provide that to you today. But we are very early in the process, and to see things typically unfold sometime seems is better. At Pilgrim, we're pleased to report the completion of 2 open items requiring resolution report of the renewal process and renewed license can be issued. First, in June 30. The NRC staff issued the supplement and safety evaluation report completing the additional safety review of the license renewal application. Then 2 weeks ago, the ASLB issued the decision rejecting on re-amp [ph] from the NRC last year, the only admitted contingent remaining before them. An appeal of this rejection by the ASLB is possible, and other late-file contingents remain outstanding. However, the NRC regulations allow for the issuance of Pilgrim's 20-year license renewal, while any appeals for late file contingents are pending. Before closing, I would remind you of the utility's extraordinary effort to respond to winter storms, tornadoes and floods affecting all aspects of operations this year. Efforts include protecting generating units along the Mississippi River from potential flooding, post-monitoring of transmission facilities to keep targeted lines in operation and restoring approximately 216,000 customer outages from multiple storms, primarily in Arkansas and Mississippi. Not only are our employees the best at responding to these challenges, but they did so more safely than ever, with the fewest number of recordable accidents over any 6-month period in the company's entire history. The utility is well prepared and battle tested as we face the peak of the hurricane season ahead. Lastly, in nuclear operations, in May, the Nuclear Energy Institute announced the top -- 2 of the top industry practice awards recognized in safety innovations for 2 of Entergy's nuclear plants. Scrutiny of the safety of the nuclear industry has never been greater and our employees throughout the company continue to show they are committed and up to the task. And now I will 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, an update of our share repurchase program, our 2011 earnings guidance, and then I'll share a few closing thoughts on our long-term financial outlook. Starting with our financial results on Slide 2. Second quarter 2011 earnings were higher than 1year ago at both the Utility and Parent & Other, while they were lower at EWC. Second quarter earnings included accretion from share repurchases, the lower share count is due to the effect of repurchases completed in both 2010 and 2011, including initiation of repurchases against the $500 million program during the quarter. Higher utility results were driven by sales growth across all customer classes, including the effect of warmer-than-normal weather. Overall, retail sales growth on a weather-adjusted basis was also higher than last year, driven by continued strength in the industrial sector. Parent & Other results were higher on the reversal of the tax reserve and at EWC lower power pricing continue to affect results. Turning now to the details driving quarter-over-quarter results. At the utility, Slide 3 shows higher net revenue as 1 factor driving the quarterly earnings increase. Overall, retail sales grew by 2.9% and for the second year in a row, weather was a significant factor. In Entergy service territory, cooling degree days were 38% above normal for the second quarter. The region's temperatures ranked second hottest in the 117 years of available data for the second quarter. Texas and Louisiana temperatures were especially warm, ranking first and second, respectively. And June was particularly warm across the service territory with stations averaging at least 4 degrees Fahrenheit above the monthly norm. Residential sales grew 3.7%, but decreased slightly on a weather-adjusted basis. While the number of residential customers increased to 0.7%, the usage per customer on a weather-adjusted basis declined. The trend of increasing industrial sales continued with 2.8% growth this quarter. Industrial expansions in Texas and Louisiana contribute to about 40% of the total industrial increase, Texas, issuing the strongest growth of all jurisdictions, especially in the industrial sector. Recent reports from the Dallas Federal Reserve Bank noted a positive outlook for refiners and petrochemical companies along the Gulf Coast. Also on a positive note, consumer confidence in the West South Central region, which includes Texas, Louisiana and Arkansas, ranked first in overall confidence among the 9 regions in the United States. These bright spots were partially offset by weakening in small industrials, as well as paper and wood products segments. These trends have affected Entergy Arkansas and Entergy Mississippi, which saw a decrease in industrial sales compared to strong results in 2010. Regulatory actions in 2010 also contributed to this quarter's net revenue increase, including rate adjustments in Entergy Arkansas and Entergy Texas, partially offset by a formula rate plan decrease at Entergy New Orleans. Also contributing to the utilities earnings increase was lower interest expense, more than $1.3 billion of refinancings have been executed at an average coupon of 4.6%, a decline of over 100 basis points. As of June 30, the weighted average coupon rate for the utilities debt portfolio was 5.6% or 30 basis points lower than last year. Moving on to EWC. The quarter-over-quarter decrease in operational earnings was due primarily to lower net revenue and a higher effective income tax rate. Net revenue for EWC's portfolio declined as the result of lower energy and capacity pricing. For the EWC nuclear fleet, the average realized price for the second quarter of this year was $52.38 per megawatt hour or 9% lower than last year. Capacity pricing has also declined over the last several years due to low demand conditions, driven by recession, coupled with a degree of energy efficiency programs success and high levels of demand response. The collapse has been most severe over the last 12 months in New York. For example, monthly spot prices in New York's rest of state zone, ranged from $0.15 to $0.65 per kilowatt month in the second quarter this year, compared to $0.64 to $3.52 a year ago. The August spot auction for New York rest of state came out a few days ago, at just about $0.05 per kilowatt month. A major driver that has affected New York capacity market over the last 2 months, and which will continue to affect in-city and the rest of state prices unless otherwise resolved has been the addition of roughly 550 megawatts from the story of 2, but has not been mitigated as expected. There has been some discussion about creating a new capacity zone in New York for the Lower Hudson Valley area. Potentially by the summer of 2014, such a development could improve capacity pricing for our Indian Point units longer term. Other help in the capacity markets will likely come over several years from retirement of certain generators that currently rely heavily on capacity revenue, and were facing increased environmental compliance costs going forward. Also, these little capacity values may drive a retrenchment of load response programs or at least slow their growth. System load growth remains a wild card, but there is some possible upside compared to New York's current load forecast, which are projected to remain below 2010 levels until 2014. Operationally, the nuclear fleet produced a 91% capacity factor slightly higher than the second quarter last year. This capacity factor improvement is due to 8 fuel refueling outage days this year. Non-refueling outage days were comparable quarter-over-quarter. A higher effective income tax rate at EWC also contributed to the lower earnings. In May, the State of Michigan enacted legislation that repealed its business tax, replacing it with a corporate income tax. The new tax law, which will be effective January 1, 2012, eliminates the future deduction, which was available for certain book and tax differences. Given that this deduction was no longer available, EWC wrote off the related deferred tax asset. Finally, Parent & Other results were higher this quarter due primarily to lower income tax expense on parent and other activities. The lower tax expense is attributed to the reversal of the tax reserve, which results from a settlement of an uncertain tax position. Our 2011 guidance assumes a 35% effective income tax rate and the tax reserve adjustment recorded this quarter is consistent with that guidance assumption. Moving now to Slide 4. Entergy's operating cash flow performance for second quarter this year reflected a decrease of approximately $140 million compared to the second quarter of 2010. This decrease, in OCF was driven mainly by 2 factors: Lower deferred fuel cost collections and the previously discussed decrease in Entergy's wholesale commodities net revenue. I'll now turn to an update on our share repurchase program as reflected on Slide 5. During the second quarter, we completed roughly $105 million of share repurchases. We purchased a total of 1.4 million shares at an average price of $68 per share. About 75% of the repurchases were made through the existing $500 million board authorized program. The balance was repurchased to offset the dilutive effects of grant exercises. At the end of last quarter, $425 million remained on the existing $500 million program. Consistent with past practice, decisions on whether to buy back stock will be based on a number of factors, including current business conditions and investment needs, our liquidity and financial flexibility to quickly respond to changing conditions or opportunities particularly since we are approaching the peak of hurricane season, and our point of view on the value of our stock. Slide 6 details our current 2011 earnings guidance, which ranges from $6.35 to $6.85 per share on both an as-reported and operational basis. The guidance range remains unchanged from the numbers we initiated last October. As we assess our earnings performance to date, we believe we have made good progress through the first half of 2011, and earnings have benefited from favorable weather. Consequently, we are well positioned relative to our full-year guidance range. For the rest of the year, efforts will focus on continuing to produce positive financial results through strong operational performance. Consistent with our past practice, we normally will affirm or revise guidance on a quarterly basis, and will revise guidance only when we see factors that move our expectations outside of the overall range we have previously provided. In closing, I'd like to touch on 2 topics. First, I'll make a few comments about our EWC sold forward table in the release, then I'll touch on our long-term financial outlook, looking ahead to next year and beyond. On Slide 7, we've summarized information from our EWC nuclear sold forward table on Page 5 of the release. This quarter, we have included a range for the average energy contract revenue per megawatt hour, rather than a specific price point. The range takes into account contracts with the collar, like the recent extension of the power purchase agreement with Con Ed that Wayne mentioned earlier. The lower end of the range reflects contract floors and the upper end, contract ceilings. At the bottom of Table 6, the average contract revenue per megawatt hour, which includes both capacity and energy revenues, reflects the price that the contacts would settle, assuming current forward market prices. Slide 8 outlines key aspects of Entergy's long-term financial outlook. Starting with the utility, we continue to see the long-term growth outlook consistent with the 6% to 8% compound average growth rate through 2014 off the 2009 base year net income. One thing to note is the changes in utility net income can be lumpy due to several factors, including weather and sales growth, timing of capital investments and regulatory actions. All of these items do not occur evenly from year to year. For EWC, we expect declining revenues as price trends for energy and capacity play out over the next few years in both sold and unsold volumes. As we outlined in Table 6 in the release, assuming current contracts and forward markets for EWC nuclear output, average prices decrease in 2012 and again in 2013 before recovery starts in 2014. Long-term EWC offers a valuable option on positive effects of ongoing economic growth and environmental regulation. Parent & Other can vary from year to year. Parent interest expense depends on the label of borrowing, as well as the cost of debt given the range of possible private and public financing options and the timing of their execution. An income tax expense can fluctuate with resolution of unresolved income tax issues. Our capital deployment philosophy focuses on maintaining a balanced investment and capital return program. Our capital plan includes expenditures to support continued safe and reliable operations, as well as value-added productive investments. We also plan to maintain a capital return program, which includes common stock dividends and share repurchases. Our current long-term outlook remains to return up to $4 billion to $5 billion to shareholders from 2012 through 2014. As we move into the next quarter, we recognize that many of you will continue to fine-tune your estimates for the coming year and beyond. In that regard, we have provided additional details on key business drivers in the appendix of this webcast presentation. Our overarching aspiration remains top quartile total shareholder return. Conditions in the commodity markets in the interim, uncertainties for the full agenda of strategic initiatives that Wayne reviewed earlier, have left us well short of these aspirations in recent years. Nevertheless, the management team continues to focus on delivering results that will create tangible long-term value we can return to you, the financial yardstick of our success. To that end, we will continue to focus on safety, operational excellence, risk management and disciplined capital deployment to maximize the value of our company. And now, the Entergy team is available for your questions.

[Operator Instructions] We'll go first to Paul Patterson from Glenrock Associates. Paul Patterson - Glenrock Associates: On the water permit, if the NRC doesn't agree to the waiver and if the water permit actually is denied, what would be the next steps? J. Leonard: I'll let Rod West take it.

If the water permit is denied by the State of New York, the remedy available to the company would be to appeal it. Paul Patterson - Glenrock Associates: And can the plant operate, I guess, while that's going on? I mean, I guess, that's the case with Vermont Yankee. If you guys -- if the case doesn't go your way in Vermont or New York, while it's under appeal, these plants can still operate, is that right?

Right. And a particular note, I'll make note of the term, the timely filed doctrine that allows the plants to continue to operate assuming that the facility has sought relicensing from NRC at least 5 years prior to plant expiration. And in the case of New York, our point of view is that, that timely filed doctrine would apply that will allow the plant to continue operating, while we are resolving issues you just raised. Paul Patterson - Glenrock Associates: Okay, great. And then just on the capacity markets in the Northeast. We've seen Astoria in Ravenswood file for emergency -- I don't know, a petition to FERC, I guess, to basically have market mitigation buyer side, market power mitigation. And we're seeing efforts in New England by generators to do the same. Do you guys see the potential for, I guess, ISO activity to potentially raise the capacity market by going after these out-of-market revenue generators?

Yes, Paul. I mean, we're part of many of those proceedings, both as a member of the ISOs, but also, at FERC. So I think it's going to play out over the next year or so, both within the ISOs and then also eventually at FERC. And in fact, you've seen preliminary rulings coming out of FERC on PJM on the same issue. Paul Patterson - Glenrock Associates: Right. So what kind of -- can you give us an idea about what you think might happen in terms of capacity pricing in the Northeast as a result of this? Any sense? I mean, I know it's kind of foggy right now, but...

Well, I mean, if the mitigation takes place, I mean as Leo went through the details of what's going on in the quarter, and both of those markets -- I mean, the prices are depressed. So with the market mitigation, they are anywhere from 75% to 80% of what their new built cost is, is what they have to bid into. So logically, that's going to increase those capacity prices. Paul Patterson - Glenrock Associates: Right. And any sense as to how much maybe? Or is that too preliminary?

I think it's too preliminary.

And we'll move next to Daniel Eggers from Crédit Suisse. Dan Eggers - Crédit Suisse AG: Without trying to pin you down on your kind of questions you won't answer, are there some external data points we should be following as far as New York's concerned, maybe the monitor discussions you're having or the process outside of your kind of the more obvious New York decisions on the water permit? J. Leonard: Well, there will be. But I think having the water quality permit, as we're saying today -- is probably about as maybe front and center as far as options or direction that we may go ahead going forward. Again, I hesitate to get into it. It's still in the process. For reasons that I just outlined, and I apologize, I can't at this point, but it just wouldn't be advisable. But I'd say on the water quality permit and in particular, the issue there that we just discussed while it's not approved, the question there that you have to keep in mind is, is it headed toward a conditional approval or rather than rejection, putting cooling towers, versus flat rejection or condition upon something else. And I'm just following those hearings versus making assumption that it's an up-or-down rejection or proceed. Other than that, I'm not sure I can help you at this point. As time passes, we'll keep you updated with those things that we feel comfortable commenting on that are part of the public record, but today there isn't much. Dan Eggers - Crédit Suisse AG: Okay, that's fair. And then just on the hedging philosophy right now, there's a big step-up in your percentage of generation that was sold for 2013 with the contracting. How should we think about kind of the strategy on filling out '13 and maybe looking out at '14 to '15, what you guys would expect as far as selling more of that power output?

Dan, this is Leo. We're pretty comfortable with the levels we are right now. We're going to continue to execute on the hedging strategy based on the limits we put in place and our point of view about around the market. Obviously, we have limits that are based on things like financial policy and liquidity and credit ratings and the like. And we're in pretty good shape where we stand right now for where we want to be. We've had to spend a lot of time figuring out the right way to hedge going forward. As Wayne mentioned, the idea of hedging out beyond the current licenses is one that we have to make sure that we put additional risk management structures around, and we do that first before we make any transaction decisions. But right now, we'll really be just basing it on what our point of view is, going forward in the markets, and where we think things are going to go. Dan Eggers - Crédit Suisse AG: And just to make sure, so the -- the out year numbers, the '14, '15, those hedge pieces are effective in the Midwest plants plus kind of the Indian Point contract with Con Ed, is that a fair representation of mix of what's captured so far?

Yes, majority, yes. Dan Eggers - Crédit Suisse AG: Okay. And just one last question, just on the Cooper plant, is there any exposure to you guys, given the flooding issues there as far as maybe additional spending or impact on payments they make to you guys running the plant? J. Leonard: Gary?

Yes, Dan. No, there's no impact. The plant did very well during the flooding issue and we're continuing to watch, actually, the river has already crept. It is already declining, and the plant actually did very well, so we don't see any impact there.

And we'll take the next question from Ashar Khan from Visium. Ashar Khan - SAC Capital: Leo, if I want to go back to the slides that was in your guidance for this year, there was a $0.62 negative variance for the weather. And so based on what you provided in the release, you're up like $0.02, if I'm right, on weather year-over-year. So I'm I correct, we are running nearly like -- based on what you provided last year, for this year, we're running like $0.64 ahead as we stand on weather for 2011 versus '10 as a positive thing?

Well, we haven't done third quarter yet, Ashar. So third quarter is really kind of, as you know, for us, given the location of our service territory, third quarter is a big quarter for us. Make or break us either way. We can have weather that's below normal cooling degree days or above normal cooling degree days. So yes, we're running pretty comparable to where we were last year, which is a pretty big year both in the winter and the summer, but until we get through the third quarter, I wouldn't declare weather closed in the books yet, one way or the other. And obviously, we always go back at the end of the year when we get ready to do next year's guidance, and we'll adjust acting on the weather for next year as well. Ashar Khan - SAC Capital: And my second question, if I can ask, what was -- can you -- what was the average purchase price for the shares that were purchased in the second quarter?

About $68.

Our next question comes from Steven Fleishman from Bank of America. Steven Fleishman - BofA Merrill Lynch: A couple of questions. Is there any sense of timing or schedule on the NRC ruling on your water permit filing? J. Leonard: All right, Chuck.

Steve, this is Chuck. No. There's really not -- there's not any pressure on the NRC to make a ruling on that really until they get much closer to the actual ruling on our license renewal application. Steven Fleishman - BofA Merrill Lynch: Okay. This is the waiver issue, correct?

The waiver issue for Indian Point. Steven Fleishman - BofA Merrill Lynch: Will they take comments and other stuff as part of that, so we'll know there's a process? Or will it just suddenly come out one day?

I don't know the answer to that. We've made our filing. There had been responses filed with the NRC by the DEC and by the River Keeper. But what their process going forward will be, we really have not been informed. Steven Fleishman - BofA Merrill Lynch: Okay. And then, Wayne, I'll do my best to try and interpret what you're trying to say, but maybe I kind of read it as you were just going to hear a lot of things over this period and hearing a lot of things early on. I guess, one thing, you're trying to say, look, if in the end it makes sense for shareholders to settle on issues, just to let us know that you're going to be looking at what's the best risk return option, I guess. J. Leonard: That's right, Steve. And you're very plugged in as you always are to a lot of these rumors. And I think what's really kind of precipitated a lot of this is, it would make a lot of sense, I mean, for both parties to come together. And it was something that will give directions and stay in direction to us. Obviously, that makes sense. In the process of posturing, sometimes things get into the press that are just not true or whatever and we can't comment on those kind of things. And then in the process of trade presses and others trying to get more information, as you've seen, there are rumors, speculations that have been leaked us back and postured or we've been positioned as not willing to consider certain things, and that's not true. I mean, as you've known over the years, we've spent -- some people in this room, have spent careers at negotiating tables. Sometimes it's turned out well and sometimes we have had deadlocked, but that is our preferred position. And in this case, it would be a preferred outcome. But it has to make commercial sense. And I guess the point that we're trying to make is just a -- not a warning, we don't need to warn you all, but just -- there will be a lot of things out there that just aren't true. And we would like to respond to them, but that will only get -- Like I said, create distrust among a lot of parties, and we don't have the best record in New York, already coming out of an excess [ph] spin in terms of trust, and things of that nature. And we're trying to rebuild that and commenting on these rumors, they always -- the words get turned around and things and we're going to stay away from that. But we are -- like you kind of described, we do continue to develop scenarios that would be in the best interest versus protracted litigation and we're open to ideas in any of these processes. Then hopefully, it won't have to go the whole nine innings here. Steven Fleishman - BofA Merrill Lynch: Okay. One last quick thing, I guess, for Leo. Just on the data on the hedges with the collars. You might have said this and I missed it, but a current forward or something like that, would you be at the low end of the collar on these? Or...

They'd be probably in the middle end of them at the moment. Steven Fleishman - BofA Merrill Lynch: Okay. So probably the best thing is to assume middle and then if things get a lot better it's higher and if things get worse, it's lower.

Correct. But if you look in the table, where we get down to the bottom of that table, where we put in the percent sold on the total revenue basis, it's got capacity and energy in it. The energy portion of that is at what we would settle at today if it was the forward curve. In that bottom section of the table, where we present percent sold on a revenue basis, that includes all of the revenue, including capacity. That estimate is a single point and that single point is used in today's forward curve to settle point.

And we'll move next to Julien Dumoulin-Smith from UBS. Julien Dumoulin-Smith - UBS Investment Bank: Firstly, to follow up on the questions on the nuclear side. The ASLB had previously issued a release suggesting it anticipated resolving the Pilgrim renewal by the end of July 2011. Is there any new comparable date we should be looking out for? Is there any kind of defined or prescribed timeline at this point in the process? J. Leonard: Rod?

Currently, end of year 2011. Julien Dumoulin-Smith - UBS Investment Bank: Great. And then secondly, could you comment briefly on your efforts to renew the FRPs in Louisiana, changes that you suggested that could be a potential new rate case filing in the state? J. Leonard: Okay, Gary?

Yes, we made our last filing for this 3-year term with the FRP in May and those rates going into effect in September. And so at this point, we will continue to work with the staff. We intend to work to continue those FRPs and renew those for another term. They've been very efficient, they work well for our customers and for owners. Julien Dumoulin-Smith - UBS Investment Bank: So you would anticipate resolving the FRP renewal by September or in the next couple of months?

Really, they're 2 different issues. If you look at the filing that rates went in will go into effect in September. So we will need to obviously have that approved by the LPSC and our intent to resolve the FRP as far as renewals hopefully by the time we would re-file in May of next year. Julien Dumoulin-Smith - UBS Investment Bank: Great. And then thirdly, can you just quickly discuss the potential for a Texas rate case in light of the latest legislation, et cetera?

Yes, if you look at Texas and in all of our jurisdictions, I mean, one of the fundamentals in our plan is that each of our businesses earn their authorized return. The average in Texas, as Wayne talked about, it's come to fruition, especially the capacity rider will help us do a lot of that. The capacity rider may require us to require to file a base rate case just to set the baseline. We've already done that for transmission and we proactively already did that for distribution in our last rate case. Although we look significantly at, where that is, that's the biggest pressure on it, and depending on where they are with relation to ROEs and whether we get these riders done, will require whether or not we file a rate case, which we can do each year in Texas.

We'll take the next question from Michael Lapides from Goldman Sachs. Michael Lapides - Goldman Sachs Group Inc.: You've talked at length about cross-states rule and the impact on the non-regulated side. Just curious, how are you thinking about what it means for the regulated side of the business in terms of potential rate base growth opportunities in terms of your Arkansas coal plant that may need scrubbing, et cetera? J. Leonard: Okay. This is a complicated question. I'm going to start with -- let Rod talk about kind of how it affects spend side, and I'll let Gary, follow up specifically on how we're thinking about how it affects the business plan.

Good. The first part of the tag team is we're assessing the impact on the rule. Obviously, the issues for us stem around timing, where the EPA prior to what we knew was the transport rule before this funding by the EPA had -- we were assuming a 2014 effective date. We've now moved up under the rules to 2012. That certainly had an impact. And then when you combine the notion of allowances, all of those affect our perspective cost of compliance. And certainly, the fines. On the regulated did side of the fence, which Gary can talk to, obviously, there are assumptions made by the EPA regarding the retirement of plants in our regulated space quite candidly that are needed, whether it's reliability purposes, transmission of baseload, load following, ready, much-run designation. And there's a lot that we have to do to try and assess where that is, and it's a dynamic process for us. We're just not at a point right now, where we're taking a firm company point of view, because we ultimately have to determine what this means for our customers, and that's an iterative conversation with the regulators. Gary?

Well, I'll actually, cover it, Michael, probably in 2 parts. The first, is really, there's mechanisms for environmental cost recoveries, the SOx and NOx in each of our jurisdictions. In the case of EGSL and NOI, there are environmental adjustment riders that are available to cover those costs, as well as through Arkansas post service, the APSC and the NPSC, and the public utility commission, Texas, all that's recovered through fuel. The rule is new, is I think what you just heard from Rod and changed significantly from what we saw and expected in 2014. So we are in the process of actually evaluating what would have to be done to each of those plants. In each case, there are technological solutions that would require some capital investment. We've not gone far enough down the rule, this road to really say what those are. We knew what they were going to be. We didn't think they will be significant as it existed under 2014, and what was the proposed rule. We believe though, our initial look, we're looking forward to it that we would still be able to make those investments. As Rod, said those plants are reliability much run and I think we're going to be able to do that and in a cost-effective way. But I think that's going to be more evolved as we're studying it right now because it's fairly new.

We have no further questions at this time. I'd like to turn the conference back to Ms. Paula Waters for any additional or closing remarks.

Thank you, and thanks to all for participating this morning. Before we close, we remind you to refer to our release and website for Safe Harbor and Regulation G combined statements. Our call is recorded and can be accessed for the next 7 days by dialing (719) 457-0820, replay code 8424061. This concludes our call. Thank you.

And again, that does conclude today's presentation. Thank you for your participation.