Paula Waters - Vice President of Investor Relations J. Wayne Leonard - Chairman, Chief Executive Officer and Chairman of Executive Committee Leo P. Denault - Chief Financial Officer and Executive Vice President Theodore H. Bunting - Group President of Utility Operations

Steven I. Fleishman - BofA Merrill Lynch, Research Division Dan Eggers - Crédit Suisse AG, Research Division Greg Gordon - ISI Group Inc., Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Paul Patterson - Glenrock Associates LLC Michael J. Lapides - Goldman Sachs Group Inc., Research Division Stephen Byrd - Morgan Stanley, Research Division

Good day, everyone, and welcome to the Entergy Corporation's Second Quarter 2012 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.

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, our CFO, will review results. [Operator Instructions] As part of today's conference call, Entergy Corporation makes certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve a number of risks and uncertainties, and there are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these factors is included in the company's SEC filings. Now, I'll turn the call over to Wayne. J. Wayne Leonard: Thanks, Paula. Good morning, everyone. I'll start today with one of our key initiatives. The proposal for the utility operating companies to join the Midwest Independent Transmission System Operator or MISO. In May, the Louisiana Public Service Commission became the first retail regulator to approve, subject to certain conditions, the proposal by Entergy Louisiana and Entergy Gulf States Louisiana to transfer functional control of their transmission facilities to the MISO Regional Transmission Organization. MISO change of control proceedings are in various stages of progress of the retail regulators in Arkansas, Mississippi, New Orleans and Texas. During the second quarter, the Arkansas Public Service and General Staff modified their position such that Entergy Arkansas should continue to progress toward joining MISO and when certain conditions are met, the APSC will grant the full change of control. An order from the Arkansas Public Service Commission could come at any time now. Testimony has been filed in the remaining 3 jurisdictions and subject to various conditions. Commission staff, all the advisers and intervenors in each proceeding generally have been supportive of or, at least, have not expressed opposition to joining MISO, with the exception of course, of the Southwest Power Pool. We believe we should receive all the retail commission orders on MISO in 2012. Given this progress, final preparations were underway now to initiate the regulatory approval process for the proposed spin-off and merger of the Entergy operating company's transmission business with ITC Holdings Corp. The retail regulatory filings will describe on both a qualitative and a quantitative basis. The benefits to customers and other stakeholders resulting from the superior independent model for transmission operations that ITC provide, as well as the improved financial flexibility and strength of the Entergy Utility operating company following the completion of the transaction. We expect to make the initial filings in Louisiana, followed by filings in other retail jurisdictions at the Federal and Energy Regulatory Commission over the next few months. Concurrently, a fully functioning project management office is mapping out the process as activities and plans for the targeted 2013 closing to ensure a seamless transition. In other Utility developments this quarter: Administrative Law Judges here in the Entergy Texas rate case issued their proposal for decision early July. ALJs recommended an overall $16.4 million base rate increase. However, the staffs' working papers that were used by the ALJs indicate an approximate $28.3 million retail base rate increase. Further, the ALJs recommended a 9.8% allowed ROE. This compares to the adjusted $105 million base rate increase, an ROE of 10.6%, that was requested by Entergy Texas. We should note the recommendation affirmed in full, Entergy Texas passed fuel costs and made no adjustments to $408 million of the capital additions or over 99% of affiliate costs. That is, the ALJs are not saying you are ineffective, inefficient, or improved. Instead the ALJs recommendation results from while we believe our misapplications of basic regulatory principles and practices and these misapplications undermine the traditional rate-making process and public policy objectives. The end result makes it impossible for Entergy Texas to earn a fair return, and that is a clear violation of some of the oldest, tested and affirmed principles of the regulatory law, no matter how you can get there. And particularly, we believe certain adjustments are clearly without basis or merit. For example, approximately $30 million of purchased capacity cost incurred after the end of the test year within the allowed pro forma period when those rates will be in effect, were suggested out with a sort of hyper-technical rationale that is at odds with the purpose of the regulation. I won't go through all the disagreements we had with the ALJs recommendation, but we strongly believe this is a fundamental misapplication of long-standing regulatory rules and practices in Texas, which provide for recovery of known and measurable costs. Under the ALJ's proposal, these nonfuel costs could not be recovered for up to 2 years, as the time it takes to prepare and complete another rate case that includes a full year of the cost to be reflected in the test year itself. And if the timing isn't perfect between the test year and historical cost, they may never be recovered. That is why it is common practice in Texas and elsewhere to utilize pro forma adjustments to the test year to eliminate discrepancies, particularly when you don't use a formula rate plan or have extensive use of riders. Regarding regulatory decisions that discourage prudent capacity purchases that didn't pick us from [indiscernible] for the development of a robust efficient wholesale market if it's allowed to stand. A public utility must be afforded the opportunity, not only with showing its financial integrity but it can maintain its credit-rating and attract additional capital as needed, but also of achieving returns on investment comparable to those of other companies having corresponding risk. This is the law of the land, and it is without argument. And ALJ's recommendation fails to acknowledge, in any way, how this proposal lines up against that basic litmus test. The PUCT is scheduled to take up the proposal for decision making at the August 17 meeting. It is expected the final decision will be made at this meeting or by the next meeting on August 30, at the latest. Entergy Texas has several other remedies available if the PUCT does not reverse the ALJ's recommendation. Options include: Continuing to pursue the open rule-making docket to establish a rider to recover capacity cost. Filing for the authorized transmission and/or distribution riders to fully recover incremental investment costs above baseline set in the case, preparing to file another base rate case if adequate recovery is not achieved in its proceeding and, of course, seeking relief through a legal process. In Louisiana and New Orleans, annual formula rate plan filings were made in May. The Entergy New Orleans 2011 test year FRP filing reflected earnings below the bottom of the bandwidth, indicating the modest increase in electric and gas rates totaling approximately $4 million. Entergy New Orleans also requested to accelerate funding of its cash storm reserves to allow to meet the $75 million target by 2017 that was established by the city council. Under the FRP tariff, new rates will be effective in the first billing cycle in October. This year's filing follows 4 straight years of rate decreases in New Orleans. Even with these file changes, electric rates for Entergy New Orleans customers will be nearly 20% below 2011 levels across the country for non-hydroelectric utilities. Furthermore, rates for New Orleans customers will be among the 5 lowest in the country after factoring in a reasonable price for CO2 as a proxy for climate risk across the country. The same general profile holds true for the rest of the operating companies, explained, in part, the strong economic development activity in our region. The earned return reflected in the 2011 test year FRP filing for Entergy Gulf States Louisiana was above the bandwidth indicating the cost of service decreased to $6.5 million. In addition, the company is requesting adjustments outside the FRP primarily for lower capacity costs. At Entergy Louisiana, the FRP filing reflected 2011 earnings consistent with the bandwidth, and therefore no cost of service adjustments are necessary. While Entergy Texas earned within its bandwidth, Entergy Louisiana earned within its bandwidth pursuant to the terms of the FRP, the company is requesting rate adjustments outside the FRP for capacity cost for PPAs not covered under the fuel cost. Both FRP filings with the LPSC are under review now, and the FRP would require rate changes to be effective in September. In addition, Entergy Louisiana's recent FRP filing was supplemented to include the estimated the first year impact of the Waterford 3 generator replacement project. Consistent with the previous LPSC order, rates will be updated upon completion of the project subject to a standard prudence review. The Waterford 3 project continues to meet provided milestones to achieve the planned end of 2012 in-service date. In early July, the steam generators arrived on site. They are ready for installation during the fall refueling outage. This Waterford 3 project is the second major capital project for the nuclear organization this year. In the spring, extended power outage project was installed at Grand Gulf during its refueling hours that concluded in June. Plant personnel are on the process now of increasing production after achieving the Nuclear Regulatory Commission's approval to operate at the higher power levels of 178 megawatts. This 15% extended power upgrade will make Grand Gulf the largest single unit nuclear plant of its type in the country. One last comment relative to generation initiatives. In July, the APSC approved Entergy Arkansas's request to acquire a hot spring power plant to set a special rider to recover the cost at the 10.2% ROE established in the most recent rate case. This follows the first quarter 2012 certification by the Mississippi Public Service Commission for Entergy Mississippi to acquire the Hinds plant. A federal proceeding on retail cost recovery remains pending in Mississippi. Closing of the acquisition has been delayed pending the U.S. Department of Justice review. We do not know where the DOJ is with its review of the transaction or to the extent which its review has been or will be affected by the ongoing civil investigation of competitive issue of the Utility operating companies. The confidential nature of the DOJ review of the transactions and the civil investigation do not allow me to comment beyond the fact that reviews are ongoing. However, I can repeat that we believe the operating companies' practices and policies and issue have satisfied all of applicable laws and regulations. In other Utility matters, last month, the FERC issued a decision in the Entergy Arkansas opportunity sales case. As a reminder, this case consumes a limited amount of short-term wholesale energy sales, less than 1/2 of 1% of the total system sales to third parties from 2000 to 2009. The FERC found that the sales in question were allowed under the system agreement and made and priced in good faith, but disagree with after-the-fact accounting used to allocate the energy to supply those sales. We believe our actions were consistent with the system agreement and as such have filed for rehearing last week. The FERC also set for hearing a separate proceeding to determine a reallocation of cost among the operating companies consistent with its decision without completing the voluminous necessary calculations, and therefore, cannot quantify the effects of the reallocation on individual operating companies at this time. We may not have a final FERC decision on this matter until 2014. At Entergy Wholesale Commodities. The NRC renewed Pilgrim's operating license through 2032 in late May about 2 weeks before the original license was scheduled to expire. The decision by the NRC came after an extensive and rigorous review spanning a 76-month period, where the NRC spent more than 20,000 hours conducting inspections and reviews and soliciting active stakeholder participation. The stated goal of the NRC is to complete these reviews in 30 months. While the Pilgrim license renewal was the longest to date, it is almost certain to be surpassed by the Indian Point process given the number of issues and parties involved. We filed a 20-year license renewal applications for Indian Point units 2 and 3 in April 2007. The application day was more than 5 years before the expiration of the current operating licenses in September 2013 for Indian Point 2 and December 2015 for unit 3. And as such, meets the standard for the NRC's timely renewal provision, which allows continued operation until the NRC takes action on the applications. Current progress certainly points to timely renewal protection being applied for Indian Point 2 next year and likely for Indian Point 3 as well. Since 2007, the United States issued a required safety evaluation report in 2009 and a supplemental environmental impact statement about a year later in 2010. Both these safety and environmental reports issuance of the 20-year license renewal. Supplement to these 2 reports are to be expected as the regulatory guidance council, the NRC's ongoing oversight, as well as when open issues are resolved. Safety report was first supplemented in August of last year and another supplement is expected to be finalized by year end. Around that time, we're expecting the finalized first supplement to the environmental report. We do not expect any of these supplements to change NRC staff's conclusion, but there are no safety or environmental issues, which would preclude the Indian Point units from operating safely for another 20 years. The next milestone in the NRC process is the initial hearings before the Atomic Safety and Licensing Board scheduled to begin in October. To date, the ASLB has submitted a total of 16 contentions, the most ever in a license renewal proceeding, and the ASLB is on track to hear possibly 3 to 4 times more contentions than have ever been heard in a license renewal proceeding. Two contentions have been resolved; 1 in the settlement, the other in the commission order. Ten of the 14 remaining contentions are slated for the track one hearing this fall. No final schedule has been set for the remaining 4 issues. NRC process allows for additional contentions to be filed after issuance of these supplemental reports or after any new maternal information comes to life. And as we've experienced the Pilgrim and Vermont Yankee, new contentions may be filed even after the records closed. I won't go over all the details of each contention, that would, well, take more time than you've got here today. But suffice it to say, these are complicated technical issues that take time to fully investigate, resolve and document. The key takeaway from all these discussions is that the nature of the rigorous process before the NRC indicates that it will be years until we reach final decision before the commission. In conjunction with the NRC process, we also need resolution on the water quality certification issue associated with the Clean Water Act and the Coastal Zone Management Act consistency determination. On the first issue. Last year, we filed notice with the NRC that the New York State Department of Environmental Conservation or DEC had not issued a final decision on our water quality certification application within the 1-year time period that is required by law. The NRC has not ruled on our filing, but if they agree that a waiver has occurred, then a new water quality certification is not a requirement for NRC's issuance at Indian Point's renewed licenses. In any event, however, Indian Point must comply with New York water quality standards to the proceeding on the State Pollutant Discharge Elimination System Permit or SPDES. The department's ALJs have combined the water quality certification and SPDES issues into one joint proceeding, now hearing that case in parallel with the NRC review of the waiver issue. Periods before the ALJ for the New York State DEC will resume this week regarding the best uses of the Hudson River and on the efficacy of performance of the Wedgewire screen proposal that we've made. These are just 2 of several issues in the water permitting certification proceedings. But the central issue is the evaluation of what is the best technology available or BTA. Operations with cooling towers or operations with our proposed Wedgewire screen alternative? And either of these options is required, only if Indian Point is creating an adverse environmental impact. A point on which we obviously disagree with the state and then we have preserved from further litigation at a later date. Portions of these proceedings date back to 2003, when the New York State DEC issued a draft SPDES permit and proposed license renewal periods suggesting cooling towers are BTA. Since then, we filed expert testimony on how cooling towers don't meet the BTA standard for a host of reasons, including that is highly unlikely that cooling towers can even gain the required air permit or approval by local governments due to zoning and other permitting issues. And furthermore, it is difficult to see how cooling towers could pass any reasonable cost-benefit test compared to Wedgewire screens, which the U.S. Supreme Court has ruled and be considered as an element of determining best technology available. Staff of the New York DEC has not yet filed its primary report, or the basis for, why they regard cooling towers has BTA and no dates for hearing have been set for this threshold BTA issue to be argued in the sunshine before the assigned judges. As it stands today, we would expect these water quality proceedings to extend into, at least, 2013 and possibly well beyond that. One last issue to report on water report. The first gate under the law on water quality issues is whether Indian Point's operation has environmental impact on the Hudson River. While the ALJ's declined to hear this argument in this proceeding, it is fully supported by our research and evidence and ready to be presented on appeal to cooling towers somehow prevail in the joint water quality proceedings. Secondly, and I know all of this starts to blend together over time as you hear this, but this is new and it's certainly not trivial, so you might want to listen carefully. Last week, we filed with the NRC a supplement to the Indian Point license renewal application related to the state of New York's requirement or Coastal Zone Management consistency determination under the federal Coastal Zone Management Act or CZMA. The supplement states that federal regulations make clear given previous reviews of the Indian Point facilities, there is no need for a further states CZM review, and as a result, the NRC may issue the requested Indian Point renewed operating licenses without the need for an additional consistency review. And let me amplify that point. Hang on just a second. Sorry I've lost about 10 pages of my script here. So let me amplify that point. The preamble to the federal regulations implementing the CZMA state: In the event the state agency has previously reviewed a license or permit activity, further review is limited to cases where the activity will be modified substantially causing new coastal zone effects. Exception does not apply in the case of Indian Point since no change in operations has proposed for purposes of license renewal. Prior CZMA consistency reviews were done for units 3 and unit 2 in 2000 and 2001 respectively by the New York Power Authority and Con Ed transferred ownership for the plans to Entergy. In both instances, the state of New York determined that operation of the Indian Point facilities was consistent with the case state coastal zone management plan. Based upon these and other prior reviews, and the fact that it's part of the license renewal proceedings, Indian Point's continued operations will not be substantially different than when the prior reviews were conducted. We do not believe CZMA requires Indian Point to obtain another consistency review from the state of New York in connection with its license renewal applications. To that end, yesterday we filed with the ASLB a motion for declaratory order agreeing with our position. Responses by parties, including the State of New York, to our ASLB motion are due within 10 days, although extensions are possible. We expect that once the parties have stated their positions, the ASLB will set a process, resolve the issue and issue a decision. ASLB decisions are appealable to the commissioners, but it's not appealed, the decisions are filed. In summary, we've made clear our position supported by the expert opinion regarding the law and the consistency of prior reviews conducted at Indian Point, that there is no basis to require a CZM determination as part of the license renewal process. How and when the processes will advance from here will be determined by the ASLB. It's important to keep in mind, under federal regulations, the NRC is the ultimate decision-maker and when the changes have been made, they'll want additional review. As a reminder, the federal law also states as national policy, the preference for continuing to use already developed areas, again, like Indian Point facilities into developing new greenfield areas within coastal zones. And furthermore New York state's federally-approved coastal management program, sites, location of nuclear facilities in the coastal zone, including the Indian Point, as demonstrating the state's recognition of the national interest of Entergy facilities. Regarding that last point, there is a good reason why Entergy point serves the national interest. Indian Point is safe, secure and vital. It's the only plant in the country that voluntarily submit to an extensive blue-ribbon panel audit, which we passed with flying colors in 2008. The preclusion of the panel of experts was unequivocal. Indian Point is a safe plant. Before closing, I want to highlight a few recent awards recognized and the operational strengths of our organization. In a report issued by J. D. Powers and Associates earlier this month, all of Entergy's Utility operating companies showed gains in the 2012 electric utility residential customer satisfaction study. In fact, Entergy New Orleans was named the most improved Utility company. This contrast to the results overall where the national customer satisfaction index declined by 3 points, the second consecutive year of decline. The key factor for the industry, of course, was the negative impact on perception of power quality and reliability due in part to severe storms that affected several parts of the country. In May, nuclear operations once again received Top Industry Practice Awards from Nuclear Energy Institute, for innovative improvements in cost and safety practices at Pilgrim and Arkansas Nuclear One. This is the 10th consecutive year we received nuclear honors in the NEI Tips Award program. And finally, I'm pleased to report that once again, Entergy scored a perfect 10.0 global ratings from GovernanceMetrics International in July 2012 for best-in-class corporate governance. Entergy has maintained its rating in each of the quarterly periods since 2006 with the exception of one small dip in early 2011 establishing stringent corporate governance standards and living up to them every day, and everything we do is an absolute necessity to us and to maintain the trust that you have placed in us. We demanded of ourselves, and I can assure the Board of Directors demands it not only of us but of themselves as well. And now I'll turn the call over to Leo. Leo P. Denault: Thank you, Wayne, and good morning, everyone. In my remarks today, I will cover second quarter 2012 financial results, our cash performance for the quarter and then add a few closing remarks. Starting with our financial results on Slide 2, higher overall second quarter 2012 earnings were driven by higher results at both the Utility and EWC compared to a year ago, and lower results at Parent & Other. Second quarter earnings included a special item for expenses incurred in connection with the proposed spin-off and merger of Entergy's transmission business with ITC Holdings. Spending on our spin-merge initiative reduced the quarter's earnings per share by $0.05 at Utility. Now let's turn to operational results for the quarter. Slide 3 summarizes the major drivers for operational earnings. Utility results were higher than a year ago due primarily to reduction in income tax expense. This was partially offset by lower net revenue and higher nonfuel operation and maintenance expenses. An agreement with the IRS regarding the storm cost financings in Louisiana for Hurricanes Katrina and Rita reduced income tax expense by $180 million for the affected companies, Entergy Louisiana and Entergy Gulf States Louisiana. The company has also recorded regulatory charges totaling $101 million after tax to reflect an agreement to share the tax benefits with Louisiana customers. The net effect of these items increased Utility earnings by $0.44 per share. Excluding the regulatory charge, Utility net revenue was modestly higher this quarter compared to a year ago. The increase was due largely to positive weather-adjusted sales growth. After excluding the effects of weather, billed retail sales increased 4%. The Entergy region benefited from a reasonably healthy economy. Industrial sales continued to grow from expansions. However, overall weather-adjusted sales growth through the second quarter is roughly consistent with what we expected. While the effect of weather was positive for the quarter, it was lower than the significantly warmer-than-normal temperatures last year. On a year-to-date basis, the weather effect was negative and well below last year. Higher nonfuel operation in maintenance expense partially offset the earnings increase. O&M for the quarter reflected higher compensation and benefits costs driven primarily by pension expense. Fossil and distribution spending also increased over last year due in part to increased fossil outage spending, with timing differences also contributing to both. Slide 4 summarizes EWC's operational adjusted EBITDA for the second quarters of the current and previous years. The quarter-over-quarter decline was due primarily to lower net revenue and increased nonfuel operation and maintenance expense. EWC's net revenue reflected lower energy pricing towards nuclear fleet. Nuclear generation also declined as a result of additional refueling and unplanned outage days. Lower production was offset by the exercise of resupply options under power purchase contracts. The nonnuclear portfolio partially offset lower net revenue from EWC's nuclear fleet. The RISEC plant acquired last December was the driving factor. Higher nonfuel operation and maintenance expense also contributed to the decrease in operational adjusted EBITDA. The increase was due primarily to higher compensation in benefits costs, again, primarily pensions. The RISEC acquisition also contributed to higher nonfuel O&M. While EWC's operational adjusted EBITDA declined, its earnings increased quarter-over-quarter. The increase was due primarily to 2 items not included in adjusted EBITDA: Lower decommissioning expense and the lower effective income tax rate. Operational results at the Parent & Other disclosure segment declined due primarily to higher income tax expenses on Parent & Other activities. The income tax expense increase reflected the net effect of favorable tax items recorded in both quarters, the 2011 effect exceeded the current quarter. Slide 5 provides a recap of our cash flow performance for the quarter. Operating cash flow for the current quarter was $587 million or $67 million lower than the same quarter last year. The decrease was due to lower net revenue at EWC and the regulatory refund to a wholesale customer at the Utility. Slide 6 summarizes our 2012 earnings guidance, which ranges from $3.49 to $4.29 per share on an as-reported basis and $4.85 to $5.65 per share on an operational basis. The as-reported earnings guidance range was updated to include specials recorded in the current quarter. The as-reported guidance does not reflect any potential future expenses for the special item in connection with the proposed spin-merge of Entergy's transmission business. As-reported earnings guidance will be updated to reflect the special item as actual costs incurred throughout 2012. On our last earnings call, we identified several challenges that had developed during the first quarter. At that time, we also had other significant uncertainties, such as the pending appeal of the foreign tax credit decision. While we still have our biggest quarter to go, as we sit here today, we are well positioned relative to our full year guidance range. Current indications point to the higher end of the range. As we head into the second half of the year, we remain focused on continuing to produce positive financial results, as well as strong operational performance. And we remain focused beyond 2012 as well. As we look ahead to 2013, I want to offer some initial thoughts. Turning to Slide 7. At the Utility, we work to get the right regulatory constructs in place to provide every jurisdiction the opportunity to earn its allowed return. One example is the Texas rate case that Wayne discussed earlier, which will have a bearing on 2013 and beyond. We also have other upcoming rate cases. Entergy Louisiana and Entergy Gulf States Louisiana will file rate cases in January of next year. Entergy Arkansas is also expected to have a rate case tied to its exit from the System Agreement at year end. All are likely to take most of next year to complete. Further, the timing and execution of our investment program will affect results. At EWC, one of the most significant variables is the price of power, both Entergy and capacity. Commodity markets continue to challenge margins. However, fundamental indicators in the natural gas market, such as narrowing storage surpluses, falling rig counts and low liquids margins appear to be signaling that we're moving off of a bottom and into a more constructive territory. The appendix to this webcast presentation include the details on the current state of the market for energy and capacity prices for EWC. Protecting the long-term value of our nuclear asset is a key priority. That includes managing the license renewal process for Indian Point -- for the Indian Point units as well as defending the license renewals already received from the NRC. In the meantime, we're utilizing hedging strategies to protect near-term value while retaining longer-term options. For both businesses, managing cost remains at the forefront. However, as we've seen this year, some things like pension expense are driven by external factors we don't control. Efforts are underway to determine opportunities to mitigate cost pressures now and over the long term. At the Parent, we're always looking for opportunities to improve business results. For example, last week, we received authorization to execute a $500 million commercial paper program at the Parent. The CP program will provide a cost-effective source of capital, as well as incremental financial flexibility. At current rates, borrowing from the commercial paper market will be about 100 basis points below the rate on the revolver, which will provide interest savings and bottom line earnings. We are now finalizing plans to implement this program in the third quarter assuming market conditions stay favorable. Every day, we focus on safety, operational excellence, risk management and disciplined capital deployment. Whether managing the current year or planning ahead, the goal is to deliver results that will create tangible long-term value for our stakeholders. And now, the Entergy team is available for your questions.

[Operator Instructions] We'll take our first question from Steve Fleishman with Bank of America. Steven I. Fleishman - BofA Merrill Lynch, Research Division: I guess on the last earnings call, Wayne, you brought up the concept of looking at strategic options for the unregulated generation business. Could you just update us on any thought process there? J. Wayne Leonard: Well, I'll let -- Leo and his team has been working on this. But I think one of the things that we kind of emphasize, that given the uncertainty in a lot of these marketplaces and the environmental regulations and other types of things that we almost have to go back -- one of the additional things we're doing is going back to when we tried to form an axis. And our opinion at the time, of course, it was -- these businesses don't belong together for a number of reasons. They're financed differently. They have different credit metrics, things of that nature. But then as power prices have fallen and things of that nature and credit metrics and credit quality become a real issue for this on a stand-alone basis as it's structured for the wholesale business. and -- but nonetheless, we still believe it should be separated from the utility. So one of the other options is to look at transactions or assets or whatever that impact positively credit quality, so we can get back to maybe at the notion of separating the 2 businesses rather than focus just on a functional adding power maybe at something else. I'll let Leo to have expand on his thoughts on the idea. Leo P. Denault: Yes, Steve, the bottom line is if you go all the way back to the kinds of things we would have been looking at the time we came up with the separation concept, a lot of those ideas haven't gone away. As we've always looked at that portfolio, ways to grow the business, ways to protect the business, way to enhance the credit quality of the business, ways to provide liquidity of the business, we continue to look at all of those kinds of opportunities whether they involve internal moves or transactions-based ideas, and really could run the gambit of ways to improve the credit quality, improve the margins, improve the valuation and to make sure that we continue to protect not only the parent company but the Utilities as well. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Okay, one other question. Just Leo, thank you for giving some of those 2013 drivers and beyond. Is there just maybe kind of a punchline of what you're trying to highlight with -- these seem generally the stuff that we normally kind of you've highlighted in the past. Was there any -- is it mainly these rate cases that... Leo P. Denault: Well, you're really, Steve, just to give you all an indication of what's going to drive 2013 and beyond, and the timing of when those things actually show up during the year as much as anything else.

And we'll hear next from Dan Eggers of Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: I just wondered if we could go back to the kind of the MISO conversation and the ITC transaction. If you think about timing and then kind of perpetual delays to get in the filings done for ITC, is there something structurally you're seeing that is slowing down that process and what is the level of confidence we'll see filing get done in the third quarter? J. Wayne Leonard: Theo Bunting is really heading that process up as the CEO of our Utility. But Dan, I don't think there's anything structurally that's holding it up. Our commitment is to put on the strongest possible case in an area that is kind of new to a lot of the parties to the case, and we want to make sure that we fully support and emphasize how important this is. We're bringing together 2 companies, Entergy and ITC, along with a number of outside experts, who believe very strongly and have evidence to support why the independent model is so much better than how we're doing it today. And just bringing all the different points of view and testimony together, it's clearly everybody's on the same page and it's clearly, there's a -- to the commission and other intervenors on the case has been a little more challenging probably than we might have expected. We thought that we would be able to make our first filing in Louisiana near the end of this month. We gave ourselves kind of another week to button everything up, and we're just not quite there yet. Now, Leo and Theo are having meetings this week to try to resolve any issues that we feel like are not supported as well as we want. To get that analysis and the testimony to -- typically the way we would do it or ITC would do it when you just do it on your own. So it's nothing structural, it's just complicated when you involve more parties, and we want to get it right. Theo, anything to add or... Theodore H. Bunting: Yes, I would like to add something, Dan let me -- I agree with a lot of -- all of the things Wayne said. The other thing I think you need to consider is we're doing this in multiple jurisdictions, and we're trying to do this on a manner that would allow us to make those filings in those jurisdictions with not much passage of time between filings. So obviously, we have to think about how do we ensure we incorporate all of items need to consider relative to those jurisdictions so that when we start that process, we don't get any significant slowdown. I do think, as Wayne said, there's still some things we need to work through. We'll be working through those things over the next few weeks, and we'll begin that filing process. Dan Eggers - Crédit Suisse AG, Research Division: Great. And I guess just, Leo, on the tax issues for the year, is there anything else we should be looking at that you could provide a benefit for this year? And did you anticipate this level of benefits showing up in the guidance when you guys updated this spring? Leo P. Denault: Well, we updated the guidance this year obviously. We had the possibility of both positive and negative items in the tax arena. We knew we were working obviously on the settlement, but at the same point in time, we had the appeal of the foreign tax credit decision, which had already been lost in a different jurisdiction at a different district for which we had provided the reserve last year. So that could have been the positive that you saw this quarter because of the win. But if we had lost that case, it was a significantly larger negative possibility. So we had indications around both of those things, but they were unknown at the time and could have gone either direction. There's always a few things in the hopper, as you know, based on the size and number of the positions that we've got in front of us at the moment that may or may not turn out, may or may not happen, could go to litigation like the foreign tax credit case or could be settled. It just depends on where we are on the audit cycle and what issues are available there. We had taken some of that into consideration when we reset the guidance, remember the $0.22. I think, we characterized that as other in the improvement. In the original guidance, some of that was taken into consideration tax items that may or may not occur. I think we've mentioned that at the time.

We'll hear next from Greg Gordon with ISI Group. Greg Gordon - ISI Group Inc., Research Division: Focusing on Table 4 on Page 3. Your weather-adjusted sales growth has been quite robust. You make some comments in there about growth in -- industrial sales growth, particularly in Louisiana. You also had retail sales growth. Can you extrapolate, a, on what's going on in terms of residential growth, why that's so strong, what types of industrial activity you're seeing that are leading to this type of growth? And then the decline in the refineries, could we characterize that as seasonal, because as I understand it, they were down for maintenance, and therefore, that should be additive when they come back? It's really a very positive underlying theme here. J. Wayne Leonard: Okay, Theo, you want to take that? Theodore H. Bunting: Sure. Craig, as Leo mentioned in his opening comments, obviously, on the residential -- let's start with the residential side first. We are seeing some impacts from still a fairly strong economy in our region, especially when you compare it to what's going on nationally. Also, I think, you have to think about some of the things we had last year that didn't necessarily repeat themselves this year. We had certain events last year that had a dampening effect on sales, for instance the flooding we had from the Mississippi River that reduced sales volumes. And also, I think last year, we had fairly extended periods of extreme weather, high bills and generally customers respond to that. So we probably had some amount of customer response relative to bills last year. And also I think, Leo mentioned the fact that our -- may have mentioned the fact that our billing cycles this year for the quarter had a few days beyond what we would have seen last year as well. And all of those things really coupled together had some effect on the year-over-year change. And if you back and if you look at the residential growth year-over-year last, it was actually slightly negative. So given that, we saw a fairly robust change year-over-year. But again as we have said earlier, I think, we still fundamentally feel like we're -- where we -- about where we expected to be at this point in time relative to sales. In terms of industrials, I think at the chemicals, that continue to show fairly strongly in terms of segments in the second quarter, and a lot of that is relative to facilities expansions. As we go through the year, we'd likely see some of that moderate as we're kind of seeing those expansions and when they hit in various points in times in prior years. There are, obviously, we do get outages in certain areas in terms of customers, bringing their facilities down for various reasons. And that can move our industrial sales up and down as you compare period-to-period.

We'll take our next question from Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Just on the Texas rate case here, just if things don't turn out as positively with the final reg here in August, what are the various avenues? You've kind of alluded to them quickly on the opening statements, but if we were to see a move towards a capacity-type rider, when would that happen? Or alternatively, if we weren't , at what point down the line, say, 6 months, a year from now, do we see another filing, just to be a little bit more explicit about the timeline? J. Wayne Leonard: Theo? Theodore H. Bunting: It sounded like you had a number of questions there, Julien. I'm trying to get though them. Yes, I guess the first thing I would make sure we well understand is where we're at today is we basically have a kind of proposal for decision. It's not an order from the commission. And that's still forthcoming. And part of that, obviously, what we would do relative to that would have a lot to do with what comes out of that commission order. I would say it's not unusual in Texas for the commission to not accept all aspects of a PFD. And as Wayne talked about earlier, in terms of various riders that are in place today, in the current rate construct in Texas, obviously, those will be opportunities for us given once we know the outcome of the case itself. And obviously, to talk about what we might do and whom we might do it at this point in time is probably a little premature because we don't have the outcome of the case yet. The capacity rider, it's in a rule-making phase, and we are working and we'll continue to work to move that along. Also, as Wayne mentioned in his opening script, the big part of what's the issue in the case, as it relates to the recommendation of ALJ is capacity. And if in fact, just assuming for a second that we don't fundamentally give what we believe is appropriate treatment relative to that, and we would obviously like to -- and try to ensure that we move that rule-making along in order to get proper alignment of the regulatory construct in Texas with what we fundamentally believe is appropriate and what's taking place there. J. Wayne Leonard: Yes, I think, like Theo said, we need to get the order out of the commission. Hopefully, it will undo some of these what we think are inappropriate adjustments. But, it won't only just be for the outcome, it will be tone set in the order. Hopefully, it will give us some guidance, that will be instructive at which way to best to proceed. And obviously, we want -- we don't want to start a war with the commission by going one way if they would prefer another. We're hopeful that they will acknowledge that this does not give us the opportunity to earn a fair return and they will fix that or give us a strong guidance on how to fix that ourselves.

We'll take our next question from Paul Patterson with Glenrock Associates. Paul Patterson - Glenrock Associates LLC: Greg asked my question on sales growth. I was wondering though, on the -- one of the commissioners in Louisiana is talking about changing the ROE kind of significantly on the downward side. And I was wondering if you could sort of elaborate if he's being joined by anybody else or if he's kind of an outlier on that, and any thoughts you have on that. J. Wayne Leonard: I'll let -- Theo is maybe closer to it. But as you know, in this interest rate environment, I suspect there isn't a commission on the country -- you don't have, at least, one commissioner who's bringing the issue up as it appropriate. It's a good question. Obviously, interest rates are much lower than we're used to and the -- in like Louisiana specifically, we really have not heard a lot on the issue, we do have one commissioner who more outspoken on it. But again, it's fairly,[indiscernible] I think across the country. But Theo, why don't you... Theodore H. Bunting: Yes, I think also one thing that you will note in Louisiana. I mean, that issue has come before the commission, at least, on maybe one, couple of occasions and they just not moved it along. And as Wayne said, I think we have one commissioner there who is very interested and looking into this. But I think you also have to consider, and I think, they have to consider interest rates is really just one input into that the entire process of defining what's an appropriate ROE. You also have to think about risk premiums and you also have to think about the fact that there's a legal standard around what is the appropriate ROE. And ROE basically should be set such that you can maintain the financial integrity of the company, you can raise capital on a reasonable term, such that the Utility can discharge its public duty relative to the customers. And in this period of time, we're seeing fairly extensive capital investment across the Utility industry. And I think regulators really need to think about and consider all of these elements as you think about what is the appropriate ROE for Utility. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: Okay, great. And then on the stock buyback repurchases, any thoughts to sort of -- at this point in time, I know you got a lot of things going on, a lot of initiatives. Obviously, the ITC stuff and everything else. How should we think about your thoughts about stock repurchases, given everything that you're looking at and what have you? J. Wayne Leonard: Leo? Leo P. Denault: Well, obviously, we haven't -- we didn't have any stock repurchases in the quarter. We've completed $150 million of the $500 million of authority that we have at the moment, so it's $350 million less. Just philosophically, the way the repurchase program works is based on the results out of EWC and/or any kind of transactional-based results that we have, for example, if we sold an asset or what have you. The dividends usually paid for by the Utility, so that's the construct around it. And depending on what capital expenditures are, the cash flow may or may not be used for that. So for example, at the end of last year, when we acquired the RISEC plant, we spent over $300 million on that plant. That part of what goes into the decision-making process around the repurchase. So I guess at the moment we haven't done any recently, we typically don't signal what we are going to do, but just philosophically to know that transactions and/or EWC non-utility earnings, that's where the buyback money comes from.

We'll take our next question from Stephen Byrd with Morgan Stanley. Stephen Byrd - Morgan Stanley, Research Division: You've been making progress at the state level and in moving towards membership in MISO. And in the filings, obviously, comes up the discussion of distinguishing between MISO membership and approving the ITC sale. Can you talk about just general a feedback that you've been receiving at the state level to the ITC sale element relative to MISO. appreciating that that's a later element. But just nonetheless, just any color on the feedback you received at the state level? J. Wayne Leonard: Theo, do you want to in detail? Theodore H. Bunting: Yes. Stephen, I'm not sure I was -- the audible level of your -- it's fairly low. Let me see if I can repeat your question on which you were asking. Were you asking us to, in the MISO proceedings, are we getting questions around the ITC sale and/or -- just want to make sure I understand what your question was. Stephen Byrd - Morgan Stanley, Research Division: Yes, I think my focus really was just in your conversations about the overall ITC transaction at the state level, which I understand we will come up as part of the MISO proceedings. Can you just talk generally to the feedback that you've been receiving at the state level relating to the ITC transaction? Theodore H. Bunting: Yes, and I made a huge mistake. I said sales, it's not a sale. It's just been merged. And I hope I don't think I used that term in my testimony that I plan to file. But in any case, It does come up from time to time, but we try to make sure folks understand that they are separate processes, they're separate transactions, they're separate steps. Obviously, we need to get to MISO to an RTO in order to effectuate the ITC transaction. And as we've said to many regulators, I mean, we are focused on getting in MISO and getting to an RTO. And that's part of the reason, I think, why you've seen some passage of time and some separation as it relates to the filings around the ITC transaction is that we are -- we're trying to work through within the various jurisdictions that MISO process. And moved the various commissions along and other parties to get through that MISO process and get on MISO approvals, but it does come up from time to time. J. Wayne Leonard: Yes, I think the discussions I had been involved in, I think, it's actually been very encouraging. The regulators have been very interested in trying to understand more. When we proposed a similar -- actually, I guess, it wasn't all that similar 2 years ago, it was hostile environment with regard to some type of divestiture of the transition system. They have -- the questions we've gotten had been very much on point with regard to how things will change. The overall feeling seems to be that they -- given the amount of merchant capacity we have in our territory, given some of the feedback that they've gotten from some of the merchants and some of the extensive audits and -- that we've had relative to merchants, some of the merchant's concerns and other concerns, they understand that this needs some sort of resolution other than continuing to try to just regulate this thing to debt. Separating, it resolves all those issues and eliminates this -- any perception along with it solves a lot of problems for Entergy with regard to credit quality and that just lowers rates for customers and assures reliability. And we've had really good dialogue, I think, with the commissions. And the big concern -- the biggest concern that I've heard is to try to explain exactly how giving that jurisdiction, the FERC would have ultimate authority on how they maintain authority to execute their job assuring reliability at a fair price and all those type of things, and they don't want to end up just as another intervenor at FERC. And so that's kind of, I think had been working through the process, trying to make sure that, that doesn't happen. That's really the issue with them, but again it's been very constructive.

And our final question comes from Mike Lapides with Goldman Sachs. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: I just want to make sure I'm following the rate changes you expect between now and maybe the year end of 2013, kind of following on some of Leo's comments. You discussed the Texas rate case. I guess, the question is do you think you would file another case and have new rates in place before year-end '13? Then the Louisiana formula rate plane adjustments that are outlined in the appendices, do you expect the incremental adjustments before the actual Louisiana rating changes or rate cases kind of resolve? And then the timing of an Arkansas case, how early would you file, when do you think rates would go into effect there? And apologies, a fourth item, how do we think about how Grand Gulf's operate will impact rates? J. Wayne Leonard: I think Theo is getting a good introduction here to his new job, but he's, like we've said before, he's certainly up to the challenge and probably the most knowledgeable person we've ever had in this job, so we'll let him prove it right now. Theodore H. Bunting: I think he's asking me to prove that because, first, he wants to make sure if I can actually remember all the questions. I'll start maybe in reverse order. Grand Gulf, I don't think, as you know, Grand Gulf is FERC regulated and there is a specific tariff around how cost through the unit power purchase agreement of SERI and the various operating companies, how that cost flows from Grand Gulf or from SERI to the operating companies. And the various operating companies have different regulatory mechanisms in place to recover cost associated with those billings from SERI. And they vary a little bit jurisdiction to jurisdiction, but they all have fairly timely mechanisms in place to recover cost associated with Grand Gulf. In terms of filings, obviously, we would expect the filing in Arkansas consistent with its departure from the system agreement. And obviously, that's targeted for the end of 2013. Louisiana, when you talked about FRPs, Wayne talked a little bit about the FRP results as it related to our filings, based on the 2011 test year, I think, as Leo mentioned, we would be making rate case filings in Louisiana in January of 2013 to basically reset rates. Depending upon the length of the proceeding, it's potentially, you could have some impact from that decision relative to that case in 2013. But that will be a function of the procedural schedule that obviously we will get once we make those particular filings. As it relates to one of the questions you had, Mississippi, we made our FRP filing, no changes relative to that filing based, again, on 2011 test year. And was there another jurisdiction that -- where there jurisdiction I missed? Michael J. Lapides - Goldman Sachs Group Inc., Research Division: When would you -- if Texas rate case resolved in the next month or so, when do you expect you would be back in filing for a new place rate increase? Theodore H. Bunting: I mean it's pretty mature to talk about that at this point. We don't have an order out of Texas. And so until we get an order and realistically see where we are, we'll evaluate that and make an assessment as to what is the appropriate time to file.

And at this time, we have no further time for any other questions. I'd like to turn the call back over to our speakers for any closing or final remarks.

Thank you, Deanna, and thanks to all for participating this morning. Before we close, we remind you to refer to our release and website for Safe Harbor and Regulation G compliance statements. Our call was recorded and can be accessed on our website or by dialing (719) 457-0820, replay code 8666645. The recording will be available as soon as practical after the transcript is filed with the U.S. Securities and Exchange Commission due to filing requirements associated with the proposed spin-off and merger of Entergy transmission business with ITC Holdings Corp. The telephone replay will be available through August 7, 2012. This concludes our call. Thank you.

Again, this does conclude today's conference. We thank you for your participation. You may now disconnect.