Paula Waters - Vice President of Investor Relations Leo P. Denault - Chairman, Chief Executive Officer and Chairman of Executive Committee Andrew S. Marsh - Chief Financial Officer and Executive Vice President Roderick K. West - Chief Administrative Officer and Executive Vice President Theodore H. Bunting - Group President of Utility Operations

Angie Storozynski - Macquarie Research Dan Eggers - Crédit Suisse AG, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Andrew Levi Greg Gordon - ISI Group Inc., Research Division Steven I. Fleishman - Wolfe Research, LLC Charles J. Fishman - Morningstar Inc., Research Division

Good day, everyone, and welcome to the Entergy Corporation Second Quarter 2013 Earnings Teleconference. Today's call is being recorded. And 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 today with comments from Entergy's Chairman and CEO, Leo Denault; and then Drew Marsh, 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. With respect to the planned spin-merge transaction, ITC filed a registration statement with the SEC, registering the offer and sell of shares of ITC common stock to be issued to Entergy's shareholders in connection with proposed transaction, and the registration statement was declared effective by the SEC on February 25, 2013. ITC is expected to file a post-effective amendment to the registration statement and ITC shareholders are urged to read the prospectus included in the ITC registration statement and the post-effective amendment to the ITC registration statement, when available, for important information about Transco and the proposed transactions. In addition, on July 24, 2013, our subsidiary, Mid South TransCo LLC, filed a registration statement with the SEC, registering the offer and sell of Transco common units to be issued to Entergy's shareholders in connection with the proposed transaction. This registration statement includes the prospectus of Transco related to the proposed transactions. Entergy also will file a tender offer statement on Schedule TO with the SEC, related to a planned exchange of shares of Entergy common stock for the Transco common units. Entergy's shareholders are urged to read the prospectus included in the ITC registration statement and the post-effective amendment to the ITC registration statement when available, the Transco registration statement, the tender offer statement on Schedule TO when available, and any other relevant documents because they contain important information about ITC, Transco and the proposed transaction. These documents, and other documents related to the proposed transaction, when they're available, can be obtained free of charge from the SEC's website at www.sec.gov. The documents, when available, can also be obtained free of charge from Entergy upon written request. Now I'll turn the call over to Leo. Leo P. Denault: Thanks, Paula, and good morning, everyone. Last quarter, I laid out our roadmap for 2013, the 7 strategic imperatives we are focused on that will bring sustainable value for our owners, our customers, our employees and the communities we serve. This morning, I'll update you on progress on each imperative over the last 3 months. As a reference, the 7 strategic imperatives are listed on Slide 2 to the webcast presentation. Starting with execute on MISO and ITC. The targeted December 19 cut-over date for the Utility operating companies to join the Midcontinent Independent System Operator is approaching quickly. Many operational and regulatory activities are ongoing in parallel to ensure a seamless transition. Last month, we received additional orders from the Federal Energy Regulatory Commission on certain key MISO-related issues. We appreciate the FERC's timely action on these items. Also in May, on the implementation front, we ran a simulation on processes, situations and communications that employees will handle when MISO integration is complete. Over 100 participants from Entergy, MISO and ITC were involved over a 2-day period. The exercise did highlight areas to work on; more importantly, however, it confirmed we are well on track for accomplishing what will be a step change in how we plan and operate our system. Regarding the spinoff and merger of the transmission business with ITC, in the second quarter we received key transaction approvals from the FERC and a private letter ruling from the Internal Revenue Service, confirming the tax-free nature of the transaction structure. These items come in addition to the April 16 ITC shareholder approval I mentioned last quarter. This brings us to the retail regulatory approvals. We entered the final critical stages in the second quarter. After careful consideration of the input from parties in all of the retail proceedings, we and ITC offered a package of rate mitigation and other commitments, including a total of $453 million in rate mitigation over the first 5 years across all jurisdictions as detailed on Slide 3, and a test to ensure customer benefits exceed ITC's high return on investment capital before rate mitigation ends. These proposals align with -- align the realization of the benefits the transaction offers to customers and the rate effects resulting from ITC's higher cost of capital. They transfer the risk of achieving the benefits of what we believe is a superior business model from the customers back to the companies. We are not asking our regulators or our customers to make a bet on us. We've been held accountable for delivering benefits preceding the cost of ITC ownership. We strongly believe this transaction will yield a more reliable, more efficient grid than joining MISO alone, as I reviewed in detail last quarter. The better grid benefits customers through fewer and shorter outages, reduced congestion and line losses, and greater access to lower-cost power. The rate mitigation and other proposals commit us and ITC to delivering both performance and economic benefits that exceed the rate effects from ITC's higher cost of capital. Rate mitigation will continue until they do. These proposals were developed and offered jointly by us and ITC. We are not in a position to discuss all of the details, but I can offer a few points about how we and ITC plan to allocate the rate mitigation between the 2 of us. The Entergy operating companies and ITC will share in the $387 million of the wholesale and retail billed credit component of rate mitigation in the first 5 years. This is the part that is not attributable, the forward test period. The Entergy operating companies will bear 65% to 70% of this component. ITC will bear the rest. The Entergy operating components will fund the $40 million of mitigation associated with the forward test year in the first 3 years. The balance of rate mitigation is comprised of net avoided costs. For years 6 through 10, if rate mitigation is still required, the Entergy operating companies and ITC will split those costs 50-50. After 10 years, the Entergy operating companies' obligation will be fixed at a modest amount, and ITC will be responsible for any balance required. Finally, the Entergy operating companies' responsibility for rate mitigation will end after 20 years. As I've said before, we believe that the benefits for our customers, employees and communities are real. This rate mitigation proposals puts us and ITC on the hook to deliver them. We do not shrink from being held accountable. In the last 2 weeks, we were encouraged by the Coalition of Cities in Texas. After considering our commitments, many of which were directly responsive to their concerns, 14 cities to-date have passed resolutions in favor of the transaction. The cities made a filing with the Public Utility Commission of Texas supporting a finding of public interest for the transaction provided that Entergy Texas and ITC meet certain conditions. The PUCT will consider our application at their opening meeting next week on August 9. We are hopeful that the benefits of the transaction, including the rate mitigation plan, combined with the city's resolution and the East Texas Electric Cooperative's recommended support, will provide the Texas commission the basis it needs to approve our application. We're in various stages in other jurisdictions. Upcoming dates for filings and hearings are shown on Slide 4. Based on current schedules, decisions by all of our retail regulators are anticipated in the fall. We believe in this transaction. We are convinced it is the right approach, and the facts and important public policy considerations support its approval by our regulators. The next strategic imperative listed on Slide 2 is to optimize the organization through human capital management. We refer to this effort internally as HCM. In July, we completed a comprehensive review of our organization design and processes. This effort resulted in a new organization structure, designed to provide optimal service to our stakeholders. This process is a critical part of our ability to be successful at our goals of being more efficient, continuing to control our costs and improving service levels. Other opportunities to make our organization more flexible and adaptable to business changes are under consideration. In the long run, these changes will ensure our employees are in the right jobs, have the right skills to be successful, and the right tools and resources to meet the changing business needs. Near term, however, workforce reductions are a difficult but necessary step. We have identified approximately 800 positions throughout the company which we expect largely will be eliminated by year end. In addition, the organizational redesign effort will reduce contractor spending. Difficult decisions like job reductions are sometimes the result of making long-term fundamental improvements in the way a company works. The redesign process was led by a team of Entergy employees and had the full involvement and oversight of the entire executive leadership team. In addition to realizing sustainable savings, the teams are tasked with the goals of improving the way we work, placing the right people with the right skills in the right roles. The process is comprehensive, thoughtful and focused on being fair and responsive to the needs of all of our stakeholders. While we spent a lot of time on organizational design and process this past quarter, we are evaluating additional opportunities to obtain savings, including compensation and benefits, procurement, and non-employee operating expenses. As a result of progress to date, we have set a financial goal of $200 million to $250 million in savings to be implemented by the end of 2015 and fully realized by 2016. I know you have more questions about these savings targets. Drew will cover those details to the extent they are currently known. As we continue this effort, I want to reemphasize its safety, security, customer service, reliability and compliance will never be compromised. The third strategic imperative is to maintain financial flexibility. Since I introduced this on last quarter's earnings call, many of you have questioned what we mean by this one. I want to be clear. It means simply what it says: maintain financial flexibility. Today, we meet and expect to continue to meet our financial flexibility objectives. Gross liquidity stood at a healthy $4.1 billion on June 30. The credit ratings are stable at both Moody's and Standard & Poor's. And our current financial outlook, which extends through 2014, supports deploying capital and meeting our obligations without the need to issue traditional common equity. Maintaining alternatives and headroom to avoid the damaging effects of dilution on our owners remains a central focus for the Board of Directors, me and the rest of the executive leadership team. This and the other strategic imperatives are simply about being better positioned to pursue more customer and owner-focused actions in the future, over and above our current plans and commitments. The next 2 strategic imperatives I will talk about are related. Growing the Utility business, such as through economic development, and continuing to develop and implement productive regulatory constructs. To be successful at one requires attention to the other. For example, effective regulatory constructs can provide utilities with the financial stability needed to make necessary investments and take actions to deliver reliable service to customers while keeping rates reasonable. Low rates helps to keep existing businesses competitive and attract new investments to our region. Higher growth can be cycled through the regulatory constructs to spread fixed cost over more volume. Defining and pursuing this path is one of the keys to addressing the risks from so-called disruptive challenges faced by the utility industry. I'm sure you noticed in Table 4 of today's investor news release, quarterly weather-adjusted sales were down in all customer classes. On the residential side, increasing interest in energy efficiency and demand side management are contributing factors, something we anticipate in setting 2013 expectations. On the topic of energy efficiency, New Orleans, Arkansas and Texas, the jurisdictions where programs are up and running, we have cost recovery through a rider or through base rates, as well as performance incentives in all 3 jurisdictions and recovery of loss contributions to fixed cost, a limited form of decoupling, in Arkansas and New Orleans. Sluggish economic growth also contributed, affecting all segments. Industrial sales were disappointing, once again, this quarter. Near-term factors such as inventory liquidations and slowing exports, have reduced industrial electricity usage, principally in the small- to mid-sized segments in Louisiana, Arkansas and Mississippi. While near-term challenges exist, new industrial development activity is a bright spot in our future expectations beyond 2015. Shortly after our last earnings call, Entergy Gulf States Louisiana announced a long-term contract with Cameron LNG to supply an additional 200 megawatts, for 10 to 30 years, to their proposed LNG facility. Construction is expected to begin next year. This is just one example of the large pipeline of new capital investments for manufacturing and other economic development projects. Our region has an attractive business climate led by its access to an abundance of natural resources, reasonable cost of living including electricity rates, tax and other business reforms enacted at the state and local levels, and programs such as the compressive workforce training program in Louisiana. To update statistics from April, we now have over $50 billion in high-probability investment projects in various stages in our service territory. This represents approximately 1,500 megawatts of load and more than 27,000 new jobs, of which nearly 11,000 would be direct. Obviously, all of these projects may not happen. We may not supply all of these projects and some may not be completed. The point is, this much in the pipeline illustrates the potential for growth of our customers and our communities. I know I don't have to remind you that we have a number of regulatory proceedings underway in each jurisdiction, including rate cases, formula rate plan filings and storm recovery. I will give you a brief update on major developments. All the usual details are provided in our release and the webcast slides. In Mississippi, Entergy Mississippi and the Mississippi Public Utilities Staff filed a stipulation settlement to resolve the 2012 test year formula rate plan proceeding. The stipulation called for a $22.3 million annual revenue increase. The rate change provides funds necessary for increased reliability, capacity for economic growth and the ability for flexible use of the power plants on the grid. It is the first FRP increase in 4 years, and even after, Entergy Mississippi's rates will remain well below a number of other utilities in the Southeast and more than 10% below the national average. The next Mississippi Public Service Commission meeting is scheduled for August 13. If approved, new rates would be effective beginning with September billings. In May, the Louisiana Public Service Commission approved a settlement in a new proceeding relating to Entergy Gulf States Louisiana's natural gas operations. The settlement extended the gas rate stabilization plan for an additional 3-year term through the 2015 test year. Return on equity midpoint was revised to 9.95%, down from 10.5%, and the plus-or-minus 50 basis points range was maintained. This settlement resulted in a $678,000 rate increase for customers related to the 2012 test year. In addition, the LPSC order directed the company and staff to work towards the gas infrastructure investment rider. The LPSC has a long-standing practice of using formula rate plans and riders for electric and natural gas utilities. Requests for new 3-year formula rate plans are a component of Entergy Louisiana and Entergy Gulf States Louisiana rate cases filed earlier this year. Regarding the rate cases, the Entergy Louisiana companies have requested LPSC review of Administrative Law Judge's denial to consolidate the 2 rate cases. As part of this request, the companies are seeking a 60-day delay in the procedural schedules to allow all parties to explore framework for a more efficient review of the rate case requests and possible resolution, and to set a new procedural schedule should the Louisiana Commission approve the motions to consolidate the 2 rate cases. The consolidation matter is on tomorrow's LPSC business and executive meeting agenda. Given these developments, the ALJ and the Entergy Gulf States Louisiana and Entergy Louisiana rate cases suspended the upcoming August deadlines for staff and intervener testimony there. Riders are another construct our regulators have approved to support actions to benefit customers and the companies. In early May, the Public Utility Commission of Texas approved a new rule adding a purchase power capacity rider as another tool available for Texas utilities. This rider will be available for Entergy Texas in the future. However, based on a review of the company's financial status and expectations, Entergy Texas expects to file a base rate case in the third quarter. Turning to the EWC business for the next strategic imperative listed on Slide 2, improving EWC results. We have a number of options we are exploring. On the revenue side, forward energy prices declined in recent weeks, but New York's rest-of-state capacity market continued to improve. Second quarter spot auctions cleared near $4.40 per kilowatt-month, roughly 60% higher than first quarter of this year and more than 2.5x higher than second quarter of last year. Capacity market improvements were driven by the effects of successful mitigation, any [ph] projects with contracts were reflected at fair prices in the auction, and plant retirements in mothballings [ph]. In addition, a new capacity zone for the Lower Hudson Valley remains on track to begin next summer, subject to FERC approval. The New York Independent System Operator identified the need for this new zone to address transmission deliverability issues and improve grid reliability. The FERC decision is expected in the near-term. Indian Point is located within this new zone, where prices are expected to be higher than the rest-of-state market where it currently resides. While we remain encouraged by the progress made related to the Lower Hudson Valley capacity pricing, we remain concerned about some of the overall market design issues in New York and New England. We are committed to continue to work towards promoting fair and competitive power markets in those regions. From the cost efficiency perspective, EWC completed a reorganization this month, as part of this strategic imperative to improve results, reducing costs going forward. It was handled separately from the human capital management optimization effort due to the financial realities the business is facing. Reorganization efforts in nuclear operations at the nuclear plants and nuclear headquarters are part of the overall HCM effort. Additional ideas and opportunities for efficiency and productivity improvements at the plants are in various stages of review and implementation. Regarding our nuclear operations, we were pleased to announce the election of a new director in June, Retired Admiral Kirkland Donald. His tremendous experience, including important positions in the Navy's nuclear program, will enhance an already strong oversight by the Board of Directors. Our actions and success in this final strategic imperative, aligning corporate culture, can best be judged by our results. How well we execute on the other strategic imperatives requires alignment throughout our organization. And successful execution requires a skilled and focused organization from top to bottom that is designed and managed to perform and achieve. We recognize there are a lot of complexities to our company today. That's inherent in the 7 strategic imperatives for 2013. It's a busy year for us and we know it is for you, too, tracking the numerous filings, regulatory decisions, and management execution. We are aiming for success in all of our strategic imperatives to support a step change in our customers' value proposition and that of the company. Next year should provide a clear picture of who we are and where we are headed as a company. Next year, we plan to be part of MISO, delivering benefits to our customers estimated at approximately $1.4 billion in the first decade upon integration into the MISO [indiscernible] market. Next year, we will not be working on the ITC transaction. We remain firmly committed to this transaction because we believe the ownership of our Mid South transmission business will create the most value for all of our stakeholders held by ITC; for our customers and communities, it will lead to lower delivered energy prices; for employees, better job opportunities in a largely, singularly focused business. This represents incremental value over and above what the transmission brings to Entergy and its stakeholders today. That said, if the transaction does not close, we will continue to operate efficiently, to make economic and reliable investments, to optimize toward achieving capital management imperative and to continue to seek out productive regulatory constructs and grow the business. By early next year, the pending rate cases in Arkansas and Louisiana will be resolved. Rate cases are a basic part of our business. We will have 2 others pending in Texas and New Orleans. But the uncertainty caused by the number of outstanding cases and jurisdictions will be behind us. Nevertheless, we will continue to seek out productive regulatory constructs that reward efficient operations, and facilitate access to capital on reasonable terms in order to maintain reasonable rates. Next year, we will be well into the implementation phases of our human capital management optimization efforts. The new organization design will largely be in place. This is a central component to the effort, but not all of it. Further development of other opportunities continues, some of which will likely also be in implementation stages by then. We are working to have better clarity before next year on the direction of the EWC business. We are considering a number of avenues and options to adapt to the current business and market realities. While we are working to strengthen the business financially, we also know the plants are valuable to all stakeholders, including to employees and communities for the direct and indirect jobs that they provide, to customers and communities where the environmental grid reliability and fuel diversity benefits from their operation, and to owners for the option for power price recovery they represent. As we consider strategic alternatives for EWC, all options are on the table. Our focus today is on streamlining for 2014 and beyond for all stakeholders by aligning our organizational design, functions and processes. For our owners, reducing complexity makes us an easier company to follow, predict and value. For employees, redesigning our organization to be more efficient and aligning our corporate culture will create a more productive, engaging work environment, ultimately making it easier to execute. These benefits help to maintain reasonable costs and safe reliable products and services for our customers, as well as economic development, philanthropy, volunteerism, and advocacy in our communities. We understand uncertainty creates a discount, and 2013 is the year for us to reduce some of that uncertainty. One last item before I turn the call over to Drew. Typically, we would not mention to you the retirement of our human resources leader. However, in the current case, it's different. In September, a long-term Entergy employee, and even longer-term friend of mine, Renae Conly, will retire. For the last couple of years, Renae has been our HR leader and, prior to that, she led our largest jurisdiction for a decade through some of the most difficult times the company has faced, for example in 2005, during Katrina and Rita. Many of you, however, will recall that Renae was the driving force behind turning Entergy's Investor Relations group into the high-quality organization it is today. And if you've been in the business as long as I have, you probably remember her filling the Investor Relations roles at both Cinergy and, before that, PSI. For those of who you that know her, you realize how capable she is, you know her tenacity, her strength, her intelligence and her kindness. I know many of you listening that are investors will recall her many contributions, and I hope you will feel free to contact her during the next month to wish her well. And I know many more of you who are employees feel the same sadness as I, that she is leaving us, but also the tremendous happiness for her as she enters the next phase of her life. All I can say is she will be greatly missed. And now, I'll turn it over to Drew. Andrew S. Marsh: Thank you, Leo, and good morning, everyone. In my remarks today, I will cover quarterly financial results and expectations for 2013 and beyond. This will include a discussion on human capital management. Now let's turn to the quarterly financial results. Slide 5 summarizes second quarter 2013 results on an as-reported and operational basis. Operational earnings per share were at $1.01 versus $2.11 a year ago. Second quarter as-reported earnings in both periods included special items for expenses associated with human capital management in 2013 and the spin-merge of the transmission business of ITC in 2012 and 2013. Turning to operational results, Slide 6 summarizes the major drivers by business. Utility operational earnings per share were lower in the second quarter 2013 due largely to a tax benefit and associated regulatory credit in the comparable 2012 period. Together, these 2 items provided a net benefit of approximately $0.44 in the second quarter of last year. Excluding these items, the quarter-over-quarter operational results declined approximately $0.15. The overall decrease is attributable to the net effects of higher non-fuel O&M expense and higher depreciation expense, partially offset by higher net revenue. A portion of the increased non-fuel O&M and depreciation expenses, as well as the increased net revenue, reflect investments placed in service in 2012. Previously identified higher benefit costs, primarily from pension discount rates, also contributed to the quarterly O&M variance. Second quarter 2013 net income also included approximately $7 million incremental pretax expense as a result of the ANO industrial act. This amount reflected incremental non-fuel O&M, less than estimate recorded for expected insurance proceeds and reduced refueling outage amortization expense. While on the topic of ANO, I'd like to give a quick update. First, recovery efforts of -- for ANO have progressed well. Unit 1 could return to service as early as August, testing and recovery continue going well. Second, we've updated cost estimates for the assessment, restoration, debris removal and recovery efforts [ph] of the damaged property and equipment to be in the range of $95 million to $120 million. This estimate does not include replacement energy and it may change the continued restoration activities. Finally, Entergy Arkansas recently filed a lawsuit in Arkansas State Court seeking to recover damages relating to the ANO event, and is continuing to assess other options for recovering damages, including insurance and other legal action. Now, turning back to the results for the quarter at the Utility. Utility net revenue increased due to the prior period regulatory credit noted earlier and pricing factors. As with first quarter of 2013, pricing adjustments included regulatory actions for major generation investments placed in service in 2012. These investments benefit customers through improved operational efficiency and favorable environmental profile. Utility retail sales volume on both an as-reported and a weather-adjusted basis declined quarter-over-quarter. Leo reviewed certain sales drivers in his earlier remarks. In setting 2013 guidance, we anticipated declines in residential and commercial sales from energy efficiency, and growth and industrial sales from expansions. However, year-to-date results have been below expectations for all segments, especially in the industrial segment. We expect better industrial performance over the balance of the year, particularly in the fourth quarter as a large expansion is scheduled to start up. Longer term, we still see support for 1% to 1.25% sales growth. At EWC, operational earnings were $0.33 per share lower than the second quarter last year. This period-over-period decline was due largely to the lower operational adjusted EBITDA drivers, which I will review shortly. EWC results also reflected higher decommissioning expense due to an item recorded in the second quarter of last year, partially offset by lower income tax expense. Slide 7 summarizes EWC's operational adjusted EBITDA for second quarter 2013 and 2012. The $66 million decrease was due primarily to the lower net revenue, driven by decreased output from EWC's nuclear fleet. The nuclear fleet had 26 additional outage days from both refueling and maintenance outages. While second quarter day-ahead Northeast Energy prices were roughly 35% higher than prior year levels, we saw a large decline in prices over the course of the quarter, due in part to reversion of New England natural gas prices from high winter levels, as well as weak supply and demand conditions in the broader natural gas market. Including the impact of hedges, average energy price for the quarter -- the current quarter on EWC's nuclear portfolio declined approximately $3 per megawatt output, versus second quarter last year. Leo had already reviewed the underlying drivers for the capacity markets. I'll note that we continue to expect to see these constructive fundamentals going forward in New York with the new Lower Hudson Valley zone, though regulatory intervention risk remains a risk. Slide 8 summarizes our cash flow performance for the second quarter. Operating cash flow was $572 million, $15 million lower than the same period a year ago. There were several drivers, both positive and negative. While the overall decrease was $15 million, the variance by segment was significantly higher, this is in large part due to intercompany tax payments. Because Entergy filed a consolidated return, income tax obligations are routinely settled between our legal entities as issues are resolved. In the current quarter, the intercompany activity was largely due to the tax settlement which we recorded in the fourth quarter last year related to the tax treatment of our utility decommissioning liabilities. Ultimately, timing of payments to the IRS will consider many factors, including storm loss carry-backs, utilization of NOLs and the taxable income of other entities in the consolidated tax group. Slide 9 summarizes our 2013 operational earnings guidance of $4.60 to $5.40 per share. I know you are familiar with the drivers so I will not repeat them today. Operational guidance does not reflect the 2 special items I discussed earlier. Now I'd like to turn to a discussion of drivers for 2014 and beyond, as they are shaping up today. Starting with HCM on Slide 10. Human capital management is designed to create sustainable value for our 4 key stakeholders and will have a real lasting impact on Entergy by changing the way we work, while reducing ongoing spending and maintaining or improving safety, security and reliability. As Leo noted, total annualized savings from our HCM initiative will be in the range of $200 million to $250 million by 2016. While execution of the initiatives and realization of the savings will occur over the next few years, the bulk of the savings will be realized in 2014. Savings realized at the Utility operating companies will be recognized appropriately in our regulatory filings when those savings and the cost to achieve are known and measured. This process will vary by jurisdiction. Estimated savings are primarily from the organizational redesign effort, which will be largely completed by the end of this year. The savings estimate also includes cost reductions from the other areas Leo discussed. On a preliminary basis, the total $200 million to $250 million savings goal is expected to be split approximately 80% to 90% non-fuel O&M and the balance in capital spending, and approximately 60% to 65% at the Utility and the balance largely at EWC. In order to implement our HCM initiatives, we expect to incur onetime costs to achieve in the range of $145 million to $185 million. The majority of these costs will be incurred in 2013 and will be classified as a special item. The level and timing of HCM savings are important in considering future O&M levels. Our future spending and earnings trends will be affected by other factors as well. Slide 11 summarizes our non-fuel O&M and refueling outage expenses over the past few years. The 2013 base line of approximately $3.5 billion represents our current expectations excluding past and future costs associated with the HCM implementation and the ITC transaction. Considering all these factors, we expect a 3-year compound annual growth rate of the 2013 base of around 1.5% to 2.5%, including HCM savings. Growth rates can vary from year to year. In addition to the level of HCM savings, other factors to consider for future O&M levels include the effects from the proposed ITC transaction, variations in pension discount rates, spending on initiatives such as energy efficiency, inflationary pressures and incremental regulatory compliance costs. Some of the factors driving changes in O&M expense, such as MISO costs, energy efficiency costs and storm reserves have corresponding offsets in net revenue. Looking ahead to 2014, Slide 12 summarizes preliminary major drivers to consider, based on where we stand today. For the Utility, whether or not the spin-merge is completed is a key factor in 2014. Excluding that transaction, we are affirming our 5-year compound annual growth rate for Utility net income of around 6% through 2014. In addition to HCM, many initiatives underway now will determine our ability to deliver on this financial outlook. Those include the outcomes of pending rate proceedings in Arkansas, Mississippi and Louisiana and, to a lesser degree, the to-be-filed rate case in Texas. The level of sales growth is also a factor to watch. As I noted earlier, 2013 sales to-date have been lower than expected. However, we still believe that over the longer term, the annual retail sales growth of 1% to 1.25% is achievable, even after factoring in energy efficiency and remaining capital [ph] management efforts. As Leo explained, our service territory has strong economic development activity, signaling the potential for long-term growth. Recent contracts, combined with other major projects that our economic development teams are working on, could have a significant impact. Even with higher growth in the lower-priced industrial segment, there is still incremental revenue and customer benefit from spreading fixed costs across higher volume. For EWC, energy and capacity markets are a major factor for the financial performance of that business. The 2014 average revenue per megawatt hour for EWC's nuclear fleet is expected to decline approximately $2 per megawatt hour based on the June 30 forward markets. Our 23% open energy position, combined with market variability in certain hedge positions, leads to a range of possible price outcomes, as you can see in the price sensitivities outlined in Table 7. Variations in nuclear plant outages, both planned and unplanned, can also affect EWC's earnings. We now expect to have full refueling outages next year, as a result of moving the Palisades refueling outage from fall of this year to early 2014, and our ability to identify and execute on opportunities to improve EWC results is important for that business. This includes the O&M factors I discussed earlier. Income tax expense is also an item that seems to vary from year-to-year and by segment, and we always have the potential for portfolio management activity. Through all of this, we are focused on managing the strategic imperatives and positioning ourselves to take advantage of any opportunities and facing new challenges that come our way, while maintaining a firm commitment to deliver sustainable value to all our stakeholders. And now, the Entergy team is available for your questions.

[Operator Instructions] We'll go first to Angie Storozynski of Macquarie. Angie Storozynski - Macquarie Research: I wanted to start with Slide 22, the illustrative adjusted EBITDA for EWC, and how it ties into the Slide 12. So you're showing a step down in EBITDA for the merchant business in '14, even though we have quite a considerable O&M cuts and an unlikely pick up in capacity revenues in New York. I know that there's a reduction in energy prices, but I would still expect a bit of a stronger projected EBITDA for that business. Leo P. Denault: Yes. Well, the reality is, is that we're still facing lower prices, overall. So as Drew suggested, on a per-megawatt-hour basis, we're seeing a reduction. So while we're encouraged and we've seen some uplift from areas such as the Lower Hudson Valley capacity zone, the fact is, in a lot of the other markets, specifically in the New England market, we're not getting appropriate rents in terms of capacity prices. So net-net, you're correct. We're still looking at a decline in total EBITDA for EWC for '14. Angie Storozynski - Macquarie Research: So that bar already fully incorporates cost-cutting and MISO's projections for the capacity price uplift? Leo P. Denault: I don't believe that it includes all of the HCM efforts, but it does reflect our point of view on current market conditions. Angie Storozynski - Macquarie Research: Okay. And then on Slide 12, could you just explain a little bit what is the -- this potential portfolio management activities? What do you mean by those? Andrew S. Marsh: Well, as we look at that portfolio, as Leo mentioned, we consider all options, and we do this on a regular basis. So obviously, we look at a hold-and-optimize scenario, where we are taking the steps to reduce our costs and be as efficient as we can at each and every facility. We also are -- explore market opportunities to determine if any asset or portfolio of assets would be better owned by another party. And we also continually evaluate the potential for a shutdown of a facility. So those are -- when we talk about options, those are kind of the 3 different areas that we constantly look at, and that's similar to what we've always done. Angie Storozynski - Macquarie Research: Okay. But why is it mentioned under corporate and not under EWC? Leo P. Denault: Well, that's -- this is Leo, Angie. That's primarily given who kind of leads some of those efforts and they work in conjunction with the folks within the business units. So the kind of people who do all that kind of activity primarily are driven out of the corporate organization, so that's more just our organizational structure than anything else. Angie Storozynski - Macquarie Research: Okay. I know I was supposed to ask only 2 questions but this last one is -- so we have the -- those projections of O&M cuts, targeted projections by 2016. Can you explain to me the timing of this announcement vis-à-vis your pending rate cases and ITC transaction? I mean, should it, you think, facilitate the ITC deal and your pending rate cases or, I mean, how will it be actually incorporated in your pending regulatory filings? Leo P. Denault: I'll let Rod take that. Rod West, who's our Chief Administrative Officer, all of the HCM effort is being directed under his organization. So I'll let Rod take that. Roderick K. West: And to be direct in answering your question, the timing is not designed to facilitate or feed a regulatory point of view. The timing of the HCM announcement really does reflect where the companies planning process has evolved to where we think we have a clear point of view on the savings and our confidence around being able to articulate what we think the bottom line impact would be. And so as we began this process, Leo, I recall, announced at EEI last year as we were formally beginning to publicly, at least, execute on our point of view around MISO and ITC, we had perspectives around where the organization needed to be on a going-forward basis. And as we evolved, as the analysis evolved, we felt more and more comfortable about when we'd be able to communicate. So the timing, it just reflects where we are.

[Operator Instructions] We'll go next to Dan Eggers of Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just following up on the cost-cutting program and kind of the numbers out there. The overall savings are pretty significant relative to maybe what we've seen in... Leo P. Denault: Dan, could you speak up? We're having trouble hearing you. Dan Eggers - Crédit Suisse AG, Research Division: Sorry about that. Just on the magnitude of cost savings, could you share a little more color on where you guys expect to find the savings? When we've seen past M&A transactions recently, their savings have been in line or smaller than what you guys are talking about today. So just kind of trying to bucket those a little better would be helpful, I think. Leo P. Denault: Sure. Rod? Roderick K. West: Sure. Dan, I think, as we've discussed in prior conversations, the -- what you know and what we call the HCM process has been centered around 4 work streams, and both Drew and Leo alluded to them. The first is the Oregon process and I think that one answers your question in terms of where we think the lion's share of, at least, what we've communicated today, rest, particularly as we look to what's meaningful in '13 going to '14. Then you have comp and benefits, procurement costs, management and then the non-employee related operational expenses. And so the lion's share of the savings, order of magnitude, 1/2 to 2/3 perhaps, comes from our Oregon and process point of view. Dan Eggers - Crédit Suisse AG, Research Division: And I guess, just -- yes, you guys reiterated the 6% earnings growth of the utilities. That would then include the 2014 savings, I guess? So was there a bit of a backfill on supporting that 6% growth or is that number actually biased higher because you'll have more savings in those numbers for next year? Andrew S. Marsh: We're not considering it added to the 6%, as I mentioned. There could be some small benefits short term but, ultimately, we expect it to be recognized in filings when it's sort of known and measurable and within the regulatory process of the utility. So we're not counting it really as incremental to the 6% target.

[Operator Instructions] We'll go next to Jonathan Arnold at Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Just to clarify on the ITC mitigation plan, as proposed, how would you envisage kind of those credits flowing through the financial statements or not? I mean, how... Leo P. Denault: Drew? Andrew S. Marsh: It's -- we're still looking at it. Preliminarily, we would expect it to be a part of -- it would be reflected in the net revenue. But there's -- it could change with final orders that we ultimately get. The only change that we would see would sort of be whether or not we would recognize a liability on the balance sheet for the first 5 years. After that, everything is contingent and so it, clearly, wouldn't be a balance sheet liability. But, at this point, we expect it to flow through in net revenue. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Just flow through in net revenue as incurred, basically? Andrew S. Marsh: Correct. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. And then my second one. On Page 12 under EWC, you have this -- you mentioned depreciation as a driver for '14. And then declining useful life of nuclear assets. Can you clarify that latter part of that statement? Andrew S. Marsh: Yes. That was related to a potential change where, currently, we had accelerating depreciation as we get closer and closer to the end of life of the units, and we may make a change where we flatten that out a little bit. But that's -- I think that's the primary thing we're talking about there. Jonathan P. Arnold - Deutsche Bank AG, Research Division: So that would be beneficial to earnings? Sorry, just to make sure I... Andrew S. Marsh: No. Well, it would be beneficial to the end tail of the earnings. It would be against earnings. It would be harmful to earnings, actually. Jonathan P. Arnold - Deutsche Bank AG, Research Division: So it's a negative '14 driver? Andrew S. Marsh: Yes. Jonathan P. Arnold - Deutsche Bank AG, Research Division: And how -- is that included in the sort of EBITDA look that you put on the later slide? Andrew S. Marsh: No, no it's not. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. Any sort of idea how much that might be or is it small? Andrew S. Marsh: We don't have -- we're not -- we don't have that information right now. But we'll give you additional details later.

And we'll go next to Andy Levi at Avon Capital.

Just on -- getting back to the cost savings. So on the EWC side, you have -- 35% to 40% of that segment would realize the cost savings. And then as you said, you have the EBITDA on that slide kind of coming down in '14. So -- and then you kind of were kind of vague on whether, ultimately, the savings were going to be incorporated in '14. So does that mean that we'll see them in '15 or -- I just kind of need some clarification. And then I have one other quick follow-up. Leo P. Denault: I think, Andy, the clarification was is that the EBITDA number did not include HCM, but we would anticipate there would be some... Andrew S. Marsh: In '14. Yes, the bulk of the segment we would expect to see for EWC in '14.

Okay. But that slide does not include the savings from HCM? Andrew S. Marsh: Correct.

Perfect. Okay. And then the other thing, just moving on to ITC very quickly. You have all these kind of rate mitigation things for the various states. Can you give us a breakdown on how much of those savings are from, let's say, the System Agreement versus just kind of other savings? Leo P. Denault: Can you repeat that question, Andy?

On the ITC Entergy deal, there's savings from the System Agreements going away, right? And then there's savings, and so I'm just wondering what the breakdown of that is? So let's say -- I'm just throwing out a number. Let's say in Louisiana it's $100 million of rate mitigation that's going to the customer. What's kind of the breakdown of that? Theodore H. Bunting: Andy, are you referring -- this is Theo. Are you referring to the avoided cost...

Yes, exactly. Roderick K. West: Column on Page 3 -- Slide 3?

I don't know if it's on Page 3, but... Roderick K. West: If you're referring to the Avoided Cost column, it includes costs that would go away as a result of the transmission business going away. And, therefore, there's no more MSS-2 transactions potentially between the various operating companies. And also I think it also reflects maybe some impacts of zonal -- a change in pricing zone structures. I don't have in front of me the various pieces and parts as it relates to those 2 components, but I think we could follow up and get that to you.

And we'll go next to Greg Gordon at ISI Group. Greg Gordon - ISI Group Inc., Research Division: So when I think about the HCM program in terms of its impact on your Utility businesses, should I just think about this as being -- driving the ability for you guys to have a higher confidence level in earning at your authorized returns across the jurisdictions prospectively? I mean, I think your guidance this year, for instance, presumes a significant level of under earnings. So the HCM program would have 2 benefits: one, it would reduce the necessity for rate increases, but also keep your cost profile from creating regulatory [indiscernible]. Is that the right way to think about it? Leo P. Denault: That's fair, Greg. I mean, the major component is to become more efficient, and through the efficiency, we should end up with lower rates, lower costs to our customers, and have a better shot at earning the rate of return that we're allowed. That's correct. Greg Gordon - ISI Group Inc., Research Division: Right. And if -- my one follow-up. If you were to be ordered to implement the rate mitigation plans by establishing regulatory liabilities, as opposed to running it through on a -- running it through the P&L, we should assume then that's an offset to rate base, right, that lowers your rate base? Is that right? Leo P. Denault: Drew? Andrew S. Marsh: Well, we would only get to do that if we got a rate order, a rate deferral. I would think of it more as a regulatory asset that we would be able to realize over time on a one-time incurred costs. Greg Gordon - ISI Group Inc., Research Division: Well, if you had a regulatory liability, right, that would flow through as a contra-expense but you'd have a reduction in revenue. So you'd wind up having sort of an upfront write-down and then flow the cash -- there would be a cash impact as you flowed the credit risk back [ph], but not an earning impact? Right? Theodore H. Bunting: This is Theo. I think what would happen if, in fact, you booked it upfront, you would recognize the liability. But the cost, obviously, would be recognized as an expense at the time you booked the liability, if in fact that was the case. As Drew said, that's not what we're saying, at this point in time, would be the case. If in fact, you had a liability as part of a regulatory construct, I would imagine that you're not likely to see that as it relates to regulatory rate setting going forward. Greg Gordon - ISI Group Inc., Research Division: Great. But you're -- so -- Okay, so you think that the most likely outcome should these mitigation plans be approved is they'll flow through as you flow back the -- as they flow back the customers, you'll incur the expense. Your human -- your cost-cutting plans allow you to sort of plow through that and still close the gap between your current ROEs and your future authorized ROEs? Theodore H. Bunting: As you state, I mean, the -- if in fact, it happens as we see it or expect it today, you would see the impacts of the rate mitigation flowing through currently as reduction to revenue, which obviously would have a -- put downward pressure on ROEs. You would also have, as the regulatory processes move forward, you would see the impacts of cost-cutting making their way through the regulatory process. That could happen at various points in time. Obviously, as that happens, as Leo mentioned earlier, we would see rates being adjusted to reflect those changes in cost structure within the utility. So for a period of time, there is a potential that you could have offsets but, again, as you go forward and the regulatory process encompasses those rate reductions within the setting of rates, the rates would be adjusted commensurate with that and those benefits would flow back to customers at that point in time.

And we'll go next to Steven Fleishman at Wolfe Research. Steven I. Fleishman - Wolfe Research, LLC: Yes. Two questions in 10 parts. Just on the percent O&M increase, could you possibly breakout that 0.5% to 2.5% just for the EWC business? Andrew S. Marsh: I don't have that in front of me right now, Steve. Steven I. Fleishman - Wolfe Research, LLC: Okay. And then also on the target of 6% growth in 2014, if you achieve that in 2014, would you generally be earning your allowed returns in your regulatory jurisdictions, overall? Or would you still be under-earning? Theodore H. Bunting: Steve, this is Theo. Yes, I believe -- if we achieve that, we would -- I think we'd be -- I think, yes. I think the answer is yes, we'd be pretty much be earning our allowed ROEs within the constructs of the jurisdictions. Steven I. Fleishman - Wolfe Research, LLC: Okay. So in theory that -- the cost-cutting is kind of helping you to get to earn it and will in the future at the utilities, I guess. One last just thing on the HCM. The compensation benefits procurement that you mentioned, are those included in the $200 million to $250 million or not? Roderick K. West: Steve, this is Rod. They are currently included. I was just making the point earlier that the lion's share of that number was in the Oregon process, but all 4 work streams are and will continue to contribute to our point of view on the 200 to 250.

We'll go next to Charles Fishman at MorningStar. Charles J. Fishman - Morningstar Inc., Research Division: On the rate mitigation plan in year 6, when it's determined by the savings, who is the arbitrator of that savings? Is it MISO? Is it the state commissions? Do you hire an independent consultant? In other words, who is making that decision of what the savings are? Theodore H. Bunting: Charles, I think if you look at what has been filed as a part of that rate mitigation plan, I think what we would -- what has been proposed is you would have an independent third-party that would be approved by some regulatory -- would be mutually agreed upon between ITC and some -- a regulatory body.

And unfortunately that is all the time that we have for questions today. I'd like to turn the conference back over to Ms. Waters for any additional or closing remarks.

Thank you, Anthony, 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 4532989. 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 proposed spin-merge transaction with ITC. The telephone replay will be available through August 7. This concludes our call. Thank you.

And this does conclude today's presentation. We thank everyone for their participation.