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 William M. Mohl - President of Entergy Wholesale Commodity Business - Entergy Corporation Theodore H. Bunting - Group President of Utility Operations

Greg Gordon - ISI Group Inc., Research Division Paul Patterson - Glenrock Associates LLC Jonathan P. Arnold - Deutsche Bank AG, Research Division Dan Eggers - Crédit Suisse AG, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Steven I. Fleishman - Wolfe Research, LLC

Good day, everyone, and welcome to the Entergy Corporation Third Quarter 2013 Earnings Release Conference Call. Today's call is being recorded. At this time, for introductions and opening remarks, I would like to turn the conference over to 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 sale of the shares of ITC common stock to be issued to Entergy's shareholders in connection with the 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. 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 a prospectus of TransCo related to the proposed transaction. 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 registration statements, prospectuses and other documents referenced above, when they are available, and any other relevant documents because they contain important information about ITC, TransCo and the proposed transactions. These documents and other documents related to the proposed transactions, when they are 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. I've been talking a lot lately about simplification. In my remarks, I will review major events of the past 3 months and how they relate to that objective. As I know many of you are well aware, especially given the number of other earnings calls scheduled this week, the annual Edison Electric Institute Financial Conference is just around the corner. As such, we will focus the call today on updating you on the developments in the past 3 months and defer more strategic updates to the conference. Starting with the proposed transaction to spinoff and merge the transmission business with ITC Holdings. In September, Entergy Texas and ITC refiled our application for transaction approval before the Public Utility Commission of Texas, acting on the opportunity the commissioners gave us in the August 9 open reading. The refiled application put in the record the enhanced rate mitigation plan that includes a benefits test and mitigation of 100% of the effects of the weighted average cost of capital for retail customers, as well as other testimony quantifying the benefits to customers. The Texas Commissioners agreed to hear the matter directly next month, and briefing will end in December. In Mississippi, briefing concluded at the end of September, and an order is now pending from the Commission. In Louisiana, a revised procedural schedule was set to conclude briefing on November 8. In Arkansas and New Orleans, we are working with the parties to come up with a new schedule. Efforts were temporarily suspended during the quarter until the refiling in Texas was made. And in Missouri, an order is pending. These schedules, once set in each of the jurisdictions, will provide more insight about the potential timeline for the transaction. The revised closing date in 2014 has not been settled upon. It will take at least 60 to 90 days after all regulatory approvals are received to close the transaction. Clearly, that puts any closing after December 31, after which our definitive agreement with ITC may be terminated by either party if the transaction has not been consummated. We continue to believe this strategic imperative to execute on the ITC transaction will result in optimal value for all stakeholders. While our operating companies are fully capable to own and operate the transmission system, we know ITC's independence, broader regional planning and sole focus will improve the reliability of the grid, reduce congestion, attract new generating resources other companies may be hesitant to build today and provide our transmission employees better opportunities for their future. These benefits will ultimately lead to lower delivered energy cost for our customers and our communities, promoting the economic good and helping to attract new businesses and industries to our region. Under the proposed rate mitigation plan, the risk of delivering on these economic and operational benefits rests with the Entergy operating company and ITC. That said, we know clarity on the future direction of our transmission system is needed for everyone, and we are committed to that clarity by early next year at the latest. Another key element in the simplification effort is to resolve ongoing rate proceedings in all of our retail jurisdictions. Rate cases are a basic part of our business, but we know the number of outstanding cases at one time creates uncertainty for all of you. We received 2 orders in August, one in Mississippi and one in New Orleans, on formula rate plan filings. On August 13, the Mississippi Public Service Commission unanimously approved a stipulated settlement between staff and Entergy Mississippi, resolving the 2012 test year FRP. The settlement called for a $22.3 million rate adjustment to be implemented over 9 months, starting in September. The rate change, the first in 4 years, provides funds necessary for increased reliability and capacity for economic growth. Also, in August, the City Council of New Orleans approved a black box settlement for Entergy New Orleans' 2011 test year FRP filing. Under the approved settlement, electric rates will decrease by $1.6 million relative to pre-October 2012 rates. There was no change in gas rates. This marks the fifth electric indoor gas rate decrease in the last 5 years. The next step in New Orleans is likely a base rate case filing in mid-2014. However, we intend to discuss with the Council and their advisors' various rate-making alternatives to a full base rate case. Last month's planned rate case filing was temporarily delayed to allow time for such alternatives to be explored and discussed. Next, in Arkansas. A final decision in the Entergy Arkansas rate case is expected by year end from the Arkansas Public Service Commission. Entergy Arkansas' most recent filing in the scenario of joining the Midcontinent Independent System Operator only reflected a $145 million base rate increase at a 10.4% ROE. About $49 million of the increase in base rates is a transfer of revenue already being recovered through riders that will terminate. Regarding pending rate cases before the Louisiana Public Service Commission, we expect resolution by May of 2014. As a reminder, filings made in February requested base rate increases for the MISO-only scenario of $144 million for Entergy Louisiana and $24 million for Entergy Gulf States Louisiana, both cases reflected a 10.4% ROE. Entergy Louisiana and Entergy Gulf States Louisiana have agreed to delay testimony in both cases until later in November and early December, respectively, in order to continue to explore settlement options. And in the case of Entergy Louisiana's Algiers rate case before the City Council, the advisors will file testimony in November. The final decision is expected by second quarter 2014. Recall, Entergy Louisiana requested a $13 million base rate increase to be implemented over 3 years in a 10.4% ROE. This would be the first rate change in 12 years for the roughly 22,000 Entergy Louisiana customers located in the city of New Orleans and regulated by the city council. This past quarter, in Texas, Entergy Texas filed a request for a $38.6 million base rate increase, excluding new riders, and a 10.4% ROE. The test year in the 2013 rate case includes the majority of the third-party capacity cost disallowed in the 2011 rate case. In addition, through a special circumstances request in the fuel and purchase power reconciliation, Entergy Texas is requesting recovery of approximately $21.5 million in capacity costs incurred from July 2011 through March 2013 not previously recovered in base rates. If approved, new rates go into effect as early as April of 2014. Successfully clearing the decks of the majority of these rate cases by early next year is a key part of the simplification effort underway. The System Agreement is another area of complexity for all of us. Entergy Arkansas' participation will terminate in December, on the same day we plan to begin operating in MISO, followed by EMI's exit in November of 2015. Earlier this month, on October 18, Entergy Texas provided its notice to terminate its participation in the System Agreement, including filing it with the Federal Energy Regulatory Commission. Prior to that, on October 11, Entergy Services filed with FERC a change to the System Agreement exit notice provision to 60 months from 96 months. FERC acceptance of the change in the notice period is required for it to become effective. The FERC filing contemplates that the 60-month notice period will apply to ETI. Similarly, Entergy Texas' notice contemplates that it will be governed by the 60-month notice period or such other period, as approved by FERC. The proposed amendment in ETI's termination notice are without prejudice to continuing efforts among affected operating companies and their retail regulators, the search for a consensual means of allowing ETI an early exit from the System Agreement, which could be different from that proposed in the October 11 FERC filing. Given that after the Entergy Texas exit, there will be only the 3 Louisiana-based operating companies remaining, it is reasonable to question whether the System Agreement should remain in place. The interpretation of the System Agreement has been a constant source of litigation and complexity over the last 30 years. Addressing this will simplify and eliminate the uncertainty it has created for us, as well as all of you. Turning to EWC. Improving results is a strategic imperative we have discussed throughout the year. Last quarter marks 2 steps in that ongoing effort. First, in August, Entergy signed agreements to sell Entergy Solutions District Energy to Brookfield Infrastructure for approximately $130 million. This is a small business you may not have even known we had. The book value was approximately $100 million at September 30. It provides chilled water and steam to customers in Houston and New Orleans, a solid business with growth opportunities better suited in a larger portfolio that can capitalize on those opportunities for customers and our employees. Closing is expected by the fourth quarter. Also, in August, we announced the decision to close the Vermont Yankee nuclear plant at the end of its current operating cycle. I can tell you, the Board of Directors and the executive management team thoroughly reviewed all alternatives in coming to this difficult decision. The employees at the plant operated at world-class levels. In the decade of our ownership, Vermont Yankee has averaged in the 92.4% capacity factor. And it is currently in its fourth breaker-to-breaker run in that 10-year period. While the plant had its opponents, we know the closure will be devastating to the community, including millions of dollars in taxes and other payments annually. I want to personally thank all those who have stood by our side over the years. Operating through fourth quarter next year allows the immensely talented, dedicated and loyal Vermont Yankee workforce the best opportunity to plan their future. It allows the communities to be begin planning for a future without Vermont Yankee as an operating asset, and allows us to plan for an orderly shutdown and decommissioning process. Shortly after announcing the decision to close VY, we amended our certificate of public bid application to operate through December 31, 2014. The CPG decision is now pending before the Vermont Public Service Board. Another area of uncertainty that is likely to continue for some time is the license renewal at Indian Point. Unit 2 entered the period of extended operations at midnight on September 28 and continued operating under the Nuclear Regulatory Commission's timely renewal provision. Indian Point filed a timely application in 2007, and as such, is authorized to continue operating while license renewal matters remain pending. The same will be true for Unit 3 after December 2015 if license renewal is still pending at that time, as we expect. Given the number of issues and parties involved, we currently project final resolution of Indian Point's license renewal application to take into 2018. Indian Point continues to be a vital component of the region's power supply, and we are committed to its continued and safe operation. We continue to believe it meets all the requirements for a renewed operating license. Today, Indian Point is necessary to meet the reliability needs of the grid. That was only further evidenced by FERC's approval of the new Lower Hudson Valley capacity zone in August. We continue to expect implementation of that zone by April of next year. Given the importance of Indian Point to New York, we understand the need for contingency planning to take prudent utility practice. We also agree with the state's priorities for grid reliability, clean environment, low-cost energy, local economic prosperity and the critical importance of safety and security of the plant. In our view, Indian Point is the best answer to meet all of those needs. We also know there are other opinions. For those seeking Indian Point's early retirement, we believe the best course of action is to find common resolution, given the benefits the plant provides. The final topic I wanted to cover this morning is an update on our strategic imperative to optimize through human capital management or what we call HCM. After completing a redesign of our company in July, efforts immediately returns to restaffing the organization to fit the required needs and skill sets. We are over 2/3 of the way through this restaffing process, and we'll complete it by year end. This process is providing many employees opportunities to expand their knowledge, skills and experience. Overall, however, we expect to eliminate approximately 800 positions, the majority by the end of the year. Job reductions are a difficult but necessary result of a restructured design to make the long-term fundamental improvements needed for the business that support adapting to the changing needs of the industry, maintaining reasonable rates at the utility to benefit the existing customers directly and indirectly by attracting new customers to the region and improving financial results at EWC for plants that are challenged in the current low-commodity price environment. Next year, we will be fully engaged in making the new organization vision a reality. Given the progress to date, we project savings, both O&M and capital, in the $200 million range in 2014. These savings estimates are incorporated in the 2014 earnings guidance initiated today, the details of which we will review in a moment. We remain on track to get the full run rate of $200 million to $250 million in savings by 2016, and the total estimated cost to achieve these savings remains in the $145 million to $185 million range. In closing, I know it's not news to any of you that we have a number of strategic imperatives underway enterprise-wide to address the challenges and opportunities facing us, some of which have been under development for years, like joining MISO, an imperative I didn't go through in detail today. Regarding MISO, we believe we remain on track to begin operating in MISO on December 19, which we estimate will produce $1.4 billion in customer savings in the first decade. These imperatives are the right thing to do. Simply put, they are geared to improve cash flows and reduce risk. Success will benefit all stakeholders, whose futures are linked. For our owners, resolution of the current initiatives will help to clarify the future state and earnings and cash return opportunities and potential for both the utility and EWC businesses, reducing the range of uncertainty, operating more efficiently, reducing uncompensated risk and maintaining financial strength that supports continued, safe, secure and reliable electric and gas services at reasonable cost for our retail and wholesale customers. Reliably delivered and reasonably priced electricity and gas helps to retain existing businesses and attracts new ones to our communities. This is particularly true in our utility service territory today. The difference in worldwide oil and natural gas prices, as well as other regional advantages, has led to a window of opportunity. There is now a $65 billion-plus economic development pipeline of industrial projects in our 4-state region. Helping to bring economic development to our Gulf Region creates a multiplier effect with benefits to our communities. In addition, financial strength enables us to continue to provide philanthropy, volunteerism and advocacy in the communities we serve. And for employees, working for a solid company offers better financial security to them and their families, facilitates a productive day-to-day work environment and offers career advancement opportunities. That is the mission of Entergy, to create sustainable value for all of our stakeholders, closing out strategic imperatives and simplifying our business to help us in that regard. We've made some progress, but more work is to be done. And now I'll turn the call over to Drew. Andrew S. Marsh: Thank you, Leo, and good morning, everyone. In my remarks today, I will cover financial results for the quarter, 2014 earnings guidance and other forward-looking financial updates, starting with the quarterly financial results. Slide 2 summarizes third quarter 2013 results on an as-reported and on operational basis. Operational earnings per share were $2.41 versus $1.95 a year ago. Third quarter as-reported earnings in both periods included special items for expenses associated with the decision to close Vermont Yankee and implementation of the human capital management imperative in 2013, as well as the spin-merge of the transmission business with ITC in both 2012 and 2013. The decision to close Vermont Yankee in third quarter 2013 resulted in a noncash impairment of the carrying values of VY and related assets to the fair value of $62 million, as well as other related charges, including the effect of capital spending not chargeable to expense because of the plant's shortened life. Going forward, we'll continue to classify VY's capital spending as operating expense and it will be reported as part of the asset impairment and related charges line item. And we will include this expense, as well as any VY severance and retention expenses as special items this year and next. Slide 3 summarizes operational earnings per share by business segment, including major drivers of period-over-period variances. Third quarter operational earnings per share were higher than the same quarter last year. Results at Utility and Parent & Other increased, while EWC results declined. Utility operational earnings were $2.04 per share, which is higher than $1.72 earned in the third quarter of last year. The overall increase was driven by higher net revenue and a lower effective income tax rate, partially offset by higher nonfuel O&M and higher depreciation expense. Utility net revenue increased due to price and volume factors. As we've noted in previous quarters, pricing adjustments included regulatory actions for productive generation investments placed in service in 2012. These investments benefit customers through improved operational efficiency in a favorable environmental profile. On a weather-adjusted basis, billed retail sales increased quarter-over-quarter. The increase was driven by growth in the industrial customer class, which was 2.7% higher than the same quarter a year ago. Industrial sales increase was due primarily to growth in the chemicals and refining segments. The majority of the increase in the chemicals segment was from chlor-alkali facilities as temporary weakness this past spring abated. In part due to stronger global economic growth and in part due to demand pull from the improving real estate and auto sectors. The refining segment also benefited from an increase in exports. Residential and commercial sales results from the quarter, reflect continued challenges from sluggish regional economic growth, increasing emphasis on energy efficiency and demand side management programs. Moving away from the top line, the effective income tax rate for the utility was lower in the quarter compared to the same quarter a year ago. In the current period, we had favorable settlements from state income tax audits. This resulted in the reversal of previously recorded expense. Partially offsetting the overall utility operational earnings increase were higher nonfuel operation and maintenance and depreciation expenses. A portion of these expenses reflected investments placed in service in 2012 and were offset in net revenues. Other drivers contributed to the expense increases as well. Detail is provided in the Utilities section in Appendix B of our earnings release. Before I move to EWC, I'll briefly discuss Parent & Other, which had an operational loss of $0.09 per share compared to a loss of $0.26 per share in the same quarter last year. The quarter-over-quarter improvement was driven by lower income tax expense, due primarily to the planned utilization of Parent's net operating loss. The EWC operational earnings were $0.46 per share, lower than the $0.49 per share in the third quarter last year. The period-over-period decline was due partly to lower operational adjusted EBITDA, which I'll review shortly. EWC results also reflected higher depreciation expense due to an item recorded in the prior period. The overall earnings decrease was partially offset by a lower effective income tax rate on operational earnings. EWC's effective income tax rate reflects a resolution of the tax issue in the third quarter. Slide 4 summarizes EWC's operational adjusted EBITDA for the third quarter of the current and prior year years. The $20 million decrease was due primarily to higher nonfuel O&M expense, driven largely by increased pension expense. EWC's net revenue was flat quarter-over-quarter. The effects of higher-capacity pricing offset other factors, including lower energy pricing. Slide 5 summarizes our operating cash flow performance. Operating cash flow was just under $1.1 billion for the quarter, $52 million higher than the same period a year ago. There were both positive and negative drivers. One example on the positive side, EAI received approximately $38 million from the Department of Energy for damages in our spent nuclear fuel disposal case. The overall increase is partially offset by higher income tax payments. Moving away from the quarterly results, as part of today's release, we are providing forward-looking financial updates. Today's updates include 2014 operational earnings guidance, our nonfuel O&M outlook, and the preliminary 3-year capital plan. You should note that our forward-looking financial updates reflect our business as it stands today. They do not reflect the proposed spinoff and merger with ITC, which we continue to believe is in the best interest of all our stakeholders. Slide 6 summarizes the 2014 operational earnings guidance. We are initiating [ph] today at $4.60 to $5.40 per share. I would like to highlight a few items, beginning with the 2013 starting point. Business segment guidance midpoints have been adjusted, consistent with current indications. The adjustment is net to 0 on a consolidated basis. Now let's turn to 2014. Utility's 2014 operational earnings guidance midpoint is $5.20 per share, $0.60 higher than the 2013 guidance midpoint. Utility's 2014 guidance midpoint is consistent with the previous 5-year financial outlook, a 6% compound annual growth rate on net income from 2009 through 2014. Among the drivers, 2014 reflects significant progress on our human capital management imperative or HCM. As Leo mentioned, we are estimating total savings of approximately $200 million in 2014. Our current 2014 estimate reflects approximately $180 million in O&M savings with the balance going to capital. The O&M portion is expected to be realized approximately $125 million at Utility and approximately $55 million at EWC. For the Utility, HCM savings affects 2 line items in our guidance table. Obviously, it will reduce nonfuel O&M and also reduces net revenue to the extent projected savings flow-through rates to benefit our customers. Utility net revenue assumptions for 2014 also reflect the conclusion of current rate proceedings. We currently have 5 base rate proceedings in process as well as other requests for riders to recover specific costs, such as MISO expenses. In addition, Utility net revenue reflects approximately 1.9% retail sales growth, driven largely by strong growth in the industrial customer class, including planned expansions. This reflects chlor-alkali and steel mill expansions expected to come online beginning in the fourth quarter of 2013 and refinery expansion coming online in mid-2014. Sales growth, excluding the effects of industrial expansions, is anticipated to be approximately 0.6%, including our expectation of renewed growth in the residential class. We talked about the significant economic development activities within our service area. In fact, just last week, Entergy Gulf States Louisiana announced another contract to provide up to 30 megawatts of power for at least 10 years to Methanex's new methanol facility in Geismar. Our 2014 guidance reflects industrial growth that is well within our line of sight. Finally, the Utility midpoint reflects an approximate 33% effective income tax rate in 2014. But calculating the effective income tax rate at Utility, note that the dividend income of the Utility preferred [ph] is nontaxable, provided the structural reduction as illustrated in the 10-K. Considering that effect, we have an approximate 36% effective tax rate from expected income tax benefits included in our guidance. Now let's turn to EWC. EWC's 2014 operational earnings guidance midpoint is $0.85 per share, which also reflects savings from HCM, as I mentioned earlier. EWC's net revenue includes an assumption from improved capacity pricing from a new Lower Hudson Valley capacity zone. The guidance midpoint assumes up the [ph] relative to rest of state associated with the LHV capacity zone of approximately $3 per kW a month on an annualized basis. The uplift assumption represents our risk-weighted point of view, reflecting different scenarios that consider potential outcomes of various factors, including reference unit technology, demand curve's 0 crossing point, vocational capacity requirements and the potential for various mitigation outcomes. As you know, it is not our practice to incorporate our point of view into our forward-looking disclosures. However, given the significance of the change, the near-term timing of the implementation and the lack of market information, we decided that it would be appropriate to incorporate a price fee for LHV. We will revert to using forward markets prices in our forward-looking statements once the market more fully forms up. Another key driver in EWC at 2014 guidance is depreciation expense, which is approximately -- which is higher by approximately $0.25 per share and reflects a few considerations. For Vermont Yankee, the decision to shutdown the plant earlier than previously expected results in higher year-over-year depreciation for that plant of $0.04 per share in 2014. Growing depreciable plant balances associated with capital investment also contributes to higher depreciation expense. And finally, one thing that may not have been on your radar, we periodically conduct depreciation rate studies. The year-over-year change reflects the estimated effects of revised depreciation rates based on a new depreciation rate study. In 2014, this expected change accounts for approximately 2/3 of the total year-over-year change or about $0.17 per share. We will continue -- and will continue in future years. Keep in mind that the change in depreciation expenses does not affect EWC's operational adjusted EBITDA. Before leaving this slide, there are a few general assumptions I'd like to mention. First, the consolidated 2014 guidance reflects an approximate 36% effective income tax rate. Next, the 2014 midpoint also assumes the pension discount rate of 4.75% compared to 4.36% in 2013. The final pension expense for 2014 will be based on interest rates, market results and other assumptions that will not be available until early next year. Finally, Section 6 of our earnings release, where we outline 2014 earnings guidance, includes additional details on key assumptions as well as earnings sensitivities for 2014. Today, we're also updating our nonfuel O&M outlook. As you can see on Slide 7, we are estimating total operational nonfuel O&M, including refueling outage expense, to be approximately $3.5 billion in 2013 and $3.35 billion for 2014. These estimates include Vermont Yankee expense. The amount of VY direct costs in the 2013 base year is approximately $145 million. This 2014 estimate is consistent with our 2014 guidance midpoint and reflects HCM savings, as we've previously discussed, as well as other year-over-year changes. The 3-year outlook indicates the compound annual growth rate of 0.5% to 2.5%. As you think about the current 3-year view, with VY ceasing operations by the end of 2014, the same range would apply to the 2013 base year, but excluding VY direct costs from the base year. Just a reminder, the 0.5% to 2.5% is the 3-year CAGR. Growth rates can vary from year-to-year. Consistent with past practice, we're also providing our preliminary 3-year 2014 through 2016 capital plan in Appendix E of the release. You can see on Slide 8 the preliminary plan totals $6.8 billion, roughly in line with the previous 3-year period. In closing, in a couple of weeks, we'll be at the EEI Financial Conference, and we'll have the opportunity to meet with many of you. Needless to say, we as a company and as an industry, have many topics to cover. While at EEI, we'll review some of the topics we've discussed today. Overall, we expect that -- overall, topics we expect to discuss are current initiatives such as ITC, current regulatory dockets and rate cases and our Human Capital Management program. Other subjects include: opportunities for our region's economic development pipeline, investment opportunities at Utility, efforts to improve EWC results, and any other topics of interest. We look forward to seeing you at EEI. And now, the Entergy team is available for questions.

[Operator Instructions] Will go first to Greg Gordon with ISI Group. Greg Gordon - ISI Group Inc., Research Division: My first question is on the expense outlook. So I know the guidance midpoint of $5 is unchanged from -- but the components have changed significantly. And specifically, the guidance midpoint at the beginning of the year for Parent & Other was $0.50. It's been rebased to $0.85 in the context of the current $5 guidance, and rises to $1.05 next year. Can you take us through the progression from $0.50 to $0.85 to $1.05? And then I have a follow-up. Leo P. Denault: I'll let Drew handle that, Greg. Andrew S. Marsh: Well, as you know, the Parent & Other is primarily comprised of interest expense and taxes. And of course, there's the affiliate preferred expenses in there as well. So that's certainly contributing as that's grown. The primary thing to think about is the tax piece of it. And particularly, as we move into 2014, we have historically used a weighted average sort of probability expectation of what our income tax is. And we place that in the Parent at the a beginning of the year, given the certainty of where it may ultimately shake out. This year, we have a better expectation of where it would probably land in that set Utility, so we've highlighted some of those Utility income tax benefits that I discussed a minute ago. That's the primary driver that you see kind of moving forward. Greg Gordon - ISI Group Inc., Research Division: Okay, great. And my follow-up question is on the CapEx guidance. It looks to me, based on where your 2014 rate base is sort of going to end up, based on looking at your rate case filing, et cetera, that the level of CapEx spending, minus level of depreciation you played out in your slides, that the rate base growth profile looks like it's more or less the same rate, i.e., around 6%, that had it had been in the past. So assuming consistent rate treatment, wouldn't it be fair to assume that your earnings growth aspiration would be consistent with that through '16? Leo P. Denault: You're jumping ahead of us a little bit on that, Greg, in terms of providing any kind of forward-looking outlook. We will discuss a little bit of that when we get to EEI in terms of what the opportunities are going forward and where we see the Utility. But, right now, we're not really prepared to go out beyond 2014. Greg Gordon - ISI Group Inc., Research Division: I'm sorry. But arithmetically the -- but arithmetically, it looks like rate CapEx minus depreciation, you're growing at about a 6% rate from '14 to '16, based on what you outlined, is that fair? Leo P. Denault: There are other components of rate base. But the pieces you're looking at have -- but there's deferred taxes and other things that go into that calculation as well. And I'm not trying to argue the math with you. I apologize, I'm just not prepared to go beyond 2014 right now. Sorry about that, Greg. I appreciate the question, though.

And we will now go to Paul Patterson with Glenrock Associates. Paul Patterson - Glenrock Associates LLC: Just wanted to touch base on the depreciation study. It sounded like quite a significant move in expected depreciation because of it. And I was wondering if you could just elaborate a little bit more as to what went into that? Leo P. Denault: Yes. Drew? Andrew S. Marsh: So we use the group method of depreciation, which means that from time to time, we have to do an updated depreciation study to sort of reflect consistency with our actual experience. And we alluded to it very briefly on our last call, but didn't really give it a full discussion. Ultimately, the effect is to take away large increases that we would expect to see towards the end of life for the nuclear assets and sort of make the depreciation more ratable, like you would expect under normal situations when you kind of go forward. As you think about depreciation, it's a zero-sum game. By the time you get to the end of life on an asset, you're going to have to depreciate all of it. And so we're -- it's a little more ratable now with the new depreciation study. It doesn't affect the cash flow at EWC. Paul Patterson - Glenrock Associates LLC: Okay. So it would suggest that the detriment in value that we'd be seeing later years is now being brought forward. And so, I guess, near term, the EPS would be more conservative in terms of the value of those plans, is that the way to think of it? Andrew S. Marsh: Yes, on an EPS basis, yes. Not on EBITDA basis. I think it would be about the same that we were seeing before. Paul Patterson - Glenrock Associates LLC: Okay. Then moving to Slide 18, on EBITDA basis, you guys show it, an increase now in 2014 versus 2013 versus last quarter. And I was wondering, you mentioned a few things on the slide, one of which has to do with Vermont Yankee. And I'm wondering whether or not the fuel expense is being reflected in EBITDA since the expense of, I believe, is being amortized. That's number one. And then number two, what's leading to those changes? I mean, I realize that there's a change in prices that would be benefit, I guess. If you could just elaborate, sort of just give us a little bit more quantification or sensitivity to that. Leo P. Denault: I'll answer the first one, and then I'll turn the second none over to Bill. Fuel amortization is in the EBITDA number for Vermont Yankee. Paul Patterson - Glenrock Associates LLC: So that's being reflected in Slide 18, the expense of fuel, the noncash expense of fuel? Leo P. Denault: Yes. One thing to think about there is fuel is -- it's part of the write-down. You write-down all of the assets at Vermont Yankee, not just the actual plant itself. So that includes part of the fuel, so you see the fuel going down as well there. Paul Patterson - Glenrock Associates LLC: Okay, so that's benefiting EBITDA? Leo P. Denault: Yes. William M. Mohl: As it relates to the revenue side of things, from a capacity perspective, Drew mentioned the fact that we included Lower Hudson Valley in our projections for 2014, basically assuming a $3/kW-month increase over rest of state prices. So that's included in our numbers here. Paul Patterson - Glenrock Associates LLC: Would that change from last quarter? William M. Mohl: Yes. I think, last quarter -- we've typically been talking in a range of what we've expected. And I think, even in the last call, there was a little bit of confusion in terms of what was actually included, but in terms of how much was included over rest of state. So this is much more specific that we're including the $3 per kW-month on an annualized basis for Lower Hudson Valley. Andrew S. Marsh: And I'll just add, Paul, that we have historically used market views, and there wasn't a market view of Lower Hudson Valley, so we didn't have it. What we had was effectively a rest-of-state view in our last call. So this time, we are explicitly pointing out that we're putting a point of view in place for Lower Hudson Valley, since there's no specific price target out there. And we'll go back to a market view once that develops.

[Operator Instructions] We will now go to Jonathan Arnold with Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: One question on VY, when you made the announcement about the shutdown, you said it was expected to be sort of a negligible contribution to 2013 at the bottom line. So firstly, I guess, is that still the case? And then, you give us an EBITDA number for '14, but with all these other moving parts, can you kind of comment on how much is the actual depreciation associated with VY in '14? And what would your, sort of, net-income-type expectation be embedded in these numbers in '14? Leo P. Denault: I'll let Drew answer it. Obviously, when you say negligible in 2013, certainly, the -- on an operational basis, it's negligible. And on an as-reported basis, I wouldn't necessarily call the parent negligible. But... Jonathan P. Arnold - Deutsche Bank AG, Research Division: I think you -- okay, fair enough. You said around breakeven operationally. Leo P. Denault: Operationally. Operationally. Andrew S. Marsh: That's right. And I think that's still the case. I think it's a little better, as we've pointed out, because of, like, the fuel write-down. And we're seeing a little bit of that in '14. In '14, there's a little more EBITDA pickup because of the fact that we're not actually having a refueling outage in that particular year. And so, that's what's your -- that's part of the driver for the improvement in EBITDA in '14, which we wouldn't have other normal -- otherwise seen under normal operating conditions. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. And you attributed $0.04 of the $0.25 depreciation delta to VY. But can you give us the -- what is the number that refers to the delta? Andrew S. Marsh: I don't have the exact depreciation for total VY in front of me, but we can follow up with that offline. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. And then just on one other topic, if I may. You have -- in the nonfuel O&M outlook slide, the reading that's rightly -- the 0.5% to 2.5%, should be looked at net of the VY cost. Firstly, is that correct? Andrew S. Marsh: Yes. What we're trying to point out is you could take the $145 million of direct cost out of sort of our base year of 2013, and you could still apply the 0.5% to 2.5% compound annual growth rate to that. And that would be sort of our revised view of where we might get to in 2016. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. So if that holds, though, looking at the slide, you have the step down in the underlying costs, and then -- yet the CAGR is still up to 2.5% in '16. I mean, when you do the math on sort of what looks like a somewhat quantifiable step down in '14, to get to 2.5% growth CAGR sort of 3 years compound by '16, you'd had to have some pretty much higher percentages than that. What kinds of things could drive you to the high end of that range, I guess, is my question? Or am I missing something on the map? Andrew S. Marsh: Yes. I think the big things are, like, pension expenses could be a big driver, if we were to acquire to more assets within the Utility, for example, that certainly adds more O&M expenses. Those are the kinds of things that could drive it up, if there are additional regulatory costs, that's something that certainly grown outside of typical inflation growth rates over the last few years. Those are the kinds of things that could push it up. Given our current expectation, 2.5% is probably on the -- it is on the high side, obviously. And I don't think under normal operating conditions, we'd expect to get all the way back to 2.5%. But those are the kinds of things that we're trying to account for, given the uncertainty associated with where the portfolio may go or where pension expenses may go, that kind of thing. Jonathan P. Arnold - Deutsche Bank AG, Research Division: So it includes potential portfolio additions, that presumably would up revenues associated with them at the high end? Andrew S. Marsh: Yes, 2.5% is accounting for the possibility of that. That's not to say that, that's what we are going out to do right now. It's just within the range. Jonathan P. Arnold - Deutsche Bank AG, Research Division: But in order for it to be that high, would it require that relative -- I'm just not sure how significantly to take that as part of this answer. Andrew S. Marsh: I mean, you were asking what could drive it up there, that's what we were thinking about when we put a number out there like that. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. And if I -- can you just share your with us sort of what you're trying to achieve, what's your budget, if not much else changed? Andrew S. Marsh: Outside of the 0.5% to 2.5% growth area? I mean, I think that's where we are generally targeting. I mean that's what our -- we were trying to achieve the low end to that range, an idea where we might even beat it. But that is -- that's where we were comfortable putting out our guidance on '14 to '16 CAGR.

And we will now go to Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Leo, just catching on kind of your ends of the EWC comments, you seem like you've made note of the idea of maybe trying to find some sort of settlement or resolution on any endpoint, given the time horizons and license extension, that sort of stuff. Can maybe share some color on kind of what the tone or interest is on that and whether that's something you can realistically get done in sort of timely fashion? Leo P. Denault: Really, Dan, all I'm trying to say is nothing different than what we've said before. We really view Indian Point as a high quality asset, very vital to the region. And certainly provides the majority of the benefits that you would like to see in a power market in the economic environment. It provides jobs. It provides tax base. It provides reliability to the grid. It provides low-cost clean energy. It provides all the things, from a public policy standpoint that you would want. And certainly, we recognize that there are some folks who would like it to not operate to the end of its license life, and that's certainly not the opinion that we have. We think it's vital not only today, but it will continue to be a vital part of that market for years to come. We're just acknowledging that we know other people have a different point of view. And if there's something there that could result in common ground, where we can come up with, as we've talked about before, the certainty equivalent of value and glide path for the market, we'd be willing to do it. But there's no more emphasis on it than that. It's just something we're willing to explore. Dan Eggers - Crédit Suisse AG, Research Division: Okay, got it. And then on the ITC process with, I guess, the commissioner coming out on Friday and saying that voter decision couldn't presumably happen until January, given their scheduling and how that corresponds to a year-end merger agreement date. Would you guys need to formally extend the merger agreement to keep the deal going beyond December? Can you guys kind of function in an at-will basis pending more regulatory action? Leo P. Denault: Technically, the merger agreement allows either of us to terminate the transaction after December 31. How we'll handle going beyond December 31 will be dependent on seeing the rest of the procedural schedule, and seeing what comes out of Arkansas and New Orleans, for example. And then, obviously, something that ITC and us will have to consider. But we're not prepared to go there at the moment. Dan Eggers - Crédit Suisse AG, Research Division: But just -- from just a technical perspective, would you guys need to sign a new agreement be to go beyond year-end 2013? Or could you guys function without an explicit time extension involved? Leo P. Denault: Technically speaking, we would not have to amend the agreement.

And we will go to Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: First, just with regards to the $5.20 at the regulated [indiscernible] next year, how do you think about that within the context of your earned ROEs overall? I appreciate that you have pending rate cases, et cetera. But generally speaking, would you say that you're earning your ROE in that $5.20? I suppose that was contemplated in your initial 6% growth CAGR, I suppose. Leo P. Denault: I'll let Theo talk about what, on each of the utilities, to the extent that he can. Theodore H. Bunting: Julien, it's Theo. Actually, I think, the last comment you made probably speaks to the best way to describe and respond to your question. I can't talk specifically on -- respond specifically to kind of what the assumption was. But obviously, the growth assumption in 2014 is consistent with, obviously, all of our other planning assumptions. And as you look at 2014 and you see that our growth assumption hits the 6%, you would expect that you're planning assumptions are aligned, then that would produce something that would be relatively within the range of what we would expect to achieve from earned-ROE perspective, as it relates to our allowed ROEs. With that said, the 2014 rate case is obviously -- don't go full -- don't go in effect at the beginning of the year in their entirety, some go in effect later in the year. And also, there is some small element of regulatory lag. Obviously, since you file the cases, from the time you file to the time rate's go into effect. But, obviously, when you see the 6% growth aspiration in 2014, achieving that, you would think -- you would also -- I think, we'd also say that, that moves us closer to our goal, obviously, which is to earn our allowed ROEs within the context of Utility. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Great. And then with regards to the latest update guidance. I suppose, in the preliminary release just that it was towards the midpoint now. Could you talk of what changes occurred in the quarter that led to that decision? Specifically, I suppose, the district sale appears to be reflected in your adjusted EBITDA in '13. Just perhaps, the various walk, if you will, to get to that, I suppose, revised range within the '13 range. Leo P. Denault: We didn't change the range, Julien, you're just talking about the fact that we said we should be around the midpoint. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Yes. Leo P. Denault: Okay. Drew, I don't know... Andrew S. Marsh: Yes. I don't think -- I think our suggestion before was that we weren't -- I think at the beginning of the year, we were suggesting that we were at the lower end of the range. And I think maybe the -- after the first quarter or the second quarter, we said that we were no longer in the lower end of the range. And for now, we're just saying we're in the middle. So I don't think, from our perspective, we've really moved a whole lot. And so, you're right, the district energy sale is reflected in there, it's about $0.15, and so that's part of the overall piece. But as you may recall from the beginning of the year, on January 1, we had about a $0.20 deficit on the pensions that we had to overcome because interest rates fell so far towards the end of last year. And so, I think that if you look across the businesses, I think there's good -- there's gives and takes at EWC, for example, with higher pricing in the first half of the year on energy, higher capacity pricing through the middle of the year, but some reductions from a volume perspective. And at the utility, I think there has been a little bit of negative weather, and that's offset a little bit lower growth -- well, I shouldn't say it's offset, it's a little -- there was a little bit lower growth than maybe we expected at the beginning of the year. That's been offset by some tax benefits and some other things. So I think, actually -- and I'll probably mention that, too, on the tax side, we guided you at the beginning of the year to about a 34% effective tax rate. And while we expect to do a little bit better than that by the end of the year, we expect it will to still be around that 34% effective tax rate range.

And we will take our last question from Steven Fleishman with Wolfe Research. Steven I. Fleishman - Wolfe Research, LLC: Just to -- I wanted to think a little bit about kind of the Utility net of parent drag. When you look at the guidance for '14, I guess you have a $5.20 Utility, $1.05 of parent drag, that's about $4.15 net. Is that a good clean base to think of kind of a future growth for the core Utility business? Leo P. Denault: Drew, you want to ...? Andrew S. Marsh: You're asking about the Utility preferred elements of that, Steve? Steven I. Fleishman - Wolfe Research, LLC: Not necessarily, specifically. let me ask the question this way. So your 2013 initial guidance had $4.70 for the Utility, $0.50 of parent drag, so a net of $4.20. So even though the Utility has gone up a lot, it's been all kind of absorbed by, in the '14 guidance, a much bigger parent drag. So I just want to kind of think about on a moving forward basis, is this kind of a clean year for Utility net of parent from which to really think about growing the company? Andrew S. Marsh: Yes. I mean, I think -- let me answer it this way. I mean, beyond 2014, we should have a pretty good view of our rate cases, as Leo mentioned earlier, and so that part will come into play. The HCM program should be in full swing, and we're going to try and get a better view of what we can do maybe even beyond HCM going forward, we're beginning to work on that. And a big piece of what the storyline is going to be beyond 2014 is going to be the possibilities with industrial growth at the Utility. And whether or not our historical load growth can actually begin to move at a higher rate than what we've seen, thanks to sort of the industrial renaissance. And I think we're going to talk a little bit more about that at EEI when we get there.

That concludes today's question-and-answer session. Ms. Waters, at this time, I will turn the conference back to you for any additional or closing remarks.

Thank you, Angela, 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 8044514. 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-merge transaction with ITC. The telephone replay will be available through November 5, 2013. This concludes our call. Thank you.

Ladies and gentlemen, this concludes today's conference. We thank you for your participation.