David Borde - VP, IR Leo Denault - Chairman and CEO Andrew Marsh - CFO and EVP Roderick West - EVP Christopher Bakken - Chief Nuclear Officer & EVP Theodore Bunting - Group President of Utility Operations, Chairman, CEO, and President, System Energy Resources, Inc.

Christopher Turnure - JPMorgan Chase Jonathan Arnold - Deutsche Bank AG Julien Dumoulin-Smith - UBS Investment Bank Michael Lapides - Goldman Sachs Group Inc. Shahriar Pourreza - Guggenheim Securities Praful Mehta - Citigroup Charles Fishman - Morningstar

Welcome to the Entergy Corporation First Quarter 2017 Earnings Release and Teleconference. [Operator Instructions]. As a reminder, today's conference is being recorded. I would now like to introduce your host for this conference call Mr. David Borde, the Vice President of Investor Relations. You may begin.

Thank you. Good morning and thank you for joining us. We will begin today with comments from Entergy's Chairman and CEO, Leo Denault; and then, Drew Marsh, our CFO, will review results. In today's call, management will make certain forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these risks and uncertainties is included in the earnings release, the slide presentation and the company's SEC filings. Entergy does not assume any obligation to update these forward-looking statements. Management will also discuss non-GAAP financial information. Reconciliations to the applicable GAAP measures are included in today's press release and slide presentation, both of which can be found in the Investor Relations section of our website. And now I will turn the call over to Leo.

Thank you, David and good morning, everyone. Our first quarter results reflect a good start to another important year for Entergy, as we build on the momentum of last year's achievements that have made us a stronger company. We continue to make significant progress to transform our generation portfolio, reduce the risk in our merchant power business and invest in our core Utility business. In fact, this quarter, we accomplished everything in our plan to achieve our objectives. The Indian Point settlement that we announced in January is being implemented on the agreed-upon schedule. We completed the sale of FitzPatrick to Exelon Generation. We filed for regulatory approval to transfer Vermont Yankee. We received the final order in our transmission cost recovery factored filing in Texas. We filed our annual FRP with forward-looking features in Mississippi. We finalized renewable RFP selections in Arkansas and Louisiana. And today, we're reporting first quarter operational earnings per share of $0.99. These results are in line with our expectations for the quarter and we're on track to achieve our full year guidance. As a validation of the disciplined execution of our strategy to reposition our company for steady predictable growth in earnings and dividends, Moody's, following on the actions taken by S&P last year, has recently upgraded our issuer rating to Baa2 from Baa3. Turning to Slide 3. This quarter we reached milestones that further reduce the risk in our merchant power business. The sale of FitzPatrick to Exelon Generation marks the culmination of months of preparation by employees from both companies to ensure a seamless transfer of the plant and its approximately 600 employees. And more importantly, FitzPatrick will continue to generate carbon-free electricity for more than 800,000 homes and businesses in its region. The FitzPatrick transaction is another important achievement in our plan to orderly wind down of EWC. We'll manage our organization each step of the way so that the level of overhead that remains after we enter merchant nuclear operations in 2021 encompasses only what is reasonable and necessary to operate our business going forward. At Indian Point, we're working toward license renewal with the NRC and we're meeting all critical milestones outlined in the terms of our settlement with New York. Specifically, the New York State Department of Environmental Conservation has issued a final water quality certificate and final water discharge permit. New York State and Riverkeeper have withdrawn their remaining contentions before the Atomic Safety and Licensing Board and the board has terminated the proceeding. Pursuant to the Coastal Zone Management Act, the New York Department of State has issued its concurrence with our Consistency Certification filing and all pending court litigation related to Indian Point license renewable -- renewal has been dismissed. Let me repeat that. All pending court litigation related to Indian Point license renewal has been dismissed and we expect the license renewal to be issued in 2018. At Vermont Yankee, we filed with the NRC this quarter and with the Vermont Public Service Board last December for approval to transfer the plant, its decommissioning trust and its decommissioning obligation to NorthStar. We've requested the NRC's approval by the end of this year and the Public Service Board's in the first quarter of next year. Finally, at Palisades, the Michigan Public Service Commission has scheduled hearings for June 13 through 16 on Consumer Energy's petition for approval of the early termination of the PPA. The commission is targeting its decision by August 31. As a reminder, Palisades and Pilgrim have begun their final refueling and maintenance outages. In Utility, Parent & Other, we continue to make strides towards delivering on our earnings outlook for 2017 and beyond. After receiving approval from the Louisiana Public Service Commission in November, we broke ground on construction of the St. Charles CCGT project which we expect to come online in 2019 as scheduled. We also have applications pending for construction of the Lake Charles CCGT in Louisiana and the Montgomery County Power Station in Texas. Procedural schedules have been set and we expect decisions from regulators in the third and fourth quarters of this year, respectively. In New Orleans, we requested a temporary suspension of the procedural schedule for approval of the New Orleans Power Station. We requested the suspension to accommodate consideration by all the parties of our latest load forecast and the implications, if any, it would have on the project. Last week, we filed a status report with the New Orleans City Council informing the parties that by late June or early July, we expect to make a supplemental and alternative filing that will include a peaking resource with a lower capacity. The filing will also include testimony setting forth a firm commitment for Entergy New Orleans to pursue construction of up to 100 megawatts of renewable resources to serve New Orleans. We plan to continue pursuing certification for the original project, given its many benefits, but will present a smaller resource for alternative consideration by the City Council. Today, I am pleased to announce that Entergy Louisiana recently signed a purchase and sale agreement with Calpine Corporation for the acquisition of a peaking plant. Calpine will construct the plant which will consist of 2 natural gas-fired combustion turbine units with a total nominal capacity of approximately 360 megawatts. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and is expected to be completed in 2021. This agreement is another step in our broader portfolio transformation efforts to replace aging units with cleaner and more efficient generation for the benefit of our customers. We also are making progress towards the deployment of our advanced meters in our service territory. Our advanced metering infrastructure project and associated regulatory approval remain on schedule. Working with vendors, we're in the early stages of implementing the IT infrastructure needed to support meter deployment and developing the logistical plan for that deployment. Regulatory filings were made in 2016 in 4 jurisdictions. Procedural schedules are now set and hearings are scheduled for the third quarter of this year. In Texas, legislation was introduced in the current session to clarify the applicability of existing advanced meter regulation to Entergy Texas. We expect to file our deployment plan with the PUCT by the fourth quarter. Following regulatory decisions and initial implementation of the communications network starting in 2018, we anticipate initiating meter deployment in 2019. Finally, Mississippi welcomed the news of Grand Gulf's 20-year license renewal with numerous local and state officials recognizing Grand Gulf's strong community support and the plant's positive impact to the state and local economy. In March, celebratory events were held which Governor Bryant presented to support a proclamation declaring March 6, 2017, as Grand Gulf's Day. On the regulatory front, with progressive constructs in most of our jurisdictions, we're carrying out our rhythm of annual formula rate plan filings and other riders. EMI continues to utilize its formula rate plan with forward-looking features and made its annual filing on March 15. The filing reflects no changes in rates with an earned ROE of 9.72% within the allowed range. The final order on that filing is expected before the end of the second quarter. In March, the Texas Commission approved a $19 million annual increase to ETI's transmission cost recovery factor. The settlement reflects $286 million in incremental transmission investment since ETI's last rate case proceeding. Use of this rider, along with the distribution cost recovery factor, provides greater financial flexibility to support the needs of customers in Texas. Our core values resonate in the ways we support our communities. The success of our business is dependent on making sure that the communities we serve are thriving. We remain committed to the economic development of our region through our $5 million, 5-year workforce development initiative. In partnership with the Texas Workforce Commission in March, we announced $600,000 in grants to support workforce readiness in Southeast Texas. The grants will support programs at community college and high schools to equip individuals to step into high-demand, good-paying jobs. We also renewed our partnership with Jobs for America's Graduates, with a grant that will help at-risk students in Arkansas, Louisiana and Mississippi, stay in school and graduate on time. All of these initiatives are focused on creating a competitive advantage for our communities in helping them attract new industry to the area. We're pleased to have been recognized through several awards for our corporate stewardship and community development. For example, in recognition of our employees' emergency preparedness and response after major events, we received the Edison Electric Institute's Emergency Recovery Award for Outstanding Power Restoration Efforts on behalf of our customers and the Emergency Assistance Award for helping other utility companies recover from Hurricane Matthew. This marks the 19th consecutive year EEI has awarded Entergy a National Storm Restoration Award. Recently, we were also included in Corporate Responsibility Magazine's annual list of the 100 Best Corporate Citizens. This is the eighth time we've been named to this list which recognizes companies taking responsible actions in employee relations, philanthropy and community support, environment and climate change which is a good segue into the administration's recent executive order around promoting energy independence which includes a review of carbon regulation. In light of the order, I will highlight Entergy's position as one of the cleanest generating fleets in the United States. The principal objective of our strategy is to remain an environmentally sustainable fleet for the communities we serve and to continue to prepare that company for operations under any type of carbon emission costs that may accrue in the future. According to the 2016 Benchmarking Air Emissions Report authored by MG Bradley and Associates, Entergy produces fewer CO2 emissions per megawatt hour than 78 of the top 100 power producers. Our emissions rates for 2015 and 2016 across our entire fleet were 540 and 590 pounds per megawatt hour, respectively. This is well below the 1,000 pounds per megawatt hour standard issued by the Environmental Protection Agency in previous administration for a new highly efficient combined cycle natural gas unit. Thus, we consider our environmental strategy to be aligned both with global ambitions for transition to a low carbon economy and with our commitment to provide reliable low-cost electricity to our customers. Preparation for this transition began when we -- we're the first U.S. utility to commit voluntarily to stabilizing CO2 emissions in 2001. 10 years later, our commitment went beyond merely stabilizing CO2 emissions. In 2011, our Environment 2020 Commitment included a voluntary pledge that through the year 2020, we would maintain our carbon dioxide emissions at 20% below year 2011. I'm pleased to report that we're meeting our commitments. And in 2016, our CO2 emissions were approximately 20% below our Year 2000 emissions. Due to the challenging economics of relying on renewable resources in our geographic footprint, we're meeting our goals through a combination of methods. For example, we're replacing older, less efficient legacy units with cleaner, more efficient resources. Highly efficient combined cycle power stations, such as St. Charles, Lake Charles, Montgomery County, will produce up to 40% fewer carbon emissions and improve our average fleet efficiency by roughly 800 BTUs per kilowatt hour. Nuclear generation is also an important source of clean, reliable baseload power. Prudently investing to preserve these valuable resources for our stakeholders is an important part of our strategy. Our planned investments in new technologies to modernize our grids, such as advanced meters, will further improve efficiency and reliability. On top of that, we're actively working to deploy and incorporate cost-effective opportunities to expand our user renewables, including distributed energy resources. These will allow us to improve supply reliability and control costs for our customers and to further reduce greenhouse gas emissions as the economics, performance and reliability of these sources -- resources continue to improve. We're committed to working with our regulators, customers and other stakeholders to consider all proven technologies. We provide additional information about these efforts in our standard reporting, including in this year's integrated report which is available on our website. While it is too early to comment on the specific impacts of the recent executive order, we remain committed to developing an electric generating and delivery system that is well-positioned for operations in a carbon constrained economy, whatever that may look like. I am pleased with all that we have achieved to date in 2017 and I see great things for Entergy this year and beyond. With critical decisions behind us, we now have good clarity on the plan we need to execute to achieve our results for the next 5 years. We now know the timing and the sequencing of the wind down of our merchant operations. We have time to manage the overhead costs associated with the exit from that business and we have a firm goal to minimize overall cash flow impacts. At the utility, we've identified the projects that we need to support our goals in that business. And we have the regulatory constructs and relationships in place to facilitate the growth of our core business through these infrastructure investments for the benefit of our customers. And while we recognize there is still much to do, our accomplishments so far are a confirmation that we have the right strategy, leadership and workforce to deliver on our operational plan and financial outlooks. Now before I close, I'd like to recognize the very valued and significant contributions of Theo Bunting, who is on his last earnings call with us before he officially retires. He has been an incredible leader, mentor and colleague at Entergy for nearly 34 years. His deep knowledge and experience in both the industry and the business have been key to our success today. Personally, I've worked with Theo almost everyday since I came to Entergy 18 years ago. While it goes without saying that his knowledge and counsel have been invaluable, I cannot imagine where I or any of the rest of us would be without his support and friendship. My appreciation for all he has done for me and for Entergy is only matched by my best wishes for his health and happiness as he and Tony enter the next chapter of their lives. And now I'll turn the call over to Drew.

Thank you, Leo. Good morning, everyone. As Leo said, we continue to execute on our strategy and we're on track to achieve our 2017 guidance. Let's get straight to the first quarter numbers starting with Slide 4. On the left, Entergy's as-reported earnings of $0.46 included special items related to decisions to sell or close EWC's nuclear plants, including the sale of FitzPatrick. These special items reduced earnings by $0.53. On an operational view, our consolidated earnings were $0.99 per share. This compares to $1.35 a year ago. Utility, Parent & Other results are summarized on Slide 5. Operational earnings were $0.62 and adjusted earnings were $0.83. Weather is estimated to have reduced operational earnings by $0.16. Adjusted earnings were $0.12 lower than the first quarter 2016. This result is in line with our expectations. Although residential and commercial sales were below our plan, our new -- our nonfuel O&M was also lower. Net revenue was higher from new rates to recover productive investments which benefit customers. Over the past 12 months, we've had a number of rate actions across utility, operating companies, from rate cases, FRPs and riders, including for last year's Union acquisition. One that became effective this year was Entergy Arkansas 2017 test year FRP rate change. Despite a steady growth in customer count, we experienced a decline in combined residential and commercial sales of 3.1% on a weather-adjusted basis. One factor was that last year was a leap year which means we had an extra billing day in 2016 and that accounts for about 1/3 of the change. In addition, our service territory experienced the mildest first quarter in over 120 years of recorded temperature history. During periods of abnormal weather conditions, such as this, it can be difficult to capture the effect of weather on residential and commercial sales. Looking on a longer term basis, the 12 months ending residential and commercial sales declined about 1%. While we're closely monitoring customer usage going forward, it is worth noting that the projects that we have identified in our capital plan are driven by customer reliability and aging infrastructure replacement needs and not by occasionally volatile quarterly sales. In the Industrial segment, sales growth was positive as continued growth from new and expansion customers was somewhat offset by lower sales to existing customers. For new and expansion customers, growth came from the primary metals, industrial gases and chloro-alkali segments. The decline in sales to existing customers was driven by refinery outages. This is consistent with our expectations as I noted on our last quarterly call. The refiners are starting to come out of their outages now. Crack spreads are currently high and we expect these customers to run strong in the second half of this year. Nonfuel O&M increased $0.20, quarter-over quarter. There were several drivers, including a beneficial cost deferral recorded last year in connection with the EAI rate case order which reduced 2016 O&M by about $0.06. Nonnuclear generation expenses were higher, primarily due to a full quarter of Union costs. Nuclear operations spending also increased as expected, while spending in support of ANO inspection activities was lower. Turning to EWC's first quarter results, summarized on Slide 6, operational earnings were $0.37 from the current quarter, $0.14 lower than the prior year. FitzPatrick accounted for $0.06 of the $0.14 decline. Excluding FitzPatrick, the other key driver was net revenue, due primarily to lower prices. The price variances partially offset by lower fuel expense attributable to impairments. As you know, Indian Point Unit 3 is in the midst of its refueling and maintenance outage which includes a baffle bolt inspection. We will replace 270 bolts. That work is underway and we expect the plant to be back online by the end of May. Slide 7 shows operating cash flow this quarter of $529 million, essentially flat to first quarter of 2016. Reduced cash flow from the timing of recovery for fuel and purchased power at the utility and lower operational net revenue at EWC were largely offset by project cash flow from income taxes and reduced spending of Vermont Yankee decommissioning. Today, we're reaffirming our 2017 earnings guidance ranges which are summarized on Slide 8. We continue to expect Utility, Parent & Other adjusted EPS to come in around the midpoint of our range. Even though first quarter weather-adjusted residential commercial sales were lower than planned, nonfuel O&M is tracking favorable to our guidance assumption due to effective cost management. For our consolidated guidance, the negative weather to date has caused us to move below midpoint expectations, but it's still early in the year and weather could turn around over the remainder of the year. There are other risks and opportunities that could apply to both Utility, Parent & Other as well as Entergy overall, such as keeping more of the O&M benefits in the first quarter and capturing additional nuclear decommissioning trust benefits as we rebalance the portfolio due to the equity market rally. Separately which we mentioned on our last quarterly call, it's a potential for an income tax item at EWC, possibly as early as the second quarter of this year. If that does materialize at the magnitude similar to or slightly larger than last year, we will shift our consolidated operational guidance accordingly, but would not change our adjusted UPO guidance. Moving to the longer term view. Slide 9 shows our adjusted UP&O outlook which is unchanged. We're also updating our EWC EBITDA outlook on Slide 10. We still see the free cash flow out of that business as relatively neutral through 2021, excluding any potential contributions to decommissioning trust. And our goal to get to completely cash neutral remains achievable. Although it is a separate analysis, we submitted the most recent NRC financial assurance filings on March 31 which indicated that no NDTs had a deficit. Summaries of these filings are included in the appendix of our webcast presentation. Our cash and credit metrics are shown on Slide 11. As you can see, parent debt to total debt is higher than our targeted range. We expect this to turn around in the year near the top of our target range or about 20%. Looking further out, we still expect the parent debt ratio decline to the 22% to 23% range in 2019. This is consistent with our estimates last fall. We continue to look for opportunities to become more efficient with our capital and O&M spending. In January, Moody's upgraded Entergy Mississippi to A2 to recognize improvements in the company's formula rate plan and expectations for improved cash flow metrics. As Leo mentioned, earlier this month, Moody's upgraded Entergy Corporation's issuer rating to be Baa2, matching our upgrade to BBB+ for Standard & Poor's last summer. Both actions are the result of our efforts to improve our business risk profile by focusing on our core Utility business and winding down our merchant business. As a reminder, we remain on positive outlook from Standard & Poor's from earlier this year. Our strategy to achieve the goals laid out for each of our 4 stakeholders remains the same as we focus on steady predicable earnings and dividend growth from our core Utility business. Meanwhile, we're continuing to manage risks throughout the company, including the orderly wind down of our merchant business. And now the Entergy team is available to answer questions.

[Operator Instructions]. Our first question comes from Chris Turnure with JPMorgan.

Drew, in your comments, you mentioned that there's the leap day in the first quarter as well as the extreme weather which impact normalization calculations on year-end. But at this time, can you say that your full year 2017 normalized guidance is still appropriate? And secondarily, when you look across the different new projects that you're working on in terms of utility generation, is there any other pushback in terms of the need for those plants, like you've seen so far in New Orleans?

All right, this is Drew. I'll take the first one and then I'll hand over the second part of that question to Rod. So at this point, obviously, if nothing changes, we haven't updated our expectations for second, third and fourth quarter to be higher than what we anticipated at the beginning of the year. So all else being equal, we would be probably slightly below where we initially anticipated the year. But it's still early in the year. So I think, it's still premature for us to make any changes as to what our expectations would be for the full year. And I'll turn the rest over to Rod.

As it relates to the rest of the supply plan, keep in mind that the rationale behind the supply plan was not primarily driven by point of view on load in New Orleans, for instance. Out of a sense of transparency, we actually brought the change in our 30-year load forecast to the attention of the stakeholders, again just to be transparent, but the rationale behind the investment is still very much intact. We've not seen across the jurisdictions any response or opposition to our plants, based solely on the load or sales forecast. Keep in mind that the load is different from the sales forecast. And I think that's a distinction we need to keep in mind as well as we look at the rest of our generation portfolio. But the answer to your question is, we're still -- we have not seen any additional pushback throughout the rest of the jurisdictions.

And Chris, this is Leo. I'll just jump in as well from a strategy standpoint. As Rod mentioned, we've got an aging infrastructure in terms of our fleet and locational issues as it relates to what we need to build from a generation standpoint. New Orleans, for example, there is no generation inside the city of New Orleans and part of the need for that, in addition to meeting peak demand, is to be able to supply the system, should we have some sort of storms that comes through and knocks out transmission infrastructure which has happened in the past. So that's a locational issue, same with some of the other plants. We've got the need because of the fact that we went into all of these transformation short to begin with. But add to that, the first quarter weather just in sales, is just an anomaly. As you know, weather normalization and these things are really mathematical algorithms that work well in most cases. But I think, Drew mentioned that this was the most mild winter in terms of degree days in the history of recording degree days, 120 years or something like that. So that's really not cause for any kind of an alarm in terms of what's going on long term.

And then switching gears to EWC. I think on the last call you commented on cash flow being pretty negative this year because of some outages and then slowly getting better into the early part of next decade when Indian Point shuts down. Can you just give us your latest thoughts there? And in particular, I'm interested if there's been any advancements with your potential offsetting cost cuts to some of that cash outflow?

This is Drew. In terms of the overall forecast at this point, Chris, I think, it's essentially the same as it was before. We still have all of the outages this year. And so that's pretty expensive, but we're anticipating pretty strong cash flow generation through the next periods primarily because we won't be paying for another refueling outage at each of the plants, well I should say, Pilgrim and Palisades. We will be doing one more at Indian Point for each of those units and then those 2 units would have better cash flow generation as they ramp down in -- into 2021. So from an overall cash flow perspective, at this point, it's still about the same. But in regards to I guess, your second question, are we making any progress? I would say, absolutely. Internally, we've been scrubbing the numbers down hard. And so we would hope to show you some specific progress over the balance of the year to demonstrate that we're closing that gap and meeting that objective that Leo talked about in his script of getting to cash flow neutral. Cash flow -- let me just clarify, cash flow neutral overall. I think from an operational cash flow perspective, we're already at neutral. It's just the NDTs that we're working on. And in addition to the operational piece, we're also working on transactions there as well.

Okay. So that cash flow neutral number is all in, including the decommissioning trusts over the 5 or 6-year period?

Yes. Our goal is 0, including the decommissioning trust through 2021. Right now, our forecast has essentially 0, operationally not including the trust, over that same time frame.

Our next question comes from Jonathan Arnold with Deutsche Bank.

So I was going to ask about sales, but I think that got covered. Maybe I could ask on -- can we get an update on the Nuclear Sustainability Plan, both progress on metrics and also just maybe a reminder of where you are on moving towards getting some of this relevant to rates?

Well, I'll let Chris give you the first part and then Rod will take the second.

In terms of the Nuclear Sustainability Plan, we remain on track working and continuing to make improvements in the performance of our fleet and improve our regulatory margins. So I would characterize this straightforward as on track.

Jonathan, it's Rod. In terms of the timing, we expect to make a filing on this coming Friday, day after tomorrow, with the APSC seeking -- formally seeking to reconcile the nuclear cost adjudication with our formula rate plan filing in July, so we can handle the nuclear cost conversation in conjunction with the FRP. And nothing has changed in terms of our point of view on the recoverability of those costs. We think the facts support the finding that the costs we're seeking recovery are consistent with what you've heard over the last several quarters with Chris. And Leo made a reference to it, the costs associated with people with improving the equipment and the plant to preserve those assets and the benefits for customers and so we feel comfortable that the evidence will support the finding of continued recovery, not just of the costs that are in question for purposes of the 2016 or 2017 forward test year, but the actual 2018 forward-looking test year that we'll file in July. So no change there and again, a consistent message around what we're seeking recovery off. I will note that the cost associated with the FRP filing and what we expect to file on overall nuclear costs in July do not include costs associated with regulatory oversight or state or things of that nature. So it's pretty much a clean nuclear cost, cost to run and operate the plant through beyond the expected life of those assets.

And the outstanding issue from the '17 Arkansas FRP is still sort of pending as scheduled, is that correct?

That's what I was referring to when I said we'll make a filing on Friday to join or conjoin those issues from a timing standpoint at Arkansas. So the outstanding issue that you made reference to, that's what -- that's the subject of the filing we'll make on Friday. We will formally ask the APSC, let's handle it all in conjunction with the planned FRP filing in July.

Okay, so take it out of the old one and put it into the new one effectively.

I think, that's fair.

Our next question comes from Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith: So quick first question on the Utility side. Obviously, AMI is the big program, you guys repping up here for. Can you discuss a little bit of the precedents in Louisiana and Arkansas with respect to perhaps peers and just some of the nuance you might expect as you move through the process there? And then I suppose specifically, on Texas, obviously, it seems that you guys are looking to file later this year, any reason for kind of the shifted schedule? And what potential size of the program that might be? And the further detail would be just is that already encompassed within your CapEx program?

I want to make sure that I'm ideal with the question in order and you may have to reask the last part. On AMI, we have filed for -- we made the AMI filings in every jurisdiction except for Texas and we're trying to address some legislative prerequisite, so we can do that, do Texas as well. And we expect resolution of the formal AMI filings by year-end. In terms of precedent with other jurisdictions, I think, the timing of both the conditions, precedent to deployment, that is the deployment of workforce management system to asset management systems and the actual timeline of our '19 deployment comes from experiences we've gathered, lessons learned from other jurisdictions, who have gone down this path before. And the message that's consistent across each of our filings and jurisdictions is that our objective is to have the benefits to our customers of AMI deployment be available to them, in addition to our benefits at the time we put those assets into service. And so that affects our plan regarding the timing of deployment. And again, that message is consistent across the rest of the jurisdictions. The third question, I didn't -- I need you to repeat, so I'll make sure I'm answering it. Julien Dumoulin-Smith: The last one's is an easy one. With respect to Texas, obviously, you haven't formally filed, but have you baked into your expectations and CapEx something in there for when you do likely eventually file?

Yes. Our plan includes -- the capital plan includes the Texas AMI filing as well. The threshold issue for us was making sure we had legislative and regulatory mechanisms in approval set up. And so we had to take care of that with the legislative session. We've had some support on the Senate side of the Texas Legislature. We're waiting word on the House legislation that would authorize us and PUCT to go down that path. But the answer to your question is yes.

And let me just give one point of clarity on that. So our capital plan, Julien, is true -- through '19 mostly includes corporate-wide efforts, communications, IT platforms, that kind of thing that would support the scaling of Texas when it comes in. And beyond our capital plan would be maybe more Texas-specific meter deployment and stuff like that, that would be -- still maybe starting in '19, but certainly going into '20 and '21. Julien Dumoulin-Smith: Just a quick clarification on the prior. You were talking about a cash flow as a sort of breakeven target for the business overall or the EWC side. Can you just elaborate a little bit on what you expect the ongoing impact to operational earnings are? Can you remind us how you're thinking about that through the period and specifically, in the later years, how we should think about operational versus nonoperational items on earnings?

You're talking about '17 through '21? Julien Dumoulin-Smith: Yes or specifically, kind of like an ongoing. I understand that obviously...

On an ongoing -- yes, on an ongoing basis, once we get the plants to shut down status and removed in the decommissioning activities or the plants have been taken off our balance sheet, like the VY type transaction, we would expect to be essentially flat at EWC. A part of that is -- next year, there is an accounting rule change that we anticipate around how you account for new decommissioning trust earnings. And that would give us an opportunity to not just realize gains that -- we've had realized gains show up on our income statement, but actually mark-to-market the growth and the trust over time on the equity side. And the effect is going -- we typically see about 6 1/4% of returns in the decommissioning trust, but you only recognize the income statement about 3%. And when you kind of closed that gap, it starts to close the gap to the ARO liability, the asset retirement obligation liability that's out there and the amortization of that. So once you get out to 2022, it's about flat. Julien Dumoulin-Smith: Excellent, so to be clear, it's effectively 0 for the cumulative cash flow and flat on an earnings basis?

Beyond 2022 -- starting 2022 and beyond, yes.

Our next question comes from Michael Lapides with Goldman Sachs.

I hate to do this, I kind of want to come back to the demand question. Can you remind me for residential and small commercial demand, what is the end year 2017 guidance and your multi-year guidance in terms of the assumption for just kind of weather normal growth there?

I'm sorry, Michael, could you repeat that question?

Sure, what's in your 2017 guidance and your multi-year guidance for weather normalized growth for residential and small commercial?

For residential and small commercial, it's about almost 0. In fact, I think, if you -- we only put out to 2017, but if you went out to 2020, 2021, it's actually slightly negative. As you see, automated meters coming online and customers realize the benefits associated to that. One of the benefits is lower expected demand. And so we actually see negative growth over sort of a 5-year period.

And when we think about industrial demand growth because your forecast is pretty robust, 3%. There's a lot going on, obviously, in East Texas and in Louisiana with the petchem industries. But just curious how sensitive your supply needs are that kind of like every percent change in that, meaning if it turns out to be, I don't know, closer to what you've seen more recently, closer to 2% or even a little less than that, does that significantly influence how much new capacity you need to build or buy?

Michael, this is Rod. I think I want to reiterate here that the driver behind our capacity needs is not so much driven by assumptions around low growth, although its precedented and that low growth certainly helps offset the impact of those capital additions on customer rates. The driver -- the primary driver locationally might be around the specific needs of industrial siting in the region, but it's really around modernizing the grid and fleet and responding to retirements of aging assets. And that represents the lion share of the generation in transmission investment in the region driven less so by assumptions on overall industrial load.

This is Drew, let me just add. We do still see positive industrial growth out through our forecast period and beyond. And a lot of that industrial growth is based upon projects that we see coming up and under construction right now over the next few years. And we've actually seen a bit of a pickup recently here on some of the petrochem, chemical industries and other things getting to their financial decision points on whether they're going to go forward with the projects. So we're still seeing good positive demand growth in the industrial space and that is offsetting the residential and commercial fees that we're talking about earlier. So even though that part looks like it's kind of flat over the next few years, we do still see overall expected growth in our business.

Got it. And finally, on Indian Point. When does the state need to tell you guys whether they could potentially need Indian Point past the 2020, '21 retirement date? Meaning, I know the original agreement left the room for the plant to operate through about '24 -- 2024, 2025. But a lot of that is kind of based on the ISOs and the state's potential views on whether it needs it or not. When do they need to tell you guys? When do you need to know?

Michael, this is Drew. We have to make a filing with New York, a formal filing with the ISO. And that will allow them to make the assessment about Indian Point and when it's going away and how they would deal with that. We were working with the ISO. We expect to make that filing later this year. And once we do make that filing, I think, there's a statutory 90-day timeline associated with the analysis that they would do and come up with a formal recommendation. But certainly, they are aware of it and -- but that process will get kicked off later this year.

Okay. And if the ISO comes back and says, "hey, actually for local reliability purposes, we need one or both of the units beyond 2020, 2021," what happens?

Okay. Well, first of all, if they said that there was a challenge that they needed to solve. If there was some operational system issue that they would need to solve, they would need to go through a process that would identify the best way for them to solve it and it wouldn't necessarily mean keeping Indian Point online. It could mean we need to upgrade a transmission line or we need to get a peaker in at some place or something like that. So depending on the nature of the issue they identify, there could be a lot of potential solutions and their objective will be to go find the most economic one that solves their problem. If for some reason, nothing else matters until you get down to Indian Point, well then we would need to work with the State to figure out how we would move towards something different besides 2020 and 2021. So it's not unilateral. If they can't tell us to do it, they have to work with us on it, but certainly we don't want to create a reliability problem in the State of New York, either. So we would work with them on that. But it seems unlikely to us that it would get to the point where they would need Indian Point to stay online at this point. It seems likely to us that they're going to find a different solution that will be more economic than keeping the plant online.

The next question comes from Shar Pourreza with Guggenheim.

When we've discussed in the past, I think we've talked about sort of the Arkansas prudency review, a separate procedural schedule, but now it's sort of looks like it's going to be rolled into a larger one. Is that -- any signal on why that wasn't separated? Is there a function of the fact that the original prudency review was small and it made sense to roll it into a joint proceeding? Just a little bit of clarity there would help.

Sure, it's Rod. I think, think about it as a nature of the cost. We've maintained all along that one, we weren't seeking separate recovery mechanism for recovery of the nuclear costs because those costs were consistent with our objective to maintain those assets and the benefits that accrue to customers. And so as we think about what's going -- what was going to happen in July, anyway, with the formula rate plan filing and our forward-looking test year, it made sense for us to -- from our vantage point, given that the APSC had not set a separate docket procedural schedule to go ahead and address it all in conjunction with the FRP, so neither we nor the APSC had to deal with essentially ongoing normalized nuclear spend in 2 separate dockets with nuclear and the rest of ANO. And so it simply made sense to us. And because of the ex parte rules, we weren't allowed to really have conversations with the commission. And so on Friday, we'll look to affirm and clarify their point of view that it makes sense to handle them both at the same time.

And then just on sort of the pending -- sorry, if I missed this, but on the decommissioning expense, the activities, the sale potential for Pilgrim and Palisades. Is there sort of any update there? And eventually could we see the same process with Indian Point?

It's Drew, Shar. Yes. So we're continuing to make progress on this. These are pretty complicated transactions. We're working through the Vermont Yankee one right now at the Public Service Board in Vermont. And it is the first of a kind process and it's very complicated and they are taking their time. They are very active in engaging process, so we're answering all their questions and expect to get through that sometime in early '18. That's sort of setting the table for Pilgrim and Palisades and we're certainly learning from Vermont Yankee as we go along. But we're making progress to introduce 2 plants instead of 1, hopefully by the end of the year or around there, get to a point where we're ready to bring a transaction forward and that satisfies all the stakeholders. And then in Indian Point, I was going to add that we're definitely planning on looking at something similar for Indian Point once we get down the road a little further.

And then just your cash flow picture, assuming you exit all of the decommissioning activities, are you still neutral? Or is there an opportunity to be slightly positive?

There could be an opportunity to be slightly positive. The objective of getting to cash flow neutral includes operational elements, while we're still operating and includes some of these transactions. So if we were -- if we hit a home run, we could certainly get to positive over the -- through 2021, over the 4-plus year period.

And Theo, congrats on the retirement, even though I think you're too young to retire, congrats.

Thank you.

He's heard that a couple of times.

Our next question comes from Praful Mehta from Citigroup.

Just a quick question going back to the decommissioning part. It sounds like in the base case plan, there is some funding required for decommissioning which you're trying to work on with [indiscernible] on cost savings. Just firstly, I wanted to figure out what's driving that? And secondly, what's the variability around it? And site-specific review is going to potentially increase that or decrease that? And Drew, you mentioned just hitting the home run. What are the variables that could allow you to hit that home run, I guess?

Well, I mentioned in my prepared remarks that we have our quarterly or I guess annual testing on the -- for the NRC minimums for the decommissioning trusts. And we passed all of those that we submitted in March, without having to post any additional information. It is when we get to the actual shutdown analysis which is the very detailed decommissioning estimates and they call it as the post-shutdown decommissioning activities report. We had to file that with the NRC within a certain amount of time after we actually shutdown the plant. When we do that, that's actually a little different than the NRC minimums. The NRC minimums are somewhat formulaic. So with all the extra detail and the studies that we've done, we expect that there could be the potential to put in a little bit more money at a couple of plants and we're working through that right now. We have our own estimates. We're working through the estimates that our potential counterparties may have and the potential sale of those trust to them. And so that's a commercial negotiation and is ongoing, but that's where the potential benefit could be. But there is also still significant potential benefits in the operating piece before we get to actual shutdown of the plants.

And then secondly, on the potential tax rate decrease. And if there is, let's say, a tax rate decrease, 15% or 20%, whatever it gets to, assuming no other tax reform, just the tax rate decrease, what does that mean in terms of -- is there any change in like a capital allocation plan or a financing plan for Entergy? Or is the current business plan really business as usual? And any benefits or impacts you've already talked about kind of stay in place?

You're talking about tax reform administration from -- at the federal level?

Yes. That's right.

Okay. Yes. In the near term, we wouldn't anticipate any significant changes. We're in an NOL position and so whether or not we're paying taxes -- we're not going to be paying taxes a whole lot in the near term under the current tax regime and we wouldn't anticipate paying taxes a whole lot in -- under a tax reform scenario. So our capital plan should be about the same either way. We will, obviously, work closely with our retail regulators to get whatever affects are into rates. And then at the parent level, since we also have the NOL there, the fact -- not the fact, the possibility, I should say, that we lose an interest deduction or there's a lower tax rate, both of which would affect the parent negatively because of the losses there. But from an earnings perspective, they wouldn't necessarily affect it from a cash flow perspective. And so we wouldn't anticipate changing our capital structure as a result of tax reform anytime near term or for the -- I should say, for the foreseeable future.

So the parent debt to consolidated debt targets would remain about the same, in respect to the tax reform?

That's what we're anticipating.

Our last question comes from Charles Fishman with MorningStar.

Drew, let me ask that question a little different way. You put up a slide last quarter on your preliminary thoughts on tax reform. Is there anything you've heard since then that would make you change anything on that slide?

No, Charles. Nothing yet. As you know, there hasn't been anything really definitive that has come out of D.C. as of yet. Perhaps today, we'll get some information from the administration about where they intend to go, but we had certainly been participating in EEI activities up on the Hill. Leo's been up there, I've been up there, our tax team has been up there, our regulatory folks had been up there to try and discuss the impact on utility customers primarily and what they mean and the impact on our ability to rate capital on the cost of capital, primarily. So we spent a lot of time up there, but we haven't garnered any additional intelligence because there hasn't been anything to discuss, really, as of yet. So we're still discussing the same kind of frameworks that we had a quarter ago.

The only thing that I'd like to add and I know we're running up against the time here, but from the standpoint of where we sit, all the questions that you all had are really, really good and helpful for us to make sure we know which to focus on. But I just want to kind of end where I started and that is from a strategic perspective, everything that we're doing is right on track with what we've laid out over the last couple of years. From an operational perspective, across the entire business, everything is right on track in terms of what we've laid out over the last couple of years. And then from a financial perspective, everything that we're -- have achieved and the things that we see in our outlooks are right on track with what we've laid out over the course of the last years -- a couple of years. So from the standpoint of where we sit, right here today, we're still very excited about the opportunities in front of us. The capital plan we have is solid, the regulatory structures we have around it give us the flexibility to benefit our customers through those investments and most of what we're doing on the -- certainly, everything we're doing on the capital side and investment has been done elsewhere within and outside of our jurisdictions, both from a regulatory and operationally and a technological standpoint. So we feel really good about where we sit and everything's right on track.

Great. Thank you. And thanks to all for participating this morning. Before we close, we remind you to refer to our release and website for safe harbor and Regulation G compliance statements. Our annual report on Form 10-Q is due to the SEC on May 10 and provides more details and disclosures about our financial statements. And please note that events that occur prior to the date of our 10-Q filing that provide additional evidence of conditions that existed at the date of the balance sheet would be reflected in our financial statements in accordance with generally accepted accounting principles. And that concludes our call. Thank you.

Ladies and gentlemen, that concludes today's presentation. You may now disconnect and have a wonderful day.