Entergy Corp (ETR) — Q2 2017 Earnings Call Transcript

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 an effort to accommodate everyone who has questions, we request that each person ask no more than one question and one follow-up. In today's call, management will make certain forward-looking statements, and 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 our earnings release, our 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. We had another productive quarter executing on our strategy to deliver steady predictable growth in earnings at our core utility business, which supports our long-term dividend growth aspiration. 2017 is on pace to be another year with significant accomplishments on multiple fronts that continue to position us to deliver on our outlooks. Specifically, the Louisiana Commission approved the Lake Charles Power Station project. The Texas Commission approved the Montgomery County Power Station project, and Entergy Louisiana filed for approval of the Washington Parish Energy Center. The Mississippi and Louisiana commissions were the first of our jurisdictions to approve deployment of advanced metering infrastructure. The State of Texas passed legislation that clarifies the applicability of existing advanced meter regulation to Entergy Texas and we now have made our formal AMI filing. Entergy Arkansas and Entergy Louisiana filed their annual Formula Rate Plans. The Mississippi Commission approved Entergy Mississippi's 2017 test year FRP. And finally, Entergy Texas filed a settlement to increase its distribution cost recovery line. In many instances, these results are the product of the strong collaborative efforts between our teams and our regulators and their staffs for the benefit of our customers. And with these project decisions and approvals, more than 85% of our cumulative capital plan through 2019 is ready for execution from a regulatory approval standpoint. And more importantly, we continue to manage the effects of our investments and rate actions on our customers. In fact, in a recent report from S&P Global Market Intelligence based on data from the Energy Information Administration indicates that in 2016 Entergy provided power to its retail customers at the lowest average retail price in the United States. Today we are reporting that Utility, Parent & Other adjusted earnings per share contributed $1.12 to our consolidated results for the quarter. These results are in line with our financial plan and they keep us solidly within our full year adjusted EPS guidance range for our core Utility, Parent & Other business. At the same time, we are shifting our Entergy consolidated operational earnings guidance through the second income tax item at EWC which Drew will discuss further in his remarks. During the quarter, we continue to demonstrate significant progress to modernize the utility infrastructure and enhance its efficiency and reliability for the benefit of our customers. Starting with generation, in June we received final approval from the Louisiana Public Service Commission to move forward with the construction of the Lake Charles Power Station in Westlake, Louisiana. This approximately 990 megawatts CCGT is expected to be placed into service in 2020. In July, we received final approval from the Public Utility Commission of Texas to build the Montgomery County Power Station. This too will be approximately 990 megawatts CCGT, with the same technology as the Lake Charles Power Station. The plan is expected to be placed into service in 2021. These projects will contribute to our portfolio transformation efforts to replace older less efficient plants with new generation. These new units will use state-of-the-art emission control technology and will be highly efficient by capturing and using waste heat that is part of their generation. They are an important part of our strategy to meet our voluntary commitment to develop an electric system that is well-positioned to operate in a carbon-constrained economy. Beyond environmental benefits, these projects are also the result of our collaborative work with our stakeholders to advance economic development in our region. Combined, the Lake Charles and Montgomery County projects are expected to produce at least $3 billion in net benefits to our customers in Louisiana and Texas to lower production costs. They are also expected to provide thousands of jobs during construction and generate over $2 billion in economic activity for their local communities. In July, we also filed a supplemental and amending application for the New Orleans Power Station. The application renewed our request for approval of the originally proposed 226 megawatt combustion turbine and also presented an alternative proposal to construct a 128 megawatt unit composed of seven natural gas-fired reciprocating engines. Both projects offer significant benefits to our customers and provide modern, efficient, faster technology that will enhance reliability and operational flexibility. Either resource will aid in restoration efforts following major weather events, which is particularly critical for the city of New Orleans. In addition, either project could facilitate the adoption of renewables into Entergy's portfolio by providing a resource capable of cycling around the intermittency of renewables. Our application also reaffirms our commitment to pursue up to 100 megawatts of renewable resources. Finally, in May we filed for the approval and cost recovery of the Washington Parish Energy Center with the Louisiana Public Service Commission. This project will benefit customers by adding much-needed long-term peaking and reserve capacity at a cost below that of the comparable new facility. In addition, the project is expected to generate millions of dollars in economic development, tax revenue, and construction jobs for Bogalusa and the surrounding area. We also invested over $220 million this quarter in the transmission grid. These investments, which have now exceeded $425 million through the first half of the year, are necessary to improve the reliability of our system, reduce transmission congestion, and enable the delivery of additional cost-effective energy, maintaining compliance with NERC standards and supporting economic development in our region. We continue to work with MISO on future transmission projects. The 2017 MTEP planning process is on course, and the MISO board is evaluating nearly $1 billion plan over the next five years and will make its selection and give final approval to projects in December. In addition, in September we will be submitting MTEP 2018 projects for approval next year. Turning now to the distribution side of our business. As you know, we made our filings in our jurisdictions seeking approval for the deployment of advanced meters and the back office systems supporting those meters. We continue to get positive feedback from our stakeholders, and I'm pleased to announce that we've reached significant milestones. In Mississippi and Louisiana, the Public Service Commissions were the first jurisdictions to approve the implementation of AMI. In Texas, legislation was passed that clarifies the applicability of existing advanced meter regulation to utilities outside of ERCOT. This cleared the path for Entergy Texas to file its AMI deployment plan with the PUCT, which we did in July. Procedural schedules have been modified in New Orleans and Arkansas to allow additional time for settlement discussions among the parties before the next rounds of testimony are filed. And finally, we are moving ahead with the construction of our back office systems and testing the infrastructure ahead of a 2019 start for meter deployment. We are very pleased with these important developments, particularly in light of the benefits that advance meters will provide to our customers and the follow-on technologies and services that will provide new opportunities to reduce costs and give our customers greater control and options over their energy usage, in addition to a better customer experience. We will continue to provide updates on these efforts, which will serve as the foundation for an integrated energy network and represent a key milestone for the future of our company and our industry. On the regulatory front, we've carried out our rhythm of Formula Rate Plans and other filings across our jurisdictions. In Mississippi, the Public Service Commission approved AMI's 2017 FRP filing with an earned ROE of 9.79% within the allowed range with no change to base rates. In May, Entergy Louisiana filed its 2016 test year FRP. We earned an ROE of 9.84%, which was within the approved band indicating no change to base rates. As a reminder, this marks the last filing under the current three-year Formula Rate Plans, and we will be working with our commissioners and stakeholders to seek to renew the FRP mechanism with some adjustments. Entergy Arkansas filed its 2018 test year FRP in July. The filing indicated an earned ROE of 6.23% with a projected deficiency of approximately $130 million. However, rate adjustment is capped at 4% of total revenue or around $70 million. We expect a decision from the commission in the fourth quarter of this year. In April, we requested that the Commission review, in conjunction with this year's FRP filing, the costs from last year's filing that remain subject to refund. The commission approved our request, and the filing includes further information supporting the prudence of those costs. In addition, in Texas, the governor signed a bill that removes the distribution cost recovery factor 2019 termination provision, thereby formally recognizing the DCRF as a permanent rate-making construct available to Entergy Texas. In July, Entergy Texas filed a settlement agreement to increase its rider recovery by approximately $10 million. The DCRF, along with the transmission cost recovery factor, provides greater financial flexibility to support the needs of our customers in Texas. From an operational perspective, I would like to highlight that our nuclear organization completed seven refueling outages this year, which was a significant undertaking. In addition to the actual refueling, we invested over $230 million to complete multiple planned capital projects across the fleet. These were driven by the need to replace equipment that has reached the end of its useful life or to proactively replace equipment before it becomes an operational challenge. All of these projects are consistent with the types of projects performed at other nuclear fleets and support sustained operational excellence to improve the equipment reliability, efficiency and capacity factors—all to the benefit of our customers, as we work to keep these important resources online for the long term. For example, at River Bend, we are replacing the analog trimming control system with a modern digital control system. With analog spare parts no longer available, many of our peers have converted to digital controls or are currently working on similar conversion projects. This modification has already prevented an automatic shut down. We replaced heat exchangers at two units to correct marginal heat removal capabilities. We replaced turbine blading at two units to maintain optimum performance and made large motor replacements across the fleet. These are just a few examples of the many projects we are conducting at our plants on an ongoing basis; some are substantial, but others are smaller in scope, but all are important to support operational excellence. As reflected in our accomplishments over the quarter, our execution at the utility was once again on the mark. Each of the projects, each of the approvals, each of the decisions contributes to reduce the risk of our capital plan and strengthen our ability to deliver our near-term and long-term outlook. With critical decisions behind us, our strategy to execute a planned orderly exit of our Merchant business remains on track. Our employees’ dedication to the safe operations of our plants through this transition exemplifies the essence of our merchant team's determination to finish strong. Pilgrim successfully completed its final refueling outage, and at Palisades, the Commission is scheduled to make its decision on early termination of the existing PPA at the end of September. As we move toward a complete wind down of our merchant operations, we will continue to look for opportunities to test our nuclear assets post-shutdown for the purposes of decommissioning. However, those efforts do not materialize into firm transactions. We are prepared and able to successfully manage the process from shutdown to dormancy, also known as safe store, and then to eventual decommissioning decades from now. At Entergy, we play a vital role as a corporate citizen in every region where we operate, and our core values are reflected in our support of our communities. We work hard every day to earn the trust of our customers we serve. Nowhere are these values more apparent than when our employees go above and beyond to serve our customers during their most difficult times. So our system withstood Tropical Storm Cindy well. Our employees remained diligent, and we safely repaired damaged infrastructure and restored power for those affected. Storm restoration is just one of the many ways our engaged workforce powers life for all of Entergy’s stakeholders. We recently received recognition for our civic-minded approach to doing business and our commitment to diversity in the workplace and organizational health. For the second consecutive year, Entergy Corporation was named to the Civic 50, the Points of Light initiative honoring the 50 most community-minded companies in the nation. The Women's Business Enterprise National Council presented Entergy with America's top corporations for women's business enterprises award. Recipients of the award were celebrated for collectively spending more than $35 billion with companies owned by women. Entergy was recognized as one of the top 2017 workplaces in the New Orleans region in recognition of our commitment to organizational health. Furthermore, we remain dedicated to the economic development of our region through our $5 million five-year workforce development initiative. So far, we've awarded $2.5 million in grants to 25 grantees in Arkansas, Louisiana, Mississippi, and Texas. We will continue to work with state agencies and local communities to promote growth across our service areas. Our success is dependent on ensuring that the communities we serve and live in flourish. In conclusion, our results year-to-date keep us solidly within our full year adjusted EPS guidance range for our core Utility, Parent & Other business. 2017 has already been a year of significant accomplishments that position us to deliver on our outcomes. A large majority of our capital plan to 2019 is ready for execution from a regulatory approval standpoint and is supported by progressive regulatory mechanisms. We are making progress toward the improvement of our nuclear operations, and with AMI, we are taking an important foundational step toward investing in the integrated Entergy Network of the future. Technology investments beyond that represent the future of our company and our industry and will deliver benefits to our customers, fundamentally altering their energy consumption habits. In the second half of the year, we look forward to continued execution on our strategy, to invest in our core utility business for the benefit of customers and reduce risk, including the orderly wind down of our merchant power business. And we will continue to manage our business to preserve our competitive edge for the benefit of our customers.

Thank you, Leo. Good morning everyone. I'd like to start the quarterly financial review with a key takeaway on the platform. Starting with our core business on the upper right, Utility, Parent & Other adjusted earnings were $1.12 per share, normalizing the effect of weather and income taxes. This result keeps us in the middle of our UP&O guidance range for the year. Turning to the top left corner, our consolidated earnings were $3.11 per share on an operational view last year. Entergy's reported earnings per share were $2.27, including special items related to decisions to sell or close EWC nuclear plants. This quarter's specials reduced earnings by $0.84 and included $0.48 for refueling outage and fuel impairments, $0.22 for capital that was immediately expensed, and $0.14 for severance and retention costs. Similar to last year, our operational earnings for the quarter reflected tax items. You previously noted the potential of our tax item this year that was not included in our guidance. Therefore, as we communicated last quarter, we are now shifting our 2017 consolidated operational earnings guidance upward by $2.05 per share to reflect the magnitude of the tax item, as you can see in the bottom right corner. Utility, Parent and Other results are summarized on slide 5. Operational earnings were $1.03, and adjusted earnings were $1.12. Weather is estimated to have reduced operational earnings by $0.09 in the quarter. On an adjusted view, earnings were slightly lower than the second quarter of 2016, as higher expenses for nuclear operations consistent with our plan were partly offset by higher net revenue. Net revenue increased from new base rates and riders to recover productive investment to benefit customers. Billed retail sales increased on a weather-adjusted basis with growth across all customer classes. In the industrial group, growth from sales to new and expansion customers came from primary metals, chloro-alkali, and industrial gases. The chloro-alkali segment also contributed to the increase in sales to existing customers. Although billed sales growth for the quarter was strong, the net revenue effect was more than offset by a decline in unbilled revenue. Turning to EWC results on slide 6, operational earnings were $2.08 in the current period compared to $1.34 in the second quarter last year. Both periods include income tax items from election battle, which resulted in a recognition of deductions for decommissioning liabilities today. These deductions created permanent differences. Excluding the tax items, EWCs operational earnings would have been $0.01 in each of the periods. Other variances which offset each other were higher earnings on decommissioning trust and higher decommissioning expense. EWC specials are largely on track for the original full year expectation. With the exception of the income tax benefit in the first quarter and the results from FitzPatrick sales, our current estimate for special items is $2.05 for the year. On slide 7, operating cash flow in the second quarter was $290 million, approximately $439 lower than a year ago. While this was unusual, there are a few understandable explanations for the decline. First, as Leo noted, we had a large number of nuclear refueling outages this quarter, both EWC and the utility plants, including the cost of the outages, as well as lost revenue at EWC. This accounted for about 50% of the total decline. We expect to recover these costs through revenue at EWC and rates utility. EWC's severance and retention payments were approximately $100 million in the quarter, as compared to minimal payments last year. It's important to note that severance and retention expense is accrued rateably over time, paid out at specific milestones, such as the completion of a refueling outage. These have been considered in our EWC cash flow outlook. Most of the remaining change to operating cash flow was in utility; we saw a decrease in cash flow due to the timing of recovery of fuel and purchase power costs. We expect these costs to be fully recovered over time. In the second half of the year, we expect operating cash flow to be higher than last year, making up a portion of the current quarter decline. Now turning to slide 8, we are affirming our Utility and Other adjusted EPS guidance. While full-year non-fuel O&M is expected to be favorable to plan, top-line growth is expected to be lower. We now see full-year sales growth a little higher than 1% with residential and commercial sales lower at around negative 0.5%, mostly offset by industrial sales above our original plan. EWC is expected to come in close to the midpoint assumption plus the quarter's income tax item. As I mentioned earlier, due to the tax item, we shifted the consolidated operational guidance range upward by $2.05 to a midpoint of $7.10. This means that we are in the same position within our guidance range where we would have been. Driven by $0.25 of weather and year to date results, we currently see year-end consolidated operational earnings in the lower end of the range. Looking ahead to the second half of the year on slide 9, there are a few key drivers for the next two quarters that I'd like to highlight in order to align your expectations with ours. For the first half of the year, UP&O adjusted earnings were $0.18 lower than a year ago. Aligning with expectations around the midpoint of our guidance range for the full year, the second half of this year is anticipated to be about $0.20 higher than last year. There are non-recurring items in 2016 that will drive a $0.05 decline in third-quarter earnings and a $0.10 increase in the core. These include DOE awards and regulatory charges, which we highlighted on our quarterly consideration slide on the fourth-quarter call. Looking at the business, we expect continued top-line growth primarily from rate actions—about $0.30 over the remainder of the year. We will continue to see higher nuclear spending to increase staffing levels to be consistent with industry norms and execute on projects that will improve reliability. This will decrease earnings by about $0.20 in the second half of the year, with about two-thirds of that coming in the third quarter. Excluding those items, other non-fuel O&M is expected to drive a $0.10 decline in third-quarter earnings and a $0.20 increase in the fourth. The fourth-quarter variance is primarily project-driven, including four planned outages at natural gas and coal plants in the fourth quarter of 2016, compared to only one this year. Online, we expect third quarter to be below last year and fourth quarter to be above last year. Moving to the longer-term view on slide 10, our adjusted UP&O outlook remains unchanged. Our expectations, especially for 2019 and beyond, are firming up with execution on key deliverables such as regulatory approvals for the Lake Charles Power Station and Montgomery County Power Station, as well as AMI in Mississippi and Louisiana. As always, we are working to mitigate near-term risks and sales growth discount rate, now assumed at 4.5% for ‘18 and ’19. We're also updating our EWC EBITDA outlook on slide 11. Our five-year EBITDA view has come down from last quarter, due mostly to lower power price curves. The spring outages were also longer than planned, which reduced EBITDA. Nonetheless, from an overall cash flow perspective, given changes to EBITDA, capital, working capital, and other categories, we now see an improvement in EWC's free cash flow through 2021, to slightly positive from about breakeven excluding any potential contribution to the decommissioning trust. However, it is still our goal to achieve a cash-neutral position through the end of operation, including decommissioning trust, and that goal remains achievable. Our cash and credit metrics are shown on slide 12. We remain committed to solid investment-grade credit ratings. For the past few years, and especially in the last 12 months, we have made a significant improvement in our credit risk profile. We transitioned to a pure play utility from a hybrid with ongoing merchant risk. Our parent debt to total debt ratio is currently 20.5%, down from 21.1% a quarter ago. We are focused on optimizing the timing and size of the utility debt issuances to maintain the appropriate equity ratios and the right levels of cash at each of our businesses. Our FFO to debt metric has been affected by the operating cash flow drivers previously discussed, and we expect this year to be stronger within the targeted range. Our results this quarter keep us on track to achieve our full-year commitment. We continue to execute on a strategy focused on our four key stakeholders and strengthen the foundation to achieve our steady and predictable growth outlook. At the same time, we will continue to manage risk throughout the company, including the order of the wind down of our merchant business. And now the Entergy team is available to answer questions.

Thank you so much. Hi, guys.

Good morning, Praful.

Morning. So quickly on nuclear O&M, I saw the nuclear O&M was higher on the utility side as well. Just wanted to understand if that is related to the improvement in nuclear operations and also wanted to understand, for instance, what’s the process in terms of recovery of that or getting that as part of the regular proceeding on the regulatory side?

This is Drew, Praful. I’ll take the first part and turn it over to Rod for the second part. So yes, it is related to the ongoing improvement efforts that we are making within the nuclear organization and the same dollars that we highlighted last fall at EEI when we talked about the expectations for spending within the nuclear business going forward. So they are the same thing.

Hey. Good morning, Praful. It’s Rod. On the process of SP recovery and the Arkansas FRB, the ex-parte rules are in effect that FRP process is undergoing with an expectation that a December decision is part of the procedural schedule. Discovery is underway in both the NSP and other costs associated with Arkansas that drive our point of view on revenue requirements that are well supported by the record. And we expect to get resolution on your question within SP by year-end, alongside the rest of Arkansas’ operating costs.

Got you. Thanks. And then secondly on the tax part, there was a meaningful benefit tax deductions on decommissioning liabilities Drew that you talked about. Could you just give a little more color on what that is and how—again, I guess, what's the way that you get that benefit?

Well, Praful, essentially it's an acceleration of the decommissioning liability to become a deduction today. And the way it happens, it's very similar to the same transaction that we had last year, only a little larger because the decommissioning liabilities are larger this year. A lot goes on in that transaction in addition to the deduction. There are offsetting gains, there are basis step ups, there are reserves. But it doesn't all back to zero, and that’s where the earnings come in. So we have certainly worked with the IRS. We've worked through external counsel to make sure that we have the interpretation of the code correct. But we are comfortable where we are. I think those are sort of the main drivers; it's that decommissioning liability recognition that is the main driver of the deduction today.

Understood. Thanks, guys.

Thank you.

Good morning. Just to follow up on the last question on the Arkansas FRP, you said that by year-end you would expect a final decision there. Have you had any conversations with interveners or other parties to give you an indication as to whether the nuclear cost issue would be settled or agreed upon in this exact schedule or if that would get deferred again? I mean, kind of what are you thinking there?

I think one of the reasons I think I stated ex-parte rules are in effect is that we're not allowed to engage at least on the commission staff side of the equation. And so it's early, and I would expect us, looking at the procedural schedule, that we get some indication sometime in the October timeframe, as we begin to get our responses to the positions we've taken from some of the stakeholders. But everything right now is happening on paper with RFIs consistent with the procedural schedule. RFIs mean requests for information amongst the parties.

Okay. And then transitioning to either do you see, you mentioned I think the multiyear cash flow outlook was slightly positive now versus roughly neutral before, excluding any kind of decommissioning activity or funding needs. What has really driven that change and kind of has anything changed on the expense O&M expect front there specifically?

A little bit, but that hasn't been the primary driver. We've also been able to reduce our capital expectations and reduce some of our fuel cost expectations. Those have been probably much bigger drivers than the O&M side. But those are being offset a little bit by the fall in market prices. So we didn't make as much progress as we hoped, but still enough to say that we are a bit ahead of neutral at this point.

Okay, great. That's all I have. Thanks.

Thank you.

Hey, guys. Thanks for taking my question. I want to ask about a couple of the regulated periods. First of all in Arkansas, do I understand correctly you're asking for almost—you're showing that your revenue requirement request is almost $130 million, but due to the caps, you can't actually get that much in the way of new revenue increases?

Yes, that's correct Michael. You know, you have it exactly right.

So we should assume that at least for 2018 there's probably a little bit of under-earning in Arkansas just due to the ballpark $16 million spread between the two unless you’re somehow able to manage O&M down or you get above-average demand growth?

Michael, throughout, I think directionally you're right. We expect to get substantially close to the allowed ROEs by ‘19 and beyond, as we work through both the 4% cap and the true-up mechanisms that will take us through that ‘17 and ‘18 timeframe. But keep in mind that we affirmed our outlooks, and in doing so, we contemplated the allowed ROEs and earnings for Arkansas during that period. So it's consistent.

Got it. And then in both Louisiana and Mississippi on the electric side in the $4 million process, you're not asking for revenue increases. Do either of those subsidiaries see the impact of some of the higher nuclear costs? And if so, why wouldn’t those costs kind of flow through and therefore you need recovery on those expenses?

In Louisiana, we're filing to renew the FRP process that expires with the ‘16 threshold year, and we are not seeking specific recovery of the nuclear costs outside of the normal rate-making process. And so it is with Mississippi, where despite the fact that we have Grand Gulf sitting in the state of Mississippi, Grand Gulf is a FERC regulated facility that's not part of Mississippi's rate-based recovery mechanism. So Mississippi recovers their Grand Gulf-associated costs through a recovery rider.

Got it. And I guess last thing, you mentioned Grand Gulf and kind of the FERC oversight of Grand Gulf. Just curious what’s embedded in that guidance for the ongoing rate case or rate complaint that's underway there?

That’s true. You know, we have contemplated something different than our expectations or I guess the current ROE that we haven't—but we haven’t published what that is because we have ongoing proceeding. But it is based into your outlook.

Are you actually currently baking in your earnings numbers and seeing this in some of the transmission cases where companies went ahead and started booking for earnings purposes a low ROE? Are you actually still booking the original ROE for Syria or are you booking something lower than that due to the complaint?

We're booking something lower. Michael, we're not booking the full amount at this point.

Got it. Okay, guys. Thank you, much appreciated.

Thank you.

Good morning, guys.

Morning, Shahriar.

Good morning.

Let me just ask on the decommissioning activities and the sale process, which has been going on for some time. Can you just maybe elaborate on sort of the interest level there? And then what the process looks like. Are you still looking at Pilgrim and Palisades to potentially be the end point? Or is this just as simple as saying Northstar has made an announcement and that you expect to make something by year-end? Just a little bit of color on that process if you could?

Sure, Shahriar. You know, we'll continue to work down the path on that front that is still a key objective for us. But as we talked about on the call last quarter, it's a pretty involved process, and as we've gone along in Vermont, Vermont has been very engaged on the discovery process. It's been more than probably we were all anticipating in terms of the volume of information, but we continue to believe that we are making good progress on that. But because of the engagement level, the process is likely going to be a little bit slower than what we had anticipated. I don't think it will change our expectations on close rate because we weren’t playing close until the end of 2018 anyway, but it's slowing down the regulatory process. And in turn, that’s slowing down our expectations for where we might go with Pilgrim and Palisades and ultimately the end point. So we are thinking about that we're working down those paths. But these are first-of-a-kind transactions and they're probably taking us a little longer than anticipated, but there's still an objective for us.

Okay. That's helpful. And then just on the same topic. It's good to see that you're modestly cash-positive here, despite the down move on the power curves. But do you expect that if there is a sale process with the remaining three assets from the decommissioning activities, that would have a material impact on the cash flow trajectory of that business?

We are assuming some cash in our current outlooks to be used for that purpose. And so I don't know that it should have a material change in our outlook. But that process remains missing. And what we have out there is based on our expectations for the decommissioning costs, not necessarily a third party. So there could be a little bit difference, and we are aiming through these processes to try and bring our expectations down a little bit. So we do have something built into our outlooks already, particularly going to be reflected mostly in that parent debt to total debt number. But I don't know that we have an expectation at this point to be materially different than that.

Okay, great. Thanks, guys.

Thank you.

Hi, good morning.

Morning, Neel.

Just had a quick question on scheduling with the Arkansas FRP. I believe the procedural schedule had a final decision sometime in January, and I guess you guys are assuming that you're going to get something in December. Just wanted to understand the discrepancy in when you think that could ultimately play out and actually matters if it's in January versus December?

This is Rod. We had the procedural schedule with a hearing and the decision in December that with a rate adjustment would take place in January.

Okay. So the final decision will come in December and then the…

The actual rate impact or adjustment would be made at the beginning of the year.

Okay, great. And then could you kind of remind me, on a rough percentage level, the Nuclear Sustainability plan, you know, in each jurisdiction how involved it is, Arkansas, Louisiana, Mississippi, etc.?

This is Drew. I think that the easiest way to think about it—and I don't know we have any updated disclosures around it—but you know, there's two points - it's almost my eyesight. We have two units in Arkansas. We have two units in Louisiana and then you have Grand Gulf, which is in Syria and it's sort of allocated amongst the few utilities. So I think that's probably the easiest way to think about it.

You know, are there some sites that are going to require more capital spending in O&M than others or for our purposes should we be kind of just weighted equally?

I think weighted more or less equally. There aren’t any—we have visual controls and condenser-type projects in most of them. And so there is not a particular project planned in particular that has a very large capital expectation. And the O&M increases are pretty much the same across each unit.

Got it. That’s very helpful. Thank you.

Thank you.

Yes. Good morning, guys.

Good morning.

I'm just curious; I mean, one of your fellow utilities as it goes, I think over the last several states just announced a major rate base wind project. I'm curious whether you think that's something that might be an opportunity for Entergy, also something along those lines?

You know, Jonathan, we are obviously like everyone else, and we're watching what's happening with the price points or renewable storage. New technologies, we've deployed renewables from the solar standpoint, which is more applicable in our service territory. If it's going to be sourced in our service territory, not without a lot of transmission structure to come in. And as I mentioned, as part of our New Orleans filing, we have also made a commitment to pursue up to 100 megawatts of renewables there. We see them playing a bigger role in our strategy going forward. The majority of what we add in the future will be natural gas and then transitioning into renewables and other technologies as they become cost-competitive. Big wind farms like that for us, we haven't found them to make a lot of sense. I wouldn't rule it out. But right now our focus is probably on smaller, more targeted projects within the footprint of our service territory.

Okay. And then, on a separate topic, I think Leo you mentioned MISO in the planning process in your prepared remarks, and I'm not sure; did you indicate you thought there might be some incremental opportunities coming out of that, or should we think about those being within the context of the current plan?

It's most likely in the context of the current plan.

Okay. All right. That’s it. Thank you very much.

Thank you, Jonathan.

Yeah. Hi, good morning. Just a quick question on the quarter, I think we were a lot of nuclear outages in the quarter, and should we view that as primarily due to the work on the Nuclear Sustainability plan or operational issues?

I'll let Chris give some color. But I will say it's probably a little bit of both. You know, the biggest outage I think we had at EWC was related to the scheduled work. But then there was a lot of work that went on with the nuclear strategic plan in the utility.

Especially if I'd characterize it the same way. This is, of course, the seven outages that were planned normal refueling outages, and then those outages we do take some extra time to improve the safety and reliability of plants. So it's a combination of the two.

Okay. And then Drew, at the end of your comments you mentioned that—and please re-characterize, as I think you said you kind of better firmed up with these plant approvals for 2019 and beyond outlook for the Utility and Other. And then there are some pressures, I thought, on ‘18 stemming from sales and pension. Could you just give a little more color there and what also you know, what should we expect at EI this year? You're going to get some of the key drivers like you normally do?

Sure. We’ll probably come out with the same type of drivers that we typically do see. ‘19 and beyond, that was I think analogous to what Leo was talking about with continued execution on the major capital projects that are going to lead us into the future in terms of rate base growth. And so, you know, our earnings growth should follow that rate base growth over time. But at any given period, what I wanted to say was, you know, we always have risks around both positive and negative for sales growth and pension—you know. The pension growth risk, I highlighted at 4.5%, we might be 25 basis points below that right now. So $0.05 to $0.10 of risk for ’18 sitting there. And then, you know, kind of using rules of thumb, you know, probably the same kind of risk on or opportunity on sales right now. So I just want to make sure that everybody's aware that those risks on a near-term basis are always out there. But over, you know, a couple of cycles in the regulatory process, it should smooth out, and the main driver is long-term going to be the capital growth in our rate base.

Okay. Thank you.

Thank you.

Thanks. Most of my questions have been answered. But pardon me if I missed this, but I know that you continue to say, as you did in the first quarter, that you're doing better on O&M relative to the baseline expectation and guidance. Can you refresh our memories specifically what areas you are doing better than budget?

This is Drew. Greg, so the main areas where we have been doing better are in the utility related—I'm talking about year-to-date. There is a little difference on the second half of the year because some of it's project-driven. But the main things year-to-date have been expectations around primarily our power generation business, which was primarily our fossil generation. We have been able to operate at lower costs year-to-date there and capture some of that. And we've also seen some lower insurance costs. We were anticipating lower insurance costs this year, but some of the premiums are coming in even better than what we anticipated. So that's been helping out. And those are things that we would continue to expect to see through the balance of the year. Some of the other pieces are timing-related costs; if we thought we were going to spend like in the second quarter, but they're now in the third quarter, that kind of thing. And those we are anticipating in the second half of the year, as part of what I've laid out. But the main things have been in our power generation business, not including nuclear, and in some of our traditional overhead costs.

Great. Thank you.

Thank you.

Thanks, Greg.

Thank you. Leo, I believe you said the industrial sales are ahead of plan year-to-date. Can you give a little more color as far as long-term? I mean, are you still pretty bullish on industrial sales, and what growth rate can you look at? I know you talked a lot about that in the past?

Yeah. Actually, Drew said it, so I'll let him start.

So Charles, the industrial growth expectation is that it will continue on for the next few years. Although in ’18, we are anticipating a slight slowdown to the industrial growth, and that’s because one of the—or actually a couple of the main drivers for ‘18 growth, those projects have been delayed and are now expected to come online in ‘19. And they were pretty large customers. So while we still are expecting large growth over the next few years comparable to what we are expecting this year on average, it’s going to be a little off-center, a little less than ’18, and probably a little bit more than ’19.

So going forward, lumpy, but you're still seeing in that same growth trajectory in the Mississippi Delta, correct?

That’s correct, for the next couple of years, next few years.

Okay…

You know, once you get out beyond like ’20, ‘21, it's a little lumpier. But you know we—because we're talking about these large industrial customers, you can usually see them coming a couple of years out. So we're basing our industrial growth based on those large customers being added to the system. Beyond that, it's hard to see because they're not yet reaching their financial decision points in order to make decisions to go forward.

Okay. That was all I have. Thank you.

Thanks, Charles.

Thank you, Amanda, and thank everyone 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 August 9 and provides more details and disclosures about our financial statements. The 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 then finally, please note that we've added a new page to Entergy's Investor Relations website called regulatory and other information, which contains information that we think will be helpful to investors. We plan to provide key updates on regulatory proceedings and important milestones on the execution of our strategy, and the company plans to use its corporate Twitter feed to notify investors of updates to this web page. While some of this information may be considered material, investors should not rely exclusively on this new website for all relevant company information. The website will not provide updates of every filing made in every regulatory proceeding or updates of all progress made on strategic execution. This concludes our call. Thank you.