安特吉 (ETR) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Entergy Corporation Second Quarter Earnings Teleconference. (Operator Instructions) As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Mr. David Borde, Vice President, Investor Relations. Sir, you may begin.

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. (Operator Instructions)

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 and 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. 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 increase its distribution cost recovery rider.

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 projects, 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're reporting that Utility, Parent & Other adjusted earnings per share contributed $1.12 to our consolidated results for the quarter. These results are 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 and operational earnings guidance to reflect an income tax item at EWC, which Drew will discuss further in his remarks.

During the quarter, we continued 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 Louisiana Public Service Commission to move forward with the construction of the Lake Charles Power Station in Westlake, Louisiana. This approximately 990-megawatt 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 an approximately 990-megawatt CCGT with the same technology as the Lake Charles Power Station. The plant 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 are highly efficient by capturing and using wave stream for 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 through 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 7 natural gas-fired reciprocating engines. Both projects offer significant benefits to our customers and provide modern, efficient fast-start 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 would facilitate the adoption of renewables into Entergy New Orleans 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 our 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, maintain compliance with NERC standards and support economic development in our region. We'll continue to work with MISO on future transmission projects. The 2017 MTEP planning process is on course, and the MISO board is evaluating our nearly $1 billion plan over the next 5 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 reached significant milestones. The Mississippi and Louisiana Public Service Commissions were the first of our 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 of 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 advanced meters will provide to our customers, and the follow-on technologies and services they enable will provide new opportunities to reduce costs and provide 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 EMI'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. The earned ROE of 9.84% was within the approved band, indicating no change to base rates. As a reminder, this marks the last filing under the current 3-year formula rate plan, and we will be working with our commissioners and stakeholders to seek to renew the FRP mechanism with some adjustment.

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, our 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 cost from last year's filing that remains subject to refund. The commission approved our request, and our filing includes further information supporting the prudence of those costs. In addition, in Texas, the Governor signed a bill that removed the Distribution Cost Recovery Factors 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 7 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 are consistent with the types of project performed at other nuclear fleets and support sustained operational excellence to improve 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 replaced the analog turbine 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 shutdown. We replaced heat exchangers at 2 units to correct marginal heat removal capability. We replaced turbine blading at 2 units to maintain optimum performance, and we 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, while others are smaller than 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 outlooks.

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 reviewing 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 the complete wind-down of our merchant operations, we will continue to look for opportunities to divest our nuclear assets post-shutdown for the purposes of decommissioning. However, if those efforts do not materialize into firm transactions, we are prepared and able to successfully manage the process from shutdown into dormancy, also known as SAFSTOR, 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.

Though 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 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, a Points of Light initiative honoring the most -- the 50 most community-minded companies in the nation. The Women's Business Enterprise National Council presented Entergy with the 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 -- of the 2017 Top Workplaces in New Orleans region in recognition of Entergy's organizational health. Furthermore, we remain dedicated to the economic development of our region through our $5 million 5-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 are flourishing.

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 outlooks. A large majority of our capital plan through 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 towards investing in the integrated Entergy network of the future. Technology investments beyond AMI represent the future of our company and our industry and will deliver benefits to our customers that will fundamentally alter 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 rates for the benefit of our customers.

And now I'll turn the call over to Drew.

Thank you, Leo. Good morning, everyone. I'd like to start the quarterly financial review with the key takeaways on Slide 4.

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, flat to a year ago. Entergy's as-reported earnings per share were $2.27, including special items related to decision to sell or close EWC's nuclear plants. This quarter's special items reduced earnings by $0.84 and included $0.48 for fueling outage and fuel impairments, $0.22 for capital that was immediately expensed and $0.14 for severance and retention cost.

Similar to last year, our operational earnings for the quarter reflected tax items. As we previously noted, the potential for a tax item this year 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 & 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 $0.06 lower than second quarter 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 investments that benefit customers. Field 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, chlor-alkali and industrial gases. The chlor-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's 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 elections that, for tax purposes, resulted in recognition of deductions for decommissioning liability today. These deductions created permanent differences. Excluding the tax items, EWC's 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 the FitzPatrick sale, 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 $430 million 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 at both EWC and Utility plant. Including the cost of the outages as well as loss revenue at EWC, this accounted for about 50% of the total decline. We expect to recover these costs through revenues at EWC and rates at 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 ratably over time but paid out at specific milestones such as the completion of refueling outages. These have been considered in our EWC cash flow outlook.

And most of the remaining change to operating cash flow within the Utility, we saw a decrease in cash flow due to the timing of recovery of fuel and purchased power costs. We expect these costs to be fully recovered over time. For the second half of the year, we expect operating cash flow to be higher than last year, making up for a portion of the current quarter decline.

Now turning to Slide 8. We are affirming our Utility, Parent & Other adjusted EPS guidance. While full year nonfuel 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 its midpoint assumption plus this 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 negative $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 2 quarters that I'd like to highlight in order to bring your expectations in line 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 nonrecurring items in 2016 that will drive a $0.05 decline in third quarter earnings and a $0.10 increase in the fourth. 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 to execute on projects that will improve reliability. This will decrease earnings about $0.20 in the second half of the year, with about 2/3 of that coming in the third quarter. Excluding those items, other nonfuel 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 4 planned outages at natural gas and coal plant in the fourth quarter of 2016 compared to only one this year. Bottom line, 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 the Montgomery County Power Station as well as AMI in Mississippi and Louisiana. As always, we are working to mitigate near-term risks in sales growth, and the pension discount rate is now assumed at 4.5% for '18 and '19.

We're also updating our EWC EBITDA outlook on Slide 11. Our 5-year EBITDA view has come down since 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 contributions to the decommissioning trust. However, it is still our goal to achieve a cash-neutral position through the end of operations, including the 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. Over the past few years, and especially in the last 12 months, we have made a significant improvement in our credit risk profile as we transition 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 remain focused on optimizing the timing and size of Utility debt issuances to maintain the appropriate equity ratios and the right levels of cash at each of our business.

Our FFO-to-debt metric has been affected by the operating cash flow drivers previously discussed, and we expect to finish the year stronger within the targeted range.

Our results this quarter keep us on track to achieve our full year commitments. We continue to execute on the strategy that focuses on our 4 key stakeholders and strengthens 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 orderly wind-down of our merchant business.

And now the Entergy team is available to answer questions.

(Operator Instructions) Our first question comes from the line of Praful Mehta of Citigroup.

So quickly on nuclear O&M. I saw the nuclear O&M was higher, the Utility side as well. Just wanted to understand, is that related with the improvement in nuclear operations? And also, I wanted to understand for Entergy Arkansas, 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, and 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 they are 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.

It's Rod. And on the process of NSP recovery and the Arkansas FRP, 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 regular requirements are well supported by the record. And so we expect to get resolution on the -- on your question with NSP by year-end, alongside the rest of Arkansas' operating cost.

Got you. And then secondly, on the tax part, there was a meaningful, I guess, benefit tax deductions on decommissioning reliabilities, Drew, that you talked about. Could you just give a little bit more color on what that is and how -- 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. There's a lot that 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 net back to 0. And that's where the earnings comes in. So we have certainly worked with the IRS. We worked through external counsel to make sure that we have the interpretation of code correct. But -- and we're comfortable where we are. And I think those are sort of the main drivers. It's that decommissioning liability recognition that's the main driver of the deduction today.

Our next question comes from the line of Chris Turnure of JPMorgan.

Just a follow-up on the last question on the Arkansas FRP. You said kind of by year-end, you would expect a final decision there. Have you had any conversations with intervenors 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? And then 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 time frame as we begin to get 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 being request for information amongst the parties.

Okay. And then transitioning to EWC, you mentioned, Drew, I think that 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 O&M expense front there specifically?

A little bit. 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. And those -- but those have been offset a little bit by the fall-in market prices. So we didn't make as much progress as we hoped, but it was still enough to say that we are a bit ahead of neutral at this point.

Our next question comes from the line of Michael Lapides of Goldman Sachs.

I want to ask about a couple of the regulated subsidiaries. First of all, in Arkansas, if I understand correctly, you're asking for almost -- you're showing that your revenue requirement request is almost $130 million. But due to the cap, you can't actually get that much in the way of new revenue increases.

Yes, yes.

Yes, that's correct, Michael. And we -- you have it exactly correct.

So we should assume that at least for 2018, there's probably a little bit of underearning in Arkansas just due to the ballpark $60 million spread between the 2, unless you're somehow able to manage O&M down or you get above average demand growth?

Michael, it's Rod. 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 time frame. But keep in mind that we affirmed our outlooks. And in doing so, we contemplated the allowed ROEs and the 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 formula rate plan 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 -- recovery of those expenses?

In Louisiana, we are filing to renew the FRP process that expires in -- with the '16 test year, and we're not seeking specific recovery of the nuclear cost outside of the normal rate-making process. And so it is with Mississippi -- where Mississippi, 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 base recovery mechanism, so Mississippi recovers their Grand Gulf-associated cost 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 guidance for the ongoing rate case or rate complaint that's underway there?

This is Drew. We have contemplated something different than our expectations or, I guess, the current ROE, but we haven't published what that is because we have that ongoing proceeding. But it is baked into our outlook.

Are you actually currently baking in your earnings numbers? We've seen this in some of the transmission cases, where companies went ahead and started booking, for earnings purposes, a lower ROE. Are you actually still booking the original ROE for CRE? Or are you booking something lower than that due to the complaint?

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

Our next question comes from the line of Shahriar Pourreza of Guggenheim Partners.

So let me just ask on the decommissioning activities and the sale process. It's been going on for some time. Can you just maybe elaborate on sort of the interest level there and what the process looks like? Are you still looking at Pilgrim and Palisades potentially in the end point? And then -- or is this just as simple as saying NorthStar hasn't made an announcement and is expected to make something by year-end? Just a little bit of color on that process would be good.

Sure, Shahriar. Yes, we're continuing to work down the path on that front, so 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. We don't think it'll change our expectations on a close day because we weren't planning the 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, Indian Point. So we are thinking about that, and 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 they're still an objective for us.

Okay, got it. That's helpful. And then just on the same topic. It's good to see that you're modestly cash flow-positive here despite the downward move on the power curves. But do you expect that if there is a sale process with the remaining 3 assets on -- from the decommissioning activities, that would have a material impact to 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 to be seen. 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 expectation down a little bit. So we do have something built into our outlooks already. Particularly, it's 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 too materially different than that.

Our next question is from the line of Neel Mitra of Tudor, Pickering.

Just had a quick question on scheduling with the Arkansas FRP. I believe the procedural schedule had a final decision in -- 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 and when you think that could ultimately play out and if it 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 -- where the rate adjustment would take place in January.

Okay, so the final decision would come in December, and then the actual rate...

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 new, Chris, sustainability plan in each jurisdiction, how involved it is, Arkansas, Louisiana, Mississippi, et cetera?

This is Drew. I think the easiest way to think about it -- and I don't know we have any updated disclosures around it, but there's 2 -- it's almost by site. You have 2 units in Arkansas. You have 2 units in Louisiana. And then you have Grand Gulf, which is in CRE and is sort of allocated amongst the -- amongst a few of the utilities. So I think that's probably the easiest way to think about it, Neel.

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

I think it's weighted more or less equally. There aren't any -- we have sort of like digital controls and condenser type projects in most of them, and so there's not a project or plan, in particular, that has a very large capital expectation. And then the O&M is pretty much the same -- increase is pretty much the same across each unit.

Our next question comes from the line of Jonathan Arnold of Deutsche Bank.

Just curious, so in one of your fellow utilities, I think, overlaps with you in several states, just announced they've made a rate base wind project. I'm curious whether you think that's something that might be an opportunity for Entergy to something along those lines.

Jonathan, we're -- obviously, like everyone else, we're watching what's happening with the price points of renewables, storage, new technologies. We've deployed renewables from a 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 infrastructure to come in. And as I mentioned, as part of our New Orleans filing, we have also made a commitment for 100 megawatts 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 then other technologies as they become cost-competitive. Big wind farms like that, for us, we haven't found any that make a lot of sense. Wouldn't rule it out. But right now, our focus is probably on smaller, more targeted projects within the footprint of our service territory itself.

Okay. So -- and then 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 that you thought there might be some incremental opportunities coming out of that? Or is that -- should we think about that as being within the context of the current plan?

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

Our next question comes from the line of Steve Fleishman of Wolfe Research.

Just a quick question on the quarter. The -- I think there were a lot of nuclear outage days in the quarter. Should we view that as primarily being doing 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. The biggest outage, I think, we had at EWC was related to the baffle bolts, but then there was a lot of work that went on with the nuclear strategic plan in the Utility.

Yes, Steve, I'd characterize it the same way. This is Chris. The 7 outages were planned, normal refueling outages. And in those outages, we did take some extra time to improve the safety and the reliability of the plants. So it's a combination of the 2.

Okay. And then, Drew, at the end of your comments, you mentioned that -- and please recharacterize this. I think you said you kind of better firmed up with these FERC plan approvals, the 2019 and beyond outlook for Utility, Parent & Other. And then -- but then noted some pressures, I thought, on '18 from sales and pension. Could you just give a little more color there? And what also -- what should we expect at EEI this year? Are you going to give some of the drivers like you normally do?

Sure. We'll probably come out with the same type of drivers that we typically do, Steve. The '19 and beyond comment 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 our earnings growth should follow that rate base growth over time. But any given period, what I wanted to say was we always have risks around -- both positive and negative, for sales growth and pension. The pension 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 kind of using the rule of thumb, probably the same kind of risk on our opportunity on sales right now. So I just want to make sure that everybody is aware that those risks on a near-term basis are always out there. But over a couple of cycles and the regulatory process, those should smooth out. And the main driver is, over the long term, going to be the capital growth in our rate base.

Our next caution comes from the line of Greg Gordon of Evercore ISI.

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 on what areas you're doing better than budget?

This is Drew, Greg. So the main areas where we have been doing better are in Utility related. I'm talking about year-to-date. They're a little bit different 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 with -- primarily, our fossil generation. We have been able to operate at lower costs year-to-date there and capture some of that. So we've also seen some lower insurance costs. We were anticipating lower insurance cost this year, but some of the premiums have come in even better than what we were anticipating, 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 that we thought we were going to spend, like 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 had laid out. But the main things have been in our power generation business, not including nuclear, and then some of our traditional sort of overhead costs.

And our last question comes from the line of Charles Fishman of MorningStar.

Leo, I believe you said that 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 are you? Continuing to look at it, I know you talked a lot about that in the past.

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

It works for me.

And it works for me, too, because Drew's a smarter guy than I am so I appreciate the compliment.

So Charles, the industrial growth expectation is that we'll 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-centered, a little less than '18, probably a little bit more '19.

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

That's correct, for the next couple years, next few years. Once you get out beyond like 2021, it's a little murkier. But we -- because we are talking about these large industrial customers, you can usually see them coming a couple of years out. And so we're basing our industrial growth based on those large customers being added to the system. And beyond that, it's harder to see because they're not yet reaching their financial decision points in order to make decisions to go forward.

And at this time, I'd like to turn the conference back over to Mr. David Borde for any closing remarks.

Thank you, Amanda, and thank you, everyone, for participating this morning. Before we close, we'll 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. Events that occurred 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 to 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 our strategic execution. This concludes our call. Thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everybody, have a great day.