安特吉 (ETR) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Entergy third-quarter earnings teleconference.

(Operator Instructions)

As a reminder, today's conference is being recorded. I would now like to introduce your host for today's conference Mr. David Borde, Vice President Investor Relations. Sir, please go ahead.

Thank you, Liz. Good morning and thank you for joining us. We will begin today with comments from Entergy 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 followup.

In today's call Management will make certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to a number of risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements.

Additional information concerning these risks and uncertainties is included in the Company's SEC filings. Management will also discuss non-GAAP financial information, and 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. Today we're announcing another solid quarter, with operational earnings per share of $2.31. Adjusted earnings of $1.98 for our core utility, parent, and other business were substantially higher than last year and in line with our growth expectations.

We remain on track to meet this year's guidance for utility, parent, and other adjusted earnings per share. As our results show, we continued to execute on our strategy and meet our objectives, both at the utility and EWC. At the beginning of the year we set out our to-do list as shown on slide 3.

And with three quarters of 2016 now behind us, I'm happy to say that we've successfully completed most of those tasks. Each of these accomplishments supports our objective of steady and predictable growth at the utility while managing risk and reducing our EWC footprint.

At the utility we continue to make needed investments which will modernize our system and enhance its efficiency and the reliability for the benefit of our customers. We have a number of generation projects in front of us which will meet this purpose. First, the St. Charles Power Station is a 980 megawatt CCGT to be constructed and placed into service in Montz, Louisiana by June of 2019.

The administrative law judge recommended supporting the certification of this project in July, and we are awaiting a final regulatory decision from the Louisiana Public Service Commission. The commission has faced some scheduling challenges, and it has been difficult for the full commission to take up major items for vote.

However, we anticipate that the Commission will be able to make a decision on this project before the end of the year. On October 7, Entergy Texas made its filing with the Public Utility Commission of Texas seeking a certification to construct the Montgomery County Power Station.

This 993 megawatt highly efficient combined-cycle plant will provide reliable power at significantly reduced energy costs. The plant will produce an expected $1.7 billion in net benefits to our Texas customers. In addition, the plant will use state-of-the-art emission control technology to lower air emissions.

And construction, anticipated to begin in 2019, will provide more than 2,800 direct jobs in Texas and nearly $1 billion in economic activity for the local economy. In June, Entergy New Orleans filed an application with the New Orleans City Council seeking approval to construct a New Orleans power station.

226 megawatt CT will provide a modern, cost-effective, local resource to enhance reliability and operational flexibility, mitigate market risks, and aid in restoration efforts following major weather events. The construction of this plant will produce hundreds of millions of dollars in economic benefits for the state and local economy.

We are currently working with the city council to set a procedural schedule, and we expect to make filings with the Louisiana Commission to begin the regulatory approval process for the Lake Charles CCGT later this year. This also will be a highly efficient plant that will support the growing customer base in the Lake Charles area.

Additionally, we estimate the plant will provide around $1.4 billion in savings to customers over its lifetime. Our transmission grid is equally vital for the operation of our system, and ongoing investments are required for compliance, reliability, and efficiency.

We continually make upgrades and additions to the grid to enhance our level of service and make room for growth. At the end of June, we completed Phase 2 of our Pine Bluff Voltage Support Project in Arkansas, constructing a new 230 KB substation and transmission line.

In July, we also finished the installation of a 230 KB line, a 500 KB to 230 KB auto transformer, and a 230 KB substation to better serve our customers in Texas. Some of our transmission investment decisions are made through the annual MISO Transmission Expansion Planning process, also known as MTEP.

We're nearing the end of the MTEP planning process for 2016. Currently we have 48 projects totaling roughly $480 million under consideration. The MISO Board will make its selections and give final approval to projects in December.

On September 15 we submitted about $700 million of proposed projects for MTEP 2017, and we will work with MISO on the selection process for those proposals over the course of the next year. For the last several years we've been executing on these and other traditional generation and transmission projects. We've also begun to outline the investments which will lay the foundation for an integrated energy network.

To that end, on September 19 Entergy Arkansas was the first of our jurisdictions to make regulatory filings seeking approval from its commission for advanced metering implementation. These were followed by filings from Entergy New Orleans on October 18. In each filing we've requested that our regulators find the deployment of advanced metering infrastructure to be in the public interests.

Entergy Arkansas expects to recover its investment through its forward-looking FRP. Entergy New Orleans has requested approval to implement a phased in customer charge. Deployment of this infrastructure, including advanced meters, is expected to bring total net benefits of approximately $260 million to our customers in Arkansas and New Orleans in addition to improved outage restoration, enhanced customer service, and tools to better manage energy usage.

Contingent on approval by the Arkansas Commission and the New Orleans City Council, meter deployment would begin in 2019. Ahead of meter deployment we're focused on constructing and integrating the back office systems that support this technology and make it smart; a meter data management system.

A new outage management system and distribution management system as well as designing and installing the infrastructure for our communications network. Advanced meters are a big step forward, and the advantages they provide to our customers as well as the follow-on technologies and services they enable represent the future of our Company and our industry.

I'd like to take a moment now to extend our sympathy to the family and friends of Clyde Holloway, the Louisiana Public Service Commission Chair who recently passed away. Commissioner Holloway was consistently fair, dedicated to serving the public interest, and true to his convictions. We appreciate his many years of public service.

Last Friday the governor of Louisiana appointed Charlie DeWitt, former speaker of the Louisiana House of Representatives, to fill the remaining months of Commissioner Holloway's term. We look forward to working with Commissioner DeWitt.

As you know, we've spent the last few years working with our regulators, Commissioner Holloway, and others for improvements in our regulatory constructs. These constructs are now facilitating our investment in the utility infrastructure.

For example, this quarter Entergy Arkansas reached a settlement in its first FRP filing with a forward test year. We've requested any potential rate adjustments to be in effect on December 30. Entergy Mississippi completed its FRP filing with a stipulated settlement for a $19.4 million rate increase. New rates were effective in July 2016.

Entergy Texas filed for a $19 million annual increase to its transmission cost recovery factor rider in September, reflecting $210 million of incremental transmission investment since its last base rate filing. Entergy Texas also presented its view on alternative rate-making mechanisms to the public utility commission in Texas through a filing made in August.

This filing was in response to the Texas legislature's request for the commission to conduct a study and make recommendations regarding appropriate reforms to the rate-making process. In its comments Entergy Texas asserted that a formula rate plant with a forward test year is an effective mechanism to reduce regulatory lag.

This mechanism would provide utilities with an opportunity to earn their authorized returns, and is also beneficial to a utilities credit ratings, providing access to capital at lower cost to customers and facilitating the infrastructure investment to support economic development and the creation of jobs in Texas. The commission will consider the filing along with the recommendations from others and provide its final rate-making report to the legislature in January.

And our FERC regulated system agreement came to an end on September 1 after more than 50 years of existence. This agreement has been a source of litigation between Entergy and various retail regulators for years, and its elimination removes that risk and allows us to focus more specifically on the priorities and policies of local regulators.

You've also heard us talk about the importance of controlling bills for our customers. Our rates continue to be among the lowest in the country, and these low rates are one of the factors that make our region attractive for industrial development. We've said there are number of levers available to keep overall customer bills reasonable.

In one such example, last month $55 million of Mississippi storm restoration bonds for Hurricane Katrina were fully paid off, and we were able to remove that charge from our customers' bills. These are the first storm securitization bonds to roll off bills, and more will follow for our customers in Louisiana in 2018 and Texas in 2021.

Shifting to our nuclear operations, we recognize the importance of nuclear power as part of the national energy landscape and the significant benefits our plants bring to our stakeholders. Nuclear power is a source of low cost, steady, reliable base load power that provides fuel diversity to our generation portfolio and reduces fuel price volatility.

It minimizes our environmental footprint by creating virtually no emissions. Each plant anchors its surrounding community with steady, good paying jobs, a significant property tax base, and other ancillary economic benefits. And last but not least, we believe the plants are necessary to ensure the continued reliability of our electric grid.

We must preserve the benefits our plants provide and ensure their operations are in line with evolving nuclear industry standards for operational excellence. This requires that we look at what investment is needed to ensure safe and reliable operations in the near term, as well as what it will take to prepare plants to operate to the end of their expected operating lives.

As a result, going forward the costs to operate our plants will be higher. Prudently investing to preserve these valuable resources for our customers, communities, employees, and owners is an important part of our utility strategy. Our financial plan now includes the investments we believe are needed to meet our goals for nuclear operations as well as mitigating actions and rate treatment.

Drew will discuss our revised earnings outlook and other outlook information in his remarks. Turning briefly to EWC, operational earnings for the quarter were essentially flat to the same quarter of last year. Like many merchant generators we face market challenges, including very low commodity prices.

These challenges are apparent in the revised EWC EBITDA outlooks we provided today, and further validate the progress we've continued to make on our strategy to reduce our merchant footprint. On August 9 we announced our agreement to sell the FitzPatrick plant to Exelon.

We recently received early termination of the HSR waiting period, and we continue to work through the required regulatory approvals with the NRC, FERC, and the New York Public Service Commission. We're targeting the second quarter of 2017 to close the transaction.

We also continue to proceed along two parallel paths, both the plant's refueling and potential sale and the possibility of permanent shut down and decommissioning. Once again, I would like to thank our FitzPatrick employees who continue to operate the plant safely and reliably throughout this transition.

We also entered into agreements this quarter to sell our EWC wind assets in Iowa and Texas and expect to close on that transaction in the fourth quarter of this year. We will continue to be disciplined in our assessment of every remaining asset in our EWC portfolio to execute on our strategy to reduce our merchant footprint.

Many of you have heard about the mid-August rainstorms in south Louisiana which brought devastation to so many of our customers as well as our employees. These historic rains dropped an estimated 7 trillion gallons of water in one week, damaging roughly 60,000 homes and businesses and causing outages to more than 32,000 of our electric customers.

Our crews worked tirelessly to restore power quickly and safely to customers. After the water receded, hundreds of Entergy employees from four states, friends and family members, all logged over 10,000 hours of volunteer service helping to clean flooded homes. In addition, they collected needed tools and supplies and provided meals to those in the area, coming together admirably to support each other and the affected community.

To that end, Entergy contributed $525,000 to local nonprofit organizations to help them respond to the storm. I'd also like to acknowledge those who were recently affected and suffered losses in the wake of hurricane Matthew.

Along with many of our peer utilities, Entergy provided over 400 workers to assist with restoration efforts. We were eager to respond to this call for help as others have done for us many times in the past. In many ways, events such as these are an important reminder of who we serve and what we do best.

Supporting the communities where our customers and employees live has always been a part of who we are at Entergy and one of the many ways we power life. In recognition of efforts such as these as well as our other sustainable business practices, Entergy has been named to the DOW Jones sustainably index for a 15th consecutive year.

We earned top scores in the areas of corporate citizenship and philanthropy, climate strategy, biodiversity, and water related risks. The index confirms that we are focused on the right things and successfully providing value to each of our four stakeholders.

Site Selection Magazine named Entergy as one of the nations top 10 utilities in economic development in 2015. This is the ninth year in a row that we've been named to the list, recognizing our integral role that resulted in nearly $10 billion of capital investment and the creation of over 4,800 jobs in our service territory.

We know that economic development is important for our customers across the region, and it's also good for business. We'll continue to work with our state agencies and local communities to promote growth across our service territory. In summary, this was another solid quarter.

Both our consolidated operational earnings and our adjusted earnings for our core business were substantially higher than last year and in line with our growth expectations. Our solid results to date demonstrate our ability to continue to execute on our strategy.

With that backdrop, I will also note that our financial outlooks now reflect our prudent decision to position the nuclear fleet for sustained operational excellence along with other non-fuel O&M adjustments such as increased benefit expenses due to the prolonged low interest rate environment and the industry-wide reality of flattening consumption from residential and commercial customers. Despite the near-term effects, the incorporation of these items in our financial outlook strengthens our competence and our ability to deliver on our long-term goals as reflected in our unchanged 2019 outlook.

As we look down the road to 2019 and beyond, we continue to see the benefits of the progress and accomplishments we've made over the past 24 months, to execute on our objectives of steady predictable growth on utility, parent, and other earnings, and corporate dividends. We look forward to talking with you some more about our plans and our outlooks at EEI next month. And with that I will turn the call over to Drew.

Thank you, Leo, and good morning, everyone. In addition to reviewing the quarterly results, I'll take some time today to talk about our longer-term outlooks. We know that you are all anticipating an update on our nuclear investments and its financial effects. We decided to give you key information in advance of EEI to help you better prepare for those meetings.

I will start with the key takeaways from our third-quarter results on slide 4, beginning with the consolidated results in the top left corner. As reported, earnings included special items related to EWC nuclear plant that we've identified to close or sell. Last year's results included significant impairments for the FitzPatrick and Pilgrim plants.

On an operational view, our consolidated earnings were $2.31 per share in the current period. This compares to $1.90 a share a year ago. The increase was due to growth in our core utility, parent, and other business shown in the top right corner. Utility, parent and other adjusted earnings increased more than 25% above last year, which I'll discuss shortly.

Just a reminder, our adjusted view normalizes for special items, the estimated effect of weather, and income taxes. Looking at the bottom left corner, EWC operational results were essentially flat. Operational earnings per share of utility, parent and other increased $0.40 quarter over quarter, shown on slide 5.

Looking at the orange bars on an adjusted view, utility, parent, and other results increased $0.42. This growth reflects rate actions to recover productive investments that benefit customers and improve returns. Specific drivers include Entergy Arkansas' rate case, the Union Power Station acquisition, Entergy Mississippi's recent formula rate plan, and Entergy Texas' new transmission cost recovery rider.

Build retail sales for the quarter were lower than a year ago. We continued to see weakness in both residential and commercial sales. Industrial sales were also lower, even considering the continued growth for new and expansion customers. This is consistent with our comments last quarter.

Despite the lower sales volume, industrial revenue was up, excluding rate effects, because of the demand components of the bill and the new customers. For the full year, we anticipate industrial growth to be in line with our original guidance assumption of approximately 2.9%, and we expect industrial growth to continue into next year at around the same level.

Also contributing to the UPO earnings increase was non-fuel O&M which declined. Lower pension and other post-retirement benefit expenses were the largest driver. Turning to EWC's third-quarter results, summarized on slide 6, operational earnings were $0.19 in the current quarter, compared to $0.18 a year ago.

Effects from 2015 impairments were partly offset by lower energy prices. Decommissioning expense was also higher due to the establishment of decommissioning liabilities for Indian Point 3 and FitzPatrick as a result of our agreement with NYPA to transfer the decommissioning trusts and liabilities to Entergy.

Slide 7 shows operating cash flow was once again around $1 billion, consistent with the same quarter last year. Our 2016 earnings guidance is summarized on slide 8. As you can see, we are affirming our 2016 guidance with consolidated operational EPS and utility, parent, and other adjusted EPS.

For the consolidated operational view, positive weather in the third quarter is being more than offset by lower EWC revenue and higher decommissioning expense for the NYPA trust transfer transaction. We also expect a slightly higher effective tax rate. Overall, we currently expect consolidated operational results will be within the bottom half of the range.

For utility, parent, and other we still expect adjusted earnings for the year at around the midpoint of our guidance range. That said, there are a few things that we're keeping an eye on. As you know, we have the Waterford 3 steam generator replacement project before the Louisiana Commission, and that issue is not yet fully resolved.

Grand Gulf is also in an extended outage, and we will continue to monitor this for potential implications. On the positive side, we recognize that our non-fuel O&M is favorable to our plan through the third quarter. We will continue to monitor our spending for opportunities in the fourth quarter.

In just under two weeks at EEI we will discuss our strategy and longer-term views. However, I would like to take a minute to talk about our financial outlooks starting with utility, parent, and other adjusted EPS on slide 9. At Analyst Day, we knew that we would have significant incremental spending to ensure the longer-term sustainability of our nuclear plants.

Since then we have spent the last few months going through the process that Chris Bakken outlined to help us understand the magnitude of the investment needed to position our fleet for sustained operational excellence. The low interest rate environment and its effect on our pension and post-retirement benefit expenses was also discussed at Analyst Day.

More recently residential and commercial sales have been lower than our expectations, and we now expect a lower growth rate. Our goal was to fully mitigate these effects by identifying opportunities to operate our business more efficiently, reprioritizing projects among the business functions, and utilizing regulatory mechanisms available to us as needed.

Considering all of this, we now expect our utility parent and other adjusted earnings to be lower in 2017 and 2018. However, we're still on track for greater than 5% three-year growth based on the midpoints of our adjusted 2019 outlook versus our 2016 guidance.

Slide 10 illustrates the major changes from our original utility, parent, and other outlook to our current expectations. The primary drivers for our changes are the aforementioned higher nuclear costs, lower pension discount rate, and lower retail sales which are expected to be about $0.75 in 2017, partially offset by mitigations we've identified over the past several months which total about $0.25 in 2017, and increased net revenue from rate actions and other items which will help about $0.20 next year.

Regarding mitigations, we've worked hard over the past several months to identify opportunities. For example, on the last call we talked about interest expense reductions from economic refinancings. We've also issued new debt at rates lower than we planned. In addition, we've identified O&M savings from various employee-led initiatives throughout the Company, driving improvements and sourcing benefits, insurance, outage, operational, and other costs over the next few years.

Our outlook now reflects recovery of our prudent spending net of mitigations through our normal rate-making mechanisms. On slide 11 EWC's operational adjusted EBITDA outlook also reflects lower expectations. A summary of what's changed is provided on slide 12.

Like utility, parent, and other, net revenue and non-fuel O&M are the two key drivers for the changes at EWC. Revenue estimates declined due to lower forward prices and reduced volume from revised assumptions on outages, including at Indian Point to more conservatively plan additional time for potential replacement of baffle poles.

As noted on slide 13, we will have additional details at the EEI financial conference where we will continue the discussion of our business strategy, including our nuclear investments, longer term outlooks, and 2017 drivers. As has been our practice, we anticipate that we will provide earnings guidance for 2017 and our detailed three-year capital plan on our fourth-quarter earnings call.

We realize that we've covered a lot of new information today. We've also included some information on our nuclear investments and our preliminary three-year capital plan in the appendix of our webcast presentation.

We'll be listening to your questions today and over the next week, and will provide information that you need to understand and analyze these changes at EEI. We look forward to moving ahead with the strategies to create value for our owners, our customers, our employees, and the communities we serve. And now, the Entergy team is available to answer your questions.

(Operator Instructions)

Greg Gordon, Evercore ISI.

I'm just wondering as we look at the magnitude of the rate actions that you think you're going to be able to recover over the next several years associated with the increase in nuclear spending, how we think about the prudence of those -- that spend and the recovery. Can you explain to us what you're benchmarking looks like in terms of your current spending on those plants, and what the increase in spend then where that puts you relative to other nuclear operations across the country, and how you are going to show that those recoveries are necessary and prudent for customers as opposed to being a function of some level of mismanagement historically that should be borne by the shareholder?

Greg, that's a good question because as you know, customer bills, customer rates is an extremely important factor in our business. It's something that we've spent a lot of time trying to maintain. As you know, we already have some of the lowest rates in the country, 20% to 25% below the national average.

And as far as the expenditures go, if they weren't prudent expenditures to make we wouldn't make them. Between our mitigation actions as well as other items that are rolling off, like the securitizations that I mentioned in Mississippi, $55 million in 2018, we have roughly $1 billion securitization bonds rolling out of the Louisiana jurisdiction.

And that and utilizing our normal regulatory processes, we do believe that all the prudently incurred expenditures will be recovered. Also keep in mind here that when we look at the jurisdictions that are most impacted by the nuclear spend, namely obviously Arkansas and Louisiana where the plants reside, you put everything together not just the spend that we've got that's addition here, but everything.

And over the period that we're talking about, we wouldn't expect customer rates to increase by much more than 1%, including everything. So far less than the rate of inflation annually. The impact here, we're trying to manage as much as we can. All of the expenditures will be prudently incurred.

We're putting all of our operations in line with what the industry is. As you know, every plant in the country is different. But that's certainly something that we've kept in mind.

We've outlined this plan in terms of amount, in terms of timing, in terms of what we need to do to balance the equation not only for the operational side of things but for our customers. And again we would envision we would come out the back side of this by the time we get to 2019 with still having some of the most competitive rates in the country.

One follow up, as I look at the numbers and rough math at this point for EWC net of the reduction and EBITDA as a function of the increase of operating costs, but also the increased CapEx, am I right that it looks like you're actually cash flow negative over the next several years at EWC, or are there some -- is there some mitigation happening here that will allow you to maintain at least a neutral value proposition there as you unwind that business?

Greg, this is Drew. We haven't ever discussed specifically, but you can do the math like we can. And so as Leo mentioned in his remarks we continue to remain vigilant and disciplined on our approach to reducing the footprint in that business. I think that you could count on us to continue to maintain that posture.

But to the extent that the business is cash flow negative, how would you fund that?

To the extent that it is in any given period, it's going to be mostly from the parent. As you look at this overall forecast, including the changes at EWC, the incremental investment at the utility, we have a parent debt level that could go up about 150 basis points from where we were originally targeting it, which is slightly above our target range.

Our target range is 18% to 20%, and we were talking about a forecast that got us around the neighborhood of 21% that we were working on. Obviously this adds, as I said, maybe another 150 basis points to that.

And so that's not going in the right direction, and that's if we financed everything with parent debt. And so we're thinking about other options around how do we manage it starting with the business itself, and can we continue to find ways to be more efficient.

Thank you.

Jonathan Arnold, Deutsche Bank.

Again on the mitigating rate actions that Greg's asking about. Can you give us a little bit of a sense of where the trajectory there is coming from, which jurisdictions, which kinds of -- which is formula, which will be actually rate cases, just so we can get a sense of what we should be tracking to see that offset come in?

I will start and then Theo can follow up, Greg, or Jonathan, sorry about that. We're not planning on using any special regulatory mechanisms at this point in time. Everything would just flow through the normal mechanisms.

So for example Arkansas would flow through the FRP, Louisiana would flow through the FRP in the near term but we do have some reset capability by the time we get out to 2019. Those are the major implications in terms of where the plants reside.

And again, from a -- you asked about the trajectory and if you look at the plan as we've laid it out now, not just that's been but everything together in those jurisdictions, we're talking about a trajectory of about -- that we wouldn't expect to be more than 1% a year from a rate standpoint. Remember it's not only our mitigating actions that Drew outlined that are on the slides in your deck, things like the securitizations rolling off the load growth that we have, the continuation of the investments that we're making.

As I outlined all those investments related to the new power plants, et cetera, we envision that those are going to provide production cost benefits as they're more efficient, et cetera. All that works together to keep that trajectory still in line with one of the best in the industry. Theo, if you want to add to that.

Jonathan, this is Theo. Just a couple of other points. The other plant clearly where we're making investment is Grand Gulf which is owned by SERI. You have a life unit PPA back to fully operating companies, that plant is subject to FERC formula rates, cost of service base rates.

Also in Louisiana, just additional clarification, we've got an opportunity for FRP reset in the 2018 timeframe, and we would expect that reset to occur. It's just that rate change is what happened within the 2018 calendar year. So you'd see a full impact of that in 2019.

Also in Arkansas the forward-looking test, your FRP with the forward-looking features, also has a true-up mechanism associated with it. So if in fact our forecasted test year is different than actuals, we have the opportunity to come back and implement rate changes to true that up to the actual cost within the context of that particular test year.

Great. Thank you. May I just ask on the mitigation expense line where you have it at $0.25 already in 2017, and then holding more or less at that level through the period. How much of that have you already identified and/or implemented?

This is Drew. Pretty much all of it we've already identified and implemented. A lot of it -- $0.10 of the $0.25 in 2017 would be associated with interest expense, and so that all the financings that we've done this year would contribute to that. And then after that the other $0.15 are various elements from the long laundry list of things that I read off that have already been put into place.

Great. Thank you. You made some comments about dividend growth and talked about giving us more of an update at EEI. Last year I think you had a dividend increase right at the end of October.

You're coming up to the -- can you give us some thoughts about how does this dampening of the trajectory in the short term feed into your thinking around dividend? And this obviously seems to be the timing of the year where you last raised it.

That's another good question, Jonathan. Obviously the dividend is a Board of Directors decision that they'll make in due course. You're right on timing. Traditionally the fall is when we make that determination.

As far as what this has done to our trajectory, again the earnings trajectory here through 2019 is pretty similar to where we were before. It's the same number by 2019. We still see growth in 2017 and 2018.

So while obviously it's a consideration through our mitigating actions, the rate levels that we have, the regulatory constructs that we have, and the work of a lot of really talented people here at Entergy, we still see the growth outlook that we've been on for that utility, parent, and other earnings that supports the dividend growth. So our objective to continue to grow the dividend is still out there.

It's still something that we take very seriously. Steady, predictable growth in earnings and the dividend, that's our objective.

Stephen Byrd, Morgan Stanley.

I wanted to focus on slide 10 and the revised retail sales growth. Could you just lay out what your revised growth rate is and what the sensitivity is? You have an appendix slide that shows the sensitivity nearer term to the 1% change. I just wanted to confirm sensitivity to change as in low growth assumptions in the out years.

This is Drew. So you're referencing the slide in the back. Was there anything in particular, Stephen, that you wanted to discuss on that sensitivity slide? I think that's slide 42.

On slide 10 what's the revised retail sales growth percentage for residential and commercial? And what would a 1% movement in that assumption do? I think the appendix would imply $0.11 for commercial and residential combined. I just wanted to confirm that.

I think that's still fairly correct, Stephen. Through three quarters of this year we're down about six-tenths of 1% versus a 1% or so, just below 1% expectation for this year.

And so we have a different starting point going into next year than what we were anticipating. That's the first thing, and then the second thing is the growth rate going forward. And we brought that down, as I mentioned in my remarks, but I think it will probably closer to about 0.5% rather than almost 1%.

Okay. Understood. Shifting gears to the sale of nuclear assets to Exelon. I know there were several conditions that were listed in the release in terms of approval by federal and state agencies.

There was recently a lawsuit filed in court opposing the credits provided in New York. In the event that in court the credits were overturned, what would be the impact to the sale of those assets?

Stephen, it really depends on the timing of the court action. So our point of view is that the ZEC is unique in that it places a value on the carbon-free attribute of the units. So we feel pretty strongly that we will survive that legal challenge.

But it really would depend at what point in the transaction that occurred. So right now we're anticipating approval by the PSC November 17. Approval of the NYSERDA contract is November 23, then NRC approvals to follow and closing of the transaction in the second quarter of next year.

Okay, and if the ZECs were overturned before second quarter of next year, would that trigger a cancellation of the transaction?

It certainly could be a consideration there, and then it really depends on what -- who's taking responsibility for that. And so the contract has some commercial terms which deal with that specific issue. It really becomes more of an issue of can you close and who has liability for the investments and the refueling, et cetera.

Thank you.

Michael Lapides, Goldman Sachs.

A couple of easy ones. First, does your utility, parent, and other guidance incorporate any external equity or equity like security issuances over the next few years?

This is Drew. Michael, it does not incorporate anything like that.

Got it. Second, on the EWC side when you look at Palisades and Indian Point and the guidance of increased costs, how do these plants look from a cost structure relative to what you would consider their benchmark peers?

This is Chris Bakken. The Indian Point cost structure is reflective of the market it operates in, which is a high labor cost. But the plant spending we believe is appropriate for the remaining life of the plant. In terms of Palisades, I would say it's consistent with the industry, and again, we're making prudent investment in the plants given the remaining life cycle of the plant.

Got it. Last thing, back to the regulated type, can you put some numbers around the size and scale of the AMI program filings in Arkansas and New Orleans? And how should we think about what size and scale through 2019 or 2020 or so you anticipate in some of the other jurisdictions?

Michael, this is Theo. I don't have the specific numbers in front of me in terms of Arkansas versus New Orleans. I know when we've talked about this initially we talked about on a system basis the investment being $900 million or so when you think about it as it relates to the entire system.

In terms of timing, as you can see as you go through the filings you will see that there was some cost we're asking to defer that will get really incurred prior to the full functionality of the meters themselves. And we believe that's consistent with the matching of that cost with the benefits that you'll see that will get implemented as a result of the implementation of the meters themselves.

There's also I think, as you recognize, that Drew mentioned some asset investments that is made in advance of meter deployment basically to develop the backbone to support the meter deployment. And our view is that asset investment is consistent with what we've seen from a timing perspective, and the necessity to get it in place in order to allow the efficient use of the meters themselves once they are fully deployed and to recognize the full benefits of it.

We also believe that infrastructure is useful for other systems as well. I think our perspective is the cost of the past is consistent with what we've seen with implementations across the country, and would be supported and supportive of the benefits that Leo mentioned as we think about the implementation overall. I would have to get specificity for you in terms of years, but we don't view that investment to be significant investment at risk in advance of the meter deployment.

Thank you. Much appreciated.

In the forecast period there's the $900 million that Theo was discussing, it's a couple hundred million in the forecast period. Most of it is beyond 2019 when the significant portion of the meter deployment really kicks in.

Thank you, Drew. Much appreciated.

Praful Mehta, Citigroup.

First question is more strategic which is there seems to be a lot of defense right now, which is both on EWC where the focus is just to reduce the strength of ties, and even on the utility side it seems like retail sales growth isn't coming out where you expected. So I'm trying to figure out from an offense perspective or future growth how are you looking at what are the dimensions that you can push and grow going forward coming out from the defensive view right now?

We don't view ourselves in a defensive view at all, Praful. We are on offense here. We had a significant amount of investment that I outlined. It goes into the generation and transmission footprint of our regulated utility: that has not changed.

And we continued to make those modernizing investments that with lower production cost provide significant benefits to our customers, improve the reliability, reduce our environmental footprint, and meet which is a continuing to grow service territory, particularly as it relates to what we see on the industrial side. All while we maintain some of the lowest rates in the country.

In addition to that, what we just -- in response to the question from Michael around AMI. AMI is the first step and we've just now started to make the regulatory filings, but first we'll get the back office and the backbone of the system to make it smart. We don't want to deploy the meters until they will actually have something to do for us.

So we're putting all that in place in advance of actually beginning to deploy the meters in 2019. There are other technologies that we will deploy on the system then that we're looking at today in terms of asset management technologies and other things that will go from that point and forward, it will provide even greater benefits, savings, helping us to manage load for our customers and provide that needed investment that will provide us an earnings opportunity, but at the same point in time it will help us help customers manage their bills through the ability to manage how much they use, when they use it, et cetera.

So that for us is again, total offense and extremely exciting for us as we look to the future. When we look at EWC, our objective has not changed. It's always been to separate that business from the utility, and we continue to execute on that.

We sold the wind assets, or are in the process of selling those. We sold the rise plant last year. We made the decisions, unfortunate as they are to shut down Pilgrim, to shut down Vermont Yankee.

And we're going to continue on that path, albeit with a different price deck that we see continues to erode, but we're still working as diligently as we can. And I think the proof of that is in our discipline around first making the decision at FitzPatrick to cease operations there, but at the same time never giving up and never wavering from the idea that we might come up with something better that resulted in the creation of the ZECs, the working with Exelon and the state to come up with the sale of that plant, the continuation of its economic benefit and its reliability benefits in the state of New York and certainly to our employees in the community.

That for us isn't defense at all. It's all offense. Like everyone else, we're in the merchant market and gas prices have been low, particularly in the northeast. We've got to manage around that, but it doesn't change what we're doing or how hard we're working, or what we think we can accomplish there.

We've accomplished a lot. We would anticipate over the course of the next couple years we will continue to accomplish a lot. So all that said, we're pretty excited about what we have the opportunity to accomplish here.

And again, just going through all that we just talked about with the sustainability of the nuclear fleet, the investment in AMI, the investment in the generation business, the investment in transmission, going through the normal regulatory constructs that we have today and still maintaining our 2019 outlook. Sounds like offense to me.

But strategically that's where we're headed. The same place we were headed before, and we just updated some of the information for you, that's all.

Fair enough, Leo. Thank you. On slide 16 a more detailed question. With increased CapEx around EWC, you also make the point of about the remaining useful life or consider the remaining useful life of assets.

I'm trying to understand how you're thinking about remaining useful life for both Indian Point and Palisades. Is there any change in view? Obviously I understand relicensing, but apart from that is there any change in view around that, given the CapEx spend?

There is not a change in view around that, Praful, other than what we always do is we continue to evaluate those facilities. But right now there is no change in point of view around those plants. Palisades, we've got the contract through 2022. And then we've got the ability to see where we think the MISO market goes at that point in time.

And Indian Point continues to be a very, very valuable asset. I think the ISO just came out with their study showing that it was required for reliability in the region, so it continues to be needed in that region.

So there's really no change in outlook for those assets at this point. That said, we continue to be disciplined in how we look at these on a regular basis, and we'll look at them -- we're always refining our point of view about them. That's all.

Fair enough. Thank you, Leo.

Thank you, Praful.

Brian Chin, Bank of America.

I wanted to go back to an earlier question about the court challenge to the zero emissions credits proposal. If that challenge is successful and the court overturns, I think you made reference to its possible under certain conditions that it might impact the sale.

Did you mean that to say that those conditions are spelled out and there's one party who might be at fault at that? Can you just give a little bit more clarity on what exactly you meant?

It's difficult to predict what the impacts of it could be without understanding what the specific ruling is, but we have put terms in the commercial agreement that try to separate those risk. But I really can't tell you what the eventual outcome of that would be.

Typically we don't discuss litigation, especially future litigation. But we have tried to address and mitigate those risk in our sale agreement with Exelon.

Got it.

Brian, one thing that I will add too is the way we're working through this process, we're going down the parallel path. We're confident that we'll close the transaction that will get to the endgame. But certainly the way it's structured, worst case for us we get back to the position we were in before hand, and that is we have to make the decision to shut down the plant around the same time we were planning on it.

Appreciate it. Thanks a lot, that's all I got.

Steve Fleishman, Wolfe.

Kind of a simple question. Could you just be clear what is not working right in the nuclear program right now that you're spending so much money?

First and foremost, the plants are safe, Steve, or we wouldn't run them. I would say that the challenges that we face stem from a desire to run a lean operation, and that lean operation to benefit our customers and get the right balance between operational excellence and the cost structure.

What we've found obviously we've had a couple of situations with plants going into Column 4. What we found is that we potentially didn't get the balances right as we want.

So to get ourselves up to the standards that we hold ourselves to and to the standards of the industry, we've got to change our strategy around how we operate the plants. As you know, we made organizational changes last year. It was six months ago that we brought Chris in, and Chris has been responsible for developing what that strategy is.

We've changed not only who it is but where it reports, whereas it used to report into the COO it now reports in directly to me. And so Chris and his team, along with his discussions with people in the industry and with regulators, et cetera have devised this change in strategy to get ourselves up to where we need to be to meet our own standards and the operational excellence standards of the industry.

Will there be some filing at the NRC that goes through the full plan, or is it going to be plant by plant?

There's no filing. The only filings will be when we include these in our retail regulatory -- these costs, just like the costs of the new CCGTs and CTs and AMI. These plants are vital to the reliability of the system.

They provide over 30% of the energy used on our system. They are a large, base load, zero emitting resource that very valuable. They are anchors to the community in terms of tax base and jobs and community support. So these are very vital assets.

They limit fuel volatility when you look at what could and has happened in the natural gas markets and the reliance on natural gas of us and others. So they are very, very vital, they fit right in with the strategy that we've got everywhere else, whether it's investing in CCGTs that reduce production costs and improve air emissions, or whether it's looking at something in the gas and ground investment that would limit fuel volatility.

So these assets fit right into our strategy, right into the need for our communities, our customers. And we just again, have to change the strategy from that lean operations into one more focused a little bit more on operational excellence side of it. And then we'll get right back on track.

And, again, as I mentioned earlier, we're not going to use any special regulatory mechanisms and no special filings at the NRC. It's just us working through this process and getting it right.

And is this spending -- part of that it sounds like higher ongoing spending. Part of this next three years, is there a way to split it out between spending to fix the program where you want it to be versus spending that's just ongoing higher levels? Or is it all ongoing higher levels?

The way to look at it, and obviously you've got to remember too, Steve, capital dollars are lumpy in these big plants and things like that. The way we're looking at is what does it take to run these plants?

And Chris' task has been to put together a plan of what does it take to run the plants on an all-in basis. And so we're doing that. Certainly getting ourselves out of Column 4 and things like that are going to be important.

Those are costs that will go away, but for the most part all that we've tasked them to do was come up with the O&M and capital plan required to put us in the operational excellence category that we want to be. And this is it, and we've included it all in the plan.

We were going to use the regular regulatory mechanisms to recover it, and as we mentioned earlier between our mitigating actions, between other things that are happening in the Company like the securitization roll offs through load growth that we have and investments that we're making that lower costs, the impact on our customers is going to be minimized as much as it can.

One last thing. Grand Gulf, can you just talk about what the outage is related to?

This is Chris again. First and foremost I want to stress that Grand Gulf was and is safe to operate. However, reflecting on some of our equipment and human performance over the last several months that didn't meet our standards of excellence, we've taken a decision to take the unit out of service, systematically understand that performance shortfalls to excellence.

We have training programs and some maintenance plans to correct that. It is well understood and we're in the process now of working through those issues and expect to have the unit back in service early part of next year.

Thank you.

That concludes today's question-and-answer session. I would like to turn the call back to Mr. Borde for closing remarks.

Thank you, Liz, and thank you all for participating this morning. Before we close, we remind you to refer to our release and website for Safe Harbor and Regulations G compliance statements.

Our quarterly report on form 10-Q is due to the SEC on November 9 and provides more detail and disclosures about financial statements. Please note that events that occur prior to the date of our 10-Q filing that provide additional evidence of conditions that existed at the date of the balance sheet would be reflected in our financial statements in accordance with Generally Accepted Accounting Principles.

The call was recorded and can be accessed on our website or by dialing 855-859-2056, confirmation ID 85417477. And the telephone replay will be available until November 1. This concludes our call. Thank you all very much.

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