Ladies and gentlemen, thank you for standing by, and welcome to the Entergy Fourth Quarter 2020 Earnings Release and Teleconference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I'd now like to hand the call over to David Borde, Vice President of Investor Relations. Please go ahead.

Thank you. Good morning and thank you for joining us. We will begin today with comments from Entergy's Chairman and CEO, Leo Denault; and then Drew Marsh, our CFO, will review results. In an effort to accommodate everyone who has questions. We requested each person ask no more than one question and one follow up. In today's call, management will make certain forward-looking statements. Actual results could differ materially from these forward-looking statements due to a number of factors, which are set forth in our earnings release, our slide presentation and our 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 on the Investor Relations section of our website. And now, I will turn the call over to Leo.

Thank you, David, and good morning, everyone. Before I turn to my remarks, I would like to give you an update on the winter storms we experienced last week. Severe weather conditions affected most of the country including our service area. In order to balance the system, MISO directed us to conduct rolling power outages. Our system is back to normal operations. Our thoughts are with all of our customers and communities who were impacted by the weather. Our employees once again demonstrated their dedication by working around the clock in difficult conditions to quickly restore service where needed. As always, I am grateful and humbled by their commitment. We're still working through our numbers, but our preliminary assessment of the cost is approximately $125 million to $140 million associated with mobilizing crews and restoring power and approximately $400 million of incremental fuel costs. We have fuel recovery mechanisms in all of our jurisdictions and we will work with our regulators to recover these costs in a manner that mitigates the impact on customer bills. I will now turn to our discussion on 2020. Today, we are reporting strong results for another successful year. Our adjusted earnings per share are $5.66. That's in the top half of our guidance range. We achieved these results by overcoming revenue challenges with our flexible spending program. We just set a goal to reduce 2020 costs by $100 million. And we exceeded that target by approximately 50%. Underlying our strong performance was the foundation that we have built over the last several years; we've become a resilient organization prepared to create sustainable value for all our stakeholders, even in extraordinary times. It's what our stakeholders expect from us and that's what it takes to be the premier utility. Challenges are a natural part of doing business. No company is immune and Entergy is no exception. As 2020 prove the test of sustainability is less about challenges, and more about how we are able to achieve our goals regardless of the circumstances. Because of this solid foundation and our proven track record, we are confident in our continued success in 2021 and beyond. As such, we are initiating 2021 guidance and affirming our longer-term outlook. All in line with what we shared an Analyst Day last September. In 2020, we brought online four large generation resources that are cleaner and more efficient than our older assets, providing customer savings and environmental benefits that will help us meet our sustainability commitments. These assets also give us dispatch flexibility that is important for system reliability. Renewable Energy is also a key part of our strategy to achieve our sustainability goals. Our clean energy efforts have escalated over the past few years. We now have more than 500 megawatts of renewable resources in operation. These resources come in many forms small and large, owned and contracted. And some are innovative solutions like the New Orleans residential rooftop project, where we own the solar systems that are installed at low income customers' homes. Those customers get a fixed bill credit on their bill, providing economic benefits to those who need it and renewable energy for all customers. We have approximately 450 megawatts of solar projects currently being installed. We have another 880 megawatts of solar resources either in regulatory review, or RFPs. We plan to solicit another 800 megawatts of solar this year. This is only the beginning. And we will continue to grow the number of renewable energy facilities across our region. Almost half of our capital was for distribution and utility support investments that are closest to the customer experience. A portion of these costs is for our advanced meter project. We have now completed the installation of 70% of the 3 million advanced meters we are deploying across our service area. This is an exciting milestone as we enter the final phase of our three-year journey. Advanced meters help our customers better manage their energy usage and bills, and it lays the foundation for new technological capabilities over time. With billions of real time data points available, we'll be able to gain new insights that will drive fundamental change in the way we serve our customers while consuming the least amount of energy resources. We invested $800 million in our transmission infrastructure, excluding storms, our transmission investments benefit our system and our customers, as they reduce congestion, strengthen service reliability, enhanced system efficiency and resiliency, and support economic development in our jurisdictions by enabling service to new customers. We completed several important projects, some of which proved critical during the active storm season. These new structures built to modern standards, which stood the record winds from Hurricane Laura, and were critical to restoring power following that storm. These projects are all part of our plan to improve the resiliency of our infrastructure, and provide a higher level of service to our customers. In 2020, we continue to work collaboratively with our regulators for the benefit of customers. In the face of difficult times due to COVID-19, we collaborated to find solutions. Early on, we suspended disconnects and work to set up payment plans for customers who couldn't pay their bills. In all our jurisdictions, we received accounting orders, deferred costs associated with COVID-19, including bad debt expense from accounts that we don't expect to collect as a result of the pandemic. We also work with our commissions on rate recovery mechanisms that give us the opportunity to recover costs that are benefiting our customers. Public Utility Commission of Texas finalized the new generation rider, which provides for full and timely recovery of capital costs associated with new generation, where timely recovery helps us create value for our stakeholders in Texas and ensures that the communities, we serve remain economically competitive. The Texas Commission approved the use of this rider earlier this year for recovery of Montgomery County power station. The city council of New Orleans approved a unanimous settlement that resolved Entergy New Orleans rate case and FRP filing, we will make the first of three annual FRP filings later this year. We also had annual FRP rate actions and Arkansas, Louisiana and Mississippi. We plan to submit filings in Louisiana and Texas in the first quarter of this year and in New Orleans in the second quarter to request recovery of 2020 storm costs. As we have done in the past, we will seek to securitize these costs. With current low interest rates, this will result in significantly lower cost to customers as compared to typical recovery. Louisiana's and Arkansas FRPs expire with the 2020 filings. And we've requested renewal both. Discussions are ongoing and we will provide updates as we get them. In spite of the positive outcomes in 2020, the Arkansas Commission's order for our 2021 FRP rate change fell short of our expectations. We believe the order incorrectly applies the law and results in an unreasonable outcome. We requested a rehearing on the Commission's order, and we expect to receive their decision on our request and the FRP extension by March 15. You should note that our guidance and outlooks today reflect the Commission's December order, and extension of the FRP. Our leadership and sustainability and environmental stewardship have been a long-standing hallmark of who we are, and are led to measurable, undeniable results. For the past two decades, our emissions rate has been well below the sector average, our utility co2 emissions rate has decreased nearly 40% since 2000. And today, we operate one of the cleanest, large scale power generation fleets in the nation. Our fleet is one of the cleanest, as we have not only set meaningful reduction targets, but we continue to exceed them. The most recent example is our environment 2020 goal, where we committed to maintain carbon dioxide emissions through 2020 at 20% below year 2000 levels. Our actual 2020 emissions were 27% below 2000 levels, beating our reduction goal by 33%. Looking ahead, our business plan supports our 2030 commitment to reduce our utility carbon emissions rate by 50% below year 2000 levels. Achieving this objective calls for continued transformation of our portfolio. To that end by 2030, we anticipate that our generation portfolio will include at least five gigawatts of renewables with potential for more. During that timeframe, we also plan to deactivate approximately four gigawatts of legacy gas along with the remainder of our coal assets. Going forward, we will not build any large scale generation that isn't hydrogen capable. As we transform our portfolio, we will work with our regulators to do so within a framework that balances reliability, affordability and environmental stewardship, while enriching the economies of the communities we serve. To support our longer-term net zero goal, we're exploring emerging technologies through a partnership with Mitsubishi power, we will develop innovative solutions that include large scale battery storage, carbon capture and sequestration, and hydrogen-based strategies. While we are not relying on hydrogen to meet our 2030 commitment, we believe it will be a part of creating a carbon free future. Hydrogen is an important technology that will allow utilities to adopt much greater levels of renewables to meet growing sustainability needs. Hydrogen storage, transportation, and utilization attributes will allow us to leverage today's pipeline and generation technologies in a manner that supports a highly reliable and fuel diverse electric grid. In the Gulf South, we have a distinct locational advantage. And we are uniquely positioned given the existing hydrogen infrastructure in Texas and Louisiana. Existing infrastructure today in our service territory includes more than 3.5 billion cubic feet of hydrogen capacity, two of the three hydrogen salt caverns operating in the United States, and more than 1,100 miles of hydrogen pipelines, which is 60% of the United States infrastructure. In addition, two of the largest hydrogen producers in the world are our customers. We also have more than 860 miles of co2 pipelines in our service area, which would facilitate carbon capture and sequestration. These are just a few of the advantages for our service area, which presents us with unique opportunities. To advance our work on hydrogen we were working on a few projects but I'd like to share. Orange County Power Station was selected in Entergy Texas's request for proposals, that facility will have the capability upon commercial operation to utilize up to 30% hydrogen. Longer term, the turbines can be configured to operate on up to 100% hydrogen at modest incremental cost. The facility is conveniently located near existing hydrogen pipeline infrastructure that can be connected to the plant to utilize hydrogen when feasible and economic. We own a storage facility with three caverns; we are evaluating converting one of these caverns to hydrogen. We are taking advantage of the existing hydrogen pipeline infrastructure in the Texas industrial corridor near the Orange County Power Station. And we are developing a four phase plan to support access to hydrogen fuel across our fleet of hydrogen capable plants. We are also in the very early stages of developing a green hydrogen demonstration plan, Montgomery County Hydrogen Innovation Center. This project will teach us important lessons about electrolysis operations, and ultimately lay the groundwork for future full-scale projects. We're excited about these projects and our collaboration with Mitsubishi. As we lead our industry to make hydrogen a reality that will create green jobs in the Gulf South region. We will provide updates on these initiatives as we have new developments. Being the premier utility means doing our part to create a more sustainable future for our customers, our communities and the world. A goal we continuously strive for in everything we do. In 2020, we are once again named to the Dow Jones Sustainability North American index. We are the only electric utility received this honor 19 years in a row. We are very proud of this recognition as DJSI is one of the most respected independent sustainability measures in the world. We earned perfect scores in the areas of climate strategy, water related risks, materiality, environmental reporting, social reporting and policy influence. This past year, our employees demonstrated once again, why Entergy is best in class in storm response. During a storm season unlike any other in our history, our commitment to health, safety and preparedness is one of our proudest achievements. Our teams worked around the clock to safely restore service, to rebuild infrastructure and to help our communities recover while following virus prevention protocols. For our employees' extraordinary efforts, we received broad support from local, state and federal officials. We also received five emergency response awards from EI. This marks the 23rd consecutive year EI has recognized Entergy employees for their emergency response. 2020 was another successful year for our company. Everything we accomplished gives me confidence in our ability to meet our goals and commitments going forward. We've proven that we are resilient company prepared to respond to adversity and deliver on our mission to create sustainable value for our stakeholders. It's what our stakeholders expect from us and that's what it takes to be the premier utility. Despite obstacles imposed by the pandemic, mild weather and storms, our employees found ways to connect innovate, drive growth, and build toward the future, all while meeting our financial commitments. The fundamentals of our company are strong and the drivers that uniquely positioned us to be the premier utility remain firmly in place. We consistently meet or exceed our guidance expectations. We have line of sight on 5% to 7% adjusted EPS growth. And by the end of the year, we expect the same for our dividend growth rate subject to board approval. And as we mature in our continuous improvement efforts, we aspire to permanently reduce O&M costs and redeploy those resources for the benefit of our stakeholders. I am as excited as ever about our future. I will now turn the call over to Drew to review our financial performance.

Thank you, Leo. Good morning, everyone. Today we are reporting strong results for 2020. As Leo mentioned, we successfully managed lower revenues by lowering our O&M expense by approximately $150 million, which exceeded our $100 million cost reduction target for the year. Our results today are a validation of a strong resilient company we are. As a result, we are confident in our continued success going forward and are initiating our guidance and affirming our longer-term outlook. I'll begin with a review of results for the full year and then provide an overview of guidance for 2021. Starting on slide 6, Entergy adjusted EPS for 2020 was $5.66, $0.26 higher than 2019 and the top half of our guidance range. Moving to slide 7, there were many drivers that are straightforward and laid out in the release. The key area focus for us in 2020 with O&M. We offset the negative impacts of storms, COVID-19 and unfavorable weather with approximately $150 million of cost reductions. And to do this, we identified a number of cost cutting measures early in the year and deliberately executed on our plan. Slide 8 lists some of the actions taken. We are proud of what we've accomplished yet we are not surprised. Our employees have built the culture, processes and resources to successfully deliver on our commitments to all of our stakeholders, even during extraordinary times. And that's been important this year more than ever. Our results further strengthen our competence in our success going forward as we affirm our earnings expectations from 2021 through 2023. Results for EWC summarized on slide 9 are generally in line with our expectations and we continue to make good progress on our exit of that business. Full year operating cash flow shown on slide 10, was approximately $2.7 billion. As you would expect, storm costs were a large driver, as were lower collections due to COVID-19. Decreased collections for fuel and purchase power costs and unfavorable weather also affected the metric. Lower unprotected, excess ADIT returned to customers partly offset the decrease. Our cash and credit metrics as of the end of the year are shown on slide 11. Our parent debt to total debt is 21.6%. And our FFO to debt is 10.3%. As we mentioned last quarter, our FFO to debt is temporarily lower in part due to the financial impacts from the storms. We expect the metric to return to target levels as we receive storm securitization proceeds next year. As we have strong precedents for storm cost recovery. We plan to submit initial filings over the next few weeks. We'll also pursue off balance sheet treatment in Louisiana and Texas. We remain committed to maintain our best investment grade profile and a supporting credit targets including at or above 15% for FFO to debt next year, and below 25% for parent debt to total debt. Moving to slide 12; with the resiliency we've demonstrated in 2020, we are confident in our continued success in 2021 and beyond. Our 2021 adjusted EPS guidance range is $5.80 to $6.10. And our current plan puts us firmly at the $5.95 midpoint. This and our 2022 and 2023 outlook ranges remain the same as the outlook we presented at Analysts Day. We continue to target a 5% to 7% annual growth rate for adjusted earnings per share. We also expect to grow our dividend commensurate with our EPS growth rate starting in the fourth quarter of this year, subject to final Board approval. On slide 13. Going backwards, we've outlined a few of the key drivers for 2021 earnings growth. We also include more detailed assumptions in the appendix of a webcast presentation, beginning with the top line a full year of 2020 rate activity following significant investments to benefit customers will contribute to 2021 growth. We will also make annual FRP filings during the year. We project utility O&M a little under $2.7 billion in line with our disclosures from Analysts Day. Depreciation expense is expected to increase and net interest is expected to decrease due to lower AFUDC as new plants came online in 2020. We also anticipate that our effective income tax rate will be higher. Our guidance and outlooks reflect the December APSC order in Arkansas, and assume an FRP extension in both Arkansas and Louisiana. In Arkansas, we are reprioritizing our O&M and capital investments to more closely align with the ordered recovery structure. To the extent the order is reversed, we will plan to readjust our O&M capital to deliver the customer benefits that those investments would produce. While we continue to monitor risks, we have already identified flexible spending levers in the event needed. We're also exploring permanent upside opportunities through solar investments and further continuous improvement. As Leo mentioned, 2020 with a strong year for our company, we exceeded our $100 million cost reduction target and delivered on our commitments to each of our four key stakeholders in the midst of unprecedented times. Looking ahead, the fundamentals that underlie our steady predictable growth are strong. Our guidance and outlooks remain the same as we presented at Analysts Day and provide clear line of sight to the 5% to 7% adjusted EPS growth rate. We have among the lowest retail rates in the country. And our solid strategic operational and financial plans will upgrade the service level that we provide to our customers. Our proven and disciplined flexible spending program helps us adapt to financial headwinds or tailwinds so we can meet our financial commitments. And in the fourth quarter of this year, we expect to grow our dividend commensurate with our 5% to 7% EPS growth rate. We have significant opportunities ahead and we are well positioned to be the premier utility. Before turning the call over to Q&A, I want to take a moment to acknowledge and thank David Borde for his great work as Vice President of Investor Relations. He built solid relationships with all of you. And the good news is he will not go far. He will work with Rod to help bring our vision of the future utility to life. And for the next few weeks, he will reach out to many of you to introduce Bill Abler, who is taking over leadership of the Investor Relations team. Bill has a strong commercial background in both commodities and utilities. And he will be an excellent representative for us with you. And as, both Dave and Bill are backed by a very strong team with discipline processes. So you should not expect any change in the level of service you will see from up there. And now, the Entergy team is available to answer questions.

[Operator Instructions] Our first question comes from Jeremy Tonet with JPMorgan.

Hi, guys, it's actually Ryan on Jeremy. Just wanted to kind of start off with kind of the order in Arkansas and you guys were very clear about reaffirming the guidance and potential offsets with capital and O&M. And I just wanted to kind of dig a little bit more of what some of those offsets you are thinking about Arkansas to kind of offset this potential negative order. And then if you kind of get a positive kind of outcome on the rehearing should we be thinking about maybe top end into the range for 2021.

This is Drew. I'll take that. And then Rod can provide any other framework elements as needed. But so we are adjusting, as I mentioned in my comments, we are adjusting our O&M and capital to prepare for or respond to, I guess, the order that we got to December, and you can see that in some of our capital disclosures. There is some other just normal pining capital moving around and some of the jurisdictions, but the main thing is in Arkansas, that's the primary thing that we are taking action to adjust with. In terms of potential upside, as I also said in my remarks to the extent that we were able to get the order reversed, we would anticipate putting most if not all depends on what the order would say, back into our capital plan, so that our customers can benefit from the capital and O&M that we are planning to deploy in Arkansas. So that's what's going on there.

Okay, that makes sense. And then just as a follow up, I mean, obviously, the stock price has kind of been at depressive levels recently, just wondering if you kind of have any thoughts on what's kind of required to kind of get the stock moving or kind of reassure market confidence. And then if kind of stays at depressed level that you'd think about any type of transaction deep maybe sell down in some of these utilities to maybe offset some of the equity needs going forward?

Well, I'll start, and I'll let Drew talk about the last part of that, Ryan, but the best thing we can do is continue as we have over the last several years to continue to execute to meet our commitments to our customers, and to meet our commitments to all of you, which just means being disciplined about our capital, and O&M spend about where it is and what level it is, continue to improve the level of service that our customers receive from us, and continue to hit or exceed the numbers that we committed to all of you. And that's what we intend to do.

And then I'll just talk about M&A and sales and possible portions of utilities certainly, of course, we're always open to anything that would be value creating for our stakeholders, which is always our number one rule in M&A anyway, is to, we would want to make sure that we're creating value for our stakeholders. Other considerations are execution and distraction from the things that we are doing to further create value for stakeholders already under way. The second one is probably the one that makes it perhaps a little bit challenging for us in the sense of trying to do that for equity raises because we would likely require approval from regulatory Commission's in order to do any sort of M&A activity at the APCO and so while we might be able to find good value, if you're - if we were counting on that for an equity raise, and we had to go through the regulatory process that would create a lot of uncertainty in that equity, right. So probably not the best path for us but certainly if there is value creation opportunity out there, then we would be looking at it.

Our next question comes from Stephen Byrd with Morgan Stanley.

Hey, good morning. Just wanted to I guess, step back and talk about the impacts to the system from just really unprecedented weather impact that you all noted, as you think about sort of lessons learned from Texas, and just from your other utility businesses, I know you're spending a lot on sort of making your system more resilient. But are the lessons learned sort of resulting in potential for further, either acceleration of spending or changes to plans? Whether it is generation plans, renewables plans, et cetera? Or is this just sort of consistent with your overall focus on resiliency and these recent data points, just kind of reaffirm sort of the existing approach that you're taking?

Well, I guess, I'll start out and let others chime in. But, Stephen, certainly every event that occurs has unique attributes that allow us to have lessons that we learn. And so whether it's the Hurricanes or tropical storms Harvey is different than Laura, for example, in terms of what the impact it had on reasonably similar areas of our service territory. And what we've experienced, obviously, we're still in the process of getting the lessons learned about the events that we saw last week. So we always, I wouldn't say that it's inconsistent with the plans we have for resiliency. But certainly every time we go through any kind of event, we will learn something that we will apply to the next events. So there are things we learned in Katrina that have really served as well, for every event that occurred after that, both in terms of what we do to our system, and how our capital shapes up, but also as well as our processes and our operations and our interactions with the industry, et cetera. So there will be lessons learned, and they will direct our activities potentially differently. I wouldn't say that it's going to create an incremental capital spends or anything like that, potentially redirection of it. Now, it could provide some incremental capital spend, if, when working with our regulators, they determine, we jointly determined that there are things that we need to do more quickly than we otherwise would have done. But I wouldn't say right now that there's some anticipation of a change in the size of the capital plan, going forward because of these events, might be a change in direction for some things just to prioritize differently. But everything's a learning experience. And we'll continue to do that. And as I said, events last week, we're still unpacking everything there.

That's helpful. Maybe just one last for me just on nuclear operations, just curious more broadly, how are you feeling in terms of operational progress, performance, just trends and any recent developments there? Or is it sort of fairly consistent with prior messaging there?

In the majority, it's consistent with where we've been. I would say that we continue to work with Grande Golf, we have some work to continue to do there to get that plant into the space where we want it to be, but majority of it is on track.

Understood and the Grande Golf work is that sort of just general operational improvements? How would you sort of highlight the work needed there?

In the equipment reliability space, for the most part, as you know, we've gone through a couple of major outages with big equipment modifications, the most recent equipment modification determined control system, we've had some issues coming out of that outage with some of the equipment associated with that modification. So we're going to continue to work through those, get those knocked out and get the plant up to the level of excellence that we desire.

Our next question comes from Shar Pourreza with Guggenheim Partners.

Hey, good morning, guys. Just a couple of questions here. Firstly, just on the cost savings you presented $150 million that was $150 million in savings that was obviously executed in 2020. That was well in excess of your original $100 million, right. So just curious to the level of recurring cost savings, you think you can - you think you can take it to 2021 and sort of continue on that momentum? And can you find sort of incremental opportunities especially on the corporate side i.e. we've seen several peers generates significant cost savings from, for instance, real estate optimization. So wondering if this is also potential leverage you guys go through COVID and the learning curves there.

Hey, Shar, this is Drew. So most of the savings that we saw in 2020, I would characterize as more one time in nature; they're part of our flexible spending efforts. And those are typically looking for ways to take action to manage to outcomes in that particular year. And so we would not necessarily see those as recurring. But this year, we've identified new ones that we would be able to use to manage this year, if needed. And we had continued on last year, after we said that we got to $100 million looking for more in the event that we needed it. And it turns out, as you know, that we need all of it. There - having said that, there were some things that were identified as potential continuous improvement elements and sort of fit into those other buckets, although they were relatively small, I would think in the 20% range. And those are now accounted for in our outlooks as part of our O&M expectations. And there are other things that we are looking at. We are driving our continuous improvement efforts forward. Things like real estate optimization are in the spotlight for us, as we think about how we manage our workforce of the future. And that's an easy one to consider as we go forward. So those things are part of what we're looking at. And some of those expectations are now getting baked into our outlooks.

Got it. And then just maybe a timing on when your update around those, on the additional levers?

Well, I think they're just part of our ongoing process. We don't have anything today. We don't have any specific timetable that we're working towards; it's just an ongoing element.

Got it. And then just on Arkansas, it's good that you're confirming or reaffirming that depending on whatever outlook happens in the FRP order that you're comfortable with the plan, midpoint of guidance embedded there. It sounds like you're obviously shifting or optimizing CapEx and O&M away from Arkansas. So I'm kind of curious, what - have you had any dialogue with the commission around sort of that strategic move, and I'm wondering where you redeploying the capital spent.

Shar, it's Rod. Good morning, the conversation as you know with the stakeholders is ongoing. And we won't comment specifically about any aspect of the give and take. But it is known in Arkansas that one of the consequences of us not having clarity around the FRP. And the extension is just that we would have to revisit how we deploy capital in Arkansas. And those conversations have been ongoing since the December order. And it's part of the motivation, why we're working the various avenues to turn that the conversation around. But they are aware of our point of view around the capital plan; we're not talking about specific puts and takes. That said our point of view that we shared with you earlier about why we thought the FRP provided us the best opportunity to create sustainable value for customers, as played out during dependency of the FRP. And why we feel so adamant about the propriety of the extension. And so I think that that message will resonate. There's more to come in terms of how it plays out. But that's about all I can speak to it, but you're raising a great point. We're all motivated to create value.

And the question about where it's going at this point is not really going anywhere. Yes, to the extent that we are optimistic that we can get some reversal of December order. We are waiting to see if we would want to put that capital back in place.

Got it. Dave Borde, congrats on sort of the new leadership position and Rod make sure you're working really hard. Thanks, guys.

I don't think you have to worry about that.

Our next question comes from Durgesh Chopra with Evercore ISI.

Hey, team, good morning. Thank you for taking my question. Can you, sorry if I missed this, but have you quantified in terms of financially? What impact if any, does sort of last week's event have for you?

Yes, so this is Drew. So Leo, in his remarks mentioned some of the cost elements up to $140 million in terms of restoration costs, and an incremental $400 million in terms of fuel costs. So I'll give you a little bit color, and there will be more specific numbers in the K which will file in a couple of days. But on the fuel cost, I think it's all in it's about $500 million, I would say about $100 million is kind of what we would normally have expected. And that gives you to the $400 million that Leo was talking about. Of the $500 million, about $200 million of it is in Louisiana, and that is about 90%to 95% EOL and the rest in New Orleans, about $150 million is in Texas. And these are all round numbers. As I mentioned, you'll have specific ones later, there is a positive deferred fuel balance in Texas of about $90 million that'll help offset that. And then in the neighborhood of $100 million and Arkansas and around $50 million and Mississippi. So that's kind of how that would all break down.

Understood, that's super helpful. Really, thank you. So it's essentially $400 million increment to what you might have otherwise expected on a normal basis.

Yes. In February, and I'm talking about the month of February really?

Yes. Okay. Perfect. Thanks. And then just quickly, can you sort of - so the slide here says the Arkansas FRP extension first quarter, right, just can you remind us what the date is of that final order? And then in terms of like what to look for? Could that get extended? Just any color on when we may get resolution on that front?

Yes, this is Rod, March 15 is the date that the Commission has set for itself to issue the order for both the 2021 FRP and the renewal of the of the FRP extension.

Our next question comes from [Steve Liesman with Wolfe Research.]

Yes, thanks. Good morning. So this was a helpful update. Thank you and just the Louisiana FRP extension. I think you continued settlement talks there. Could you just maybe give color on your confidence and be able to settle that case?

Steve, Dave, I can, well, this is Rod. But I can tell you that the conversations in Louisiana are going perhaps consistent with our expectations slowed only by the last certainly the storms and occasionally COVID. But the types of issues that we've been working through with our stakeholders and the regulators have been consistent with expectations. We're targeting the resolution of the Louisiana renewal by the end of March. And that said we'll be monitoring that progress as we have others but March is our target to resolve that all things being equal.

Okay. Great. And then separate, different question just Drew on your financing plans is there - I might have missed it. But is there any update or changes in your equity issuance plans for the three-year period?

No, no new changes from what we described in Analysts Day. We have made some progress. We got the aftermarket program up and running in January. And then we will have a proxy finally coming up. We'll have a request to get the authorization to issue preferred equity. So that should be coming up soon. But those are the only two things that are noteworthy since our last disclosure.

Okay, and then just on after market, is there like a timeline for that part of the financing you're targeting or -

No, there's no timeline. We don't have any additional information there.

Our next question comes from Paul Fremont with Mizuho.

Thank you very much. I guess if I heard you correctly in Arkansas, your guidance is essentially contingent on an FRP extension. Are you expecting that to come through a negotiation or through a final Arkansas public service commission rate order?

The answer without being sounding trite is yes. So whatever progress we're able to make to date in through the 15th, which is only two and a half to three weeks away, we'll incorporate whatever progress we make. The assumptions we're making in our guidance and outlook assume the December order and an FRP, presumptively, with a December order. But it's our confidence and our ability to manage to expectations with whatever would be the likely or reasonable components of an Arkansas order. And so that's really the commitment we're making today that our outlooks are tied to those two primary assumptions.

Right, but would your guidance hold if the FRP were not renewed?

If the FRP was not renewed, then we would likely have to see what the circumstances were, obviously, we have the ability, if needed to, for instance, file a rate case or take some other remedial action. And so from a planning standpoint, we're contemplating all of those scenarios, but it's too early for us to know which levers we'd ultimately pull. But our commitment is to manage to those likely outcomes.

Our next question comes from Julian Dumoulin with Bank of America.

Hey, thank you, team. Good morning rather.

Don't you get we are having a 24x7 shop as you don't know what time of day it is.

Feels it that way. But if I can, let me come back to the planning scenarios we talked about a second ago. So you're talking about cost reductions, CapEx levers, and also a series of flowcharts, if you will, around what you could do? Can you elaborate a little bit on all these levers? Like, if you were to pursue this out, would you file a rate case later this year in Arkansas, or are litigious and appeals strategy, the first way to go? How quickly when you think about the different scenarios would you pursue one over another? And how quickly could we come back with a cost savings program and CapEx program to preserve at least the integrity of returns I suppose?

Julian, I appreciate the question. I guess we're in the midst of discussions and these orders, and we're only a couple of weeks out from resolution. So I think it'd be best for us to just defer commentary around all of that until we get the outcome. Since it's pretty prompt.

Yes. Understood. But to be clear about this, it sounds like you've got contingencies already running on both costs and CapEx levers as it stands today.

Correct.

And then the second quick question, if I can probably related on the subject of bill impacts and how you think about cumulative bill impact, how do you think about the total trajectory, knowing what you know about storms and otherwise, as well as the pace of CapEx and sales trajectory in 2021 onwards? Are you anticipating at this point in time across your service territories?

So make sure we get to everything that was in there. So you're correct, right. We've made adjustments to our plan to anticipate what we think is the likely outcomes in the FRP renewals for any regulatory process going forward, so that is incorporated in our thinking and obviously in our outlooks based on what we told you today. And certainly from a bill impact standpoint, we're obviously going to work through all of these processes, whether it be the storms from last year, or the storms from last week, and try to make recovery work for - keep the company in the right space as it relates to our credit profile, and earnings as well as to keep our customer bills mitigated as much as we possibly can, which is what we've always done. So the tools that we talked about, whether it be securitization, or normal ways that we handle fuel cost recovery, or some of the options that we've taken those in previous times, all that'll be on the table to where we can make it as minimal and the impact on customers as we possibly can while we continue to meet, for example, our credit and earnings commitments.

That's the next question comes from Jonathan Arnold with Vertical.

Yes, good morning, guys. Could we get maybe an update on where you are on say on rate and incremental bad debt since you updated last quarter?

Sure, Jonathan. This is Drew. So as of the end of the year we had recorded bad debt expense of $112 million. Our normal bad debt expense in any given year is about $25 million. So that incremental $87 million was recorded as a regulatory asset, because we have orders in each of our jurisdictions that would allow us to recover those costs. The arrear is typically runs about three times higher than the bad debt expense. And so that number is pretty consistent, we've seen it begin to level off, but we need to see where it goes with this latest round of storms, and a little bit of backtracking on disconnects because of the storms. And we never did get often disconnects in Arkansas or New Orleans. So those two jurisdictions have continued on for a little bit longer. But that's kind of where we stand right now.

So just to be clear, I understand that for the rate numbers more like a something in the 300.

Correct.

And as you reserved just or written off for fees or recovery 30 half a third, roughly?

That's correct.

Okay. Thank you for that. And then just if I may, on the quarter, and just an understanding that the numbers are a little better than the full year, it looks like you had $0.23 of tax related benefit for the year, but you were sort of shooting for $0.15 when you last updated guidance on Q3 and so there would be a sort of $0.08 incremental held versus what you were expecting and maybe another $0.07 or so P&L. Am I reading that right? Or is there a better way to think about that?

No, that's correct. There are some details in the appendix which talk about those things for 2020. And sure they are on the fourth quarter, most of that is in the fourth quarter, it was related to just annual true up that happened to work out in our direction, there was a small item that we found, which was an opportunity for us. But that's consistent with what we've been doing for a long, long time. Obviously, the big item, we adjusted out which we committed to you all we would do. And so going forward, any of those annual true up, they might break for us, they might break against us, and we have to manage within that. We do expect to find some small items going forward. But we're not counting on it. If you look at our tax rate for 2021 it's a 22%. And I think we're not disclosing it. But in our plan, we actually have it drifting back up to around 24%, 24.5% beyond that. We've had it lower for the last years as you know because we had all the AFUDC from the projects, all pretty much all of which went online in 2020. So that positive tax effect isn't as strong going forward.

So is it fair to say it sort of helped you $0.15 or so in Q4?

It did. We also weren't planning the $0.16 regulatory provision from the Arkansas order. So it kind of balanced out.

For sure, yes. I got it. And then I may have missed this. So make sure I obviously noticed your CapEx down I guess 2021, $300 odd million best follow up to 9% was, is most of that sort of dialing back in Arkansas, or some other things going on?

That is that is primarily Arkansas there. We we've taken some capital out of 2021 and 2022. We put a little bit back in 2023 in Arkansas. There were some other timing elements of the other jurisdictions, but the main impact is Arkansas.

Our next question comes from James Thalacker with BMO Capital Market.

Thanks so much. Good morning, guys. Just real quick follow up. And I think I know the answer, you reiterated your ranges, I guess through 2023 as well as the midpoint. And I think in relation to Steve's question, Drew doesn't sound like your financing plan has changed? Has there been any change? I guess in the cadence of that financing, and maybe to look at it is fairly ratable. But just kind of given where the FFO metrics are, should we assume that maybe some of that equity is a little bit more front end loaded or still ratable?

So we haven't, we don't have any additional information provide on timing. Other than what we've said previously, we do expect to issue some equity this year. And then we have the $2.55 billion by 2024. But outside of that we don't have any other timing or amount, items that we would disclose right now.

Got it and the $1 billion ATM that you were mentioning, I think you guys put that in place in December that was part of that original financing plan, too just to clarify.

That's correct. It's one of the tools that we were putting in place, with the other being the authorization requests for preferred equity

Our last question comes from Ryan Levine with Citi.

Thank you for taking my question. I just wanted to follow up on some of the bad debt items. Can you remind us exactly what in your 2021 earnings guidance is around bad debt expense assumption? And if there's any incremental off of initial assumption from the events from last week, appreciate the $400 million of incremental fuel costs number, so curious if you've adjusted any of your bad debt assumptions on that regard.

We have not adjusted our bad debt assumptions for that. Right now, I believe it's probably fairly normal around the $25 million amount that I was talking about earlier. Obviously, we'll be monitoring that closely. And seeing where all the COVID arrears actually fall out, we have an estimate, as we were discussing earlier, there are about a third. Ultimately, we would expect to be able to recover those costs through the regulatory process. But we don't have exact numbers yet. This is - that part's a little bit uncharted territory, we'll see where it comes out.

Are there any regulatory approaches or tools that you have, or any potential political responses to help mitigate that potential incremental bad debt expense?

I don't know about regulatory tools. I mean, we have the orders that are already in place. We are working closely with customers to try and mitigate the impact on customers, we've done a number of things to put new deferred payment plans in place, we've been working hard with our customers, we've renegotiated 1000s of plans with our customers already, to try and help them out. We've invented new ways to get likely funding to our customers and other community tools that are available. We've actually worked with some of our retail regulators to do some of that in New Orleans and other jurisdictions. So there are a number of things that we have underway to try to mitigate the impact and we are trying to work hard and communicate very closely with our customers to make sure that they know where we are and with our retail regulators at the same time.

Okay, and in fact to just squeeze on one last question, in terms of - what's the regulatory approach to enable a path forward for Louisiana and from your other jurisdictions to fuel LDCS with hydrogen, in light of your hydrogen strategies that you highlighted?

Well, from a regulatory process standpoint, it would be the same process we use to with our resource planning. So whether it's an RFP process, recovery of those of the investments we make for those resources would go through our existing recovery mechanisms. But to the extent there are some nuances, where the current mechanisms don't account for some of the really forward-looking aspects of the hydrogen or any new technology. We'll be talking with our regulators about closing whatever those gaps are. But we have an existing process thus far with the RFP and the riders would have.

Appreciated, thank you.

And I'll just repeat the LDC is a very small piece of our overall business. I think the rate base is only about $200 million or so overall.

I'd like to turn the call back over to David Borde for any closing remarks.

Thank you, Michelle. And thanks to everyone for participating this morning. Our annual report on Form 10-K is due to the SEC on March 1, and provides more details and disclosures about our financial statements. Events that occur prior to the date of our 10-K 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. Also, as a reminder, we maintain a webpage as part of Entergy Investor Relations website called regulatory and other information, which provides key updates of regulatory proceedings and important milestones on our strategic execution. While some of this information may be considered material information, you should not rely exclusively on this page for all relevant company information. And this concludes our call. Thank you very much.

Ladies and gentlemen, this concludes the program. You may all disconnect. Everyone have a great day.