Entergy Corp (ETR) — Q1 2017 Earnings Call Transcript

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

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

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

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

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

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

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

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

This is Drew. Regarding the overall forecast, Chris, I believe it's essentially unchanged from before. We still face all the outages this year, which are quite costly. However, we expect strong cash flow generation moving forward mainly because we won't incur another refueling outage at each of the plants, specifically at Pilgrim and Palisades. We will have one more at Indian Point for each of its units, after which those two units should generate better cash flow as they transition into 2021. So, from a cash flow perspective, it remains about the same. As for your second question on progress, I can confidently say we are making headway. We've been rigorously examining the numbers internally and hope to show specific progress throughout the year, demonstrating that we are closing the gap and working towards the cash flow neutral objective that Leo mentioned in his remarks. Just to clarify, we are already operationally cash flow neutral; it's the nuclear decommissioning trusts that we are still addressing. Additionally, we are pursuing transactions related to this as well.

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

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

I was going to ask about sales, but that seems to have been addressed. Instead, could we get an update on the Nuclear Sustainability Plan, including progress on the metrics and a reminder of where you stand in making some of this relevant to rates?

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

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

In terms of timing, we plan to file this coming Friday with the APSC to formally reconcile the nuclear cost adjudication with our formula rate plan filing in July. This will allow us to address the nuclear cost discussion alongside the FRP. Our view on the recoverability of those costs remains unchanged. We believe the facts support our claim that the costs we are seeking recovery for align with what has been communicated over the last several quarters. The costs pertain to enhancements made to the equipment and the plant to maintain these assets and benefit customers. We are confident that the evidence will substantiate the recovery not just of the costs in question for the 2016 or 2017 forward test year, but also for the actual 2018 test year that we will file in July. No changes there, and we maintain a consistent message regarding our recovery efforts. It’s important to note that the costs related to the FRP filing, as well as the overall nuclear costs we plan to file in July, will not cover costs associated with regulatory oversight or similar issues. Therefore, these will primarily reflect the operational costs of running and maintaining the plant beyond the expected lifespan of the assets.

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

I was referring to our plan to file on Friday to address those issues related to timing in Arkansas. The issue you mentioned is the subject of the filing we will make on Friday. We will formally request the APSC to consider it along with the scheduled FRP filing in July.

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

I want to ensure that I address the question correctly, so you may need to repeat the last part. Regarding AMI, we have submitted filings in every area except for Texas, where we are working to meet some legislative prerequisites before proceeding there. We anticipate that the formal AMI filings will be resolved by the end of the year. When considering other jurisdictions, the timeline for both the conditions necessary for deployment, which includes integrating workforce management systems with asset management systems, and our deployment timeline from 2019 is informed by the experiences and lessons we have learned from other regions that have previously followed this path. Our consistent message across all filings and jurisdictions is that our goal is to ensure that customers can benefit from AMI deployment alongside the benefits we gain when we put those assets into operation. This goal influences our deployment timeline plans, and this message remains the same for all jurisdictions. As for the third question, I didn't quite catch it, so please repeat it to ensure I provide an accurate response.

Let me clarify one point on that. Our capital plan for 2019 primarily focuses on corporate-wide initiatives, including communications and IT platforms that will support the scaling of Texas as it develops. Beyond this capital plan, there will be more Texas-specific projects like meter deployment, which may commence in 2019 but will definitely continue into 2020 and 2021.

Just a quick clarification on the prior. You were talking about cash flow as a sort of breakeven target for the business overall or the EWC side. Can you just elaborate a little bit on what you expect the ongoing impact to operational earnings are? Can you remind us how you're thinking about that through the period and specifically, in the later years, how we should think about operational versus nonoperational items on earnings?

You're referring to the years '17 through '21? Yes, moving forward, once we reach a shutdown status for the plants and those are removed from our decommissioning activities or taken off our balance sheet, like the VY transaction, we expect EWC to remain mostly stable. Additionally, next year there will be a change in accounting rules regarding how we handle new earnings from decommissioning trusts. This will allow us not only to recognize realized gains on our income statement but also to reflect market growth in the trust over time on the equity side. Typically, we see returns of around 6.25% from the decommissioning trust, but we only account for about 3% on the income statement. Closing this gap helps align the asset retirement obligation liability and its amortization. Thus, by 2022, we anticipate the earnings to be flat.

Excellent, so to be clear, it's effectively 0 for the cumulative cash flow and flat on an earnings basis?

Starting in 2022 and continuing thereafter, yes.

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

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

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

For residential and small commercial, it's nearly zero. In fact, if you were to look beyond 2017 to 2020 or 2021, the figure would be slightly negative. This is due to the rollout of automated meters, which allows customers to realize associated benefits. One key benefit is the expectation of lower demand. Consequently, we are experiencing negative growth over a span of about five years.

Michael, this is Rod. I want to emphasize that our capacity needs are not primarily influenced by assumptions regarding low growth, although such growth helps mitigate the effects of capital increases on customer rates. The main reason for our capacity needs in specific locations is related to the particular requirements of industrial sites in the area, but fundamentally, it revolves around modernizing the grid and fleet and addressing the retirement of aging assets. This represents the majority of the investment in generation and transmission in the region, which is influenced less by assumptions about overall industrial demand.

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

Got it. And finally, regarding Indian Point, when does the state need to inform you if they might require Indian Point beyond the 2020-2021 retirement date? I understand the original agreement allowed for the plant to operate until around 2024 or 2025, but much of that depends on the ISOs and the state's perspective on its necessity. When do they need to notify you? When will you need to have that information?

Michael, this is Drew. We need to submit a formal filing with New York's ISO, which will help them assess Indian Point, its future, and how to manage it. We are coordinating with the ISO and plan to make this filing later this year. Once submitted, there is a 90-day period for their analysis and formal recommendation. They are aware of the situation, and the process will begin later this year.

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

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

In our previous discussions, we mentioned the Arkansas prudency review and a distinct procedural schedule, but now it appears to be integrated into a larger one. Can you provide any insight into why it wasn't kept separate? Was it due to the original prudency review being small, making it reasonable to include it in a joint proceeding? Some clarification on this would be appreciated.

Sure, it's Rod. We have consistently maintained that we weren’t looking for a separate recovery mechanism for the nuclear costs, as these costs align with our goal of preserving those assets and the benefits they provide to customers. Considering the upcoming situation in July with the formula rate plan filing and our forward-looking test year, it seemed logical for us to address everything together, especially since the APSC had not established a separate procedural schedule. This way, neither we nor the APSC would have to manage ongoing nuclear spending in two separate dockets for nuclear and the rest of ANO. It simply made sense to us. Due to the ex parte rules, we couldn’t have discussions with the commission. So, on Friday, we aim to confirm and clarify our perspective that handling both matters simultaneously is the right approach.

Can you provide an update on the decommissioning expenses and the sale potential for Pilgrim and Palisades? Will we see a similar process for Indian Point in the future?

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

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

There could be an opportunity to achieve a slightly positive cash flow. Our goal of reaching cash flow neutrality involves operational aspects while we continue our operations and manage certain transactions. If we were to experience significant success, we could potentially turn positive throughout 2021 and over the next four-plus years.

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

Thank you.

He's heard that a couple of times.

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