Entergy Corporation (ETR) Q4 2016 Earnings Report, Transcript and Summary

Welcome to Entergy Corp. Fourth Quarter 2016 Earnings Release and Teleconference. [Operator Instructions]. As a reminder, this conference call is being recorded. I would now like to turn the conference over to David Borde, VP, Investor Relations. Please begin.

Thank you. Good morning and thank you for joining us. We will begin today comments from Entergy's Chairman and CEO Leo Denault and then Drew Marsh, our CFO, will review results. In an effort to accommodate everyone who has questions, we request that each person ask no more than one question and one follow-up. In today's call, management will make certain forward-looking statements. 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. Today we're reporting final results for 2016, a pivotal year for our Company, a year in which our objectives were ambitious and our execution was on the mark. We delivered on our commitment to grow our core business and our utility, parent and other adjusted earnings reflected over 40% growth year over year. These financial results are the outcome of exceptional performance and have positioned us to achieve our financial outlooks in the coming years and to deliver steady, predictable growth in earnings, as well as our dividend. We raised our dividend for the second consecutive year, a trend we expect to continue subject as always to Board approval. And finally, with the Indian Point announcement last month, we completed our plan to exit the merchant power business and transition to a pure play utility. Our results today are the outcome of the disciplined execution of our strategy for the past few years, a strategy intended to fundamentally reposition our Company on a steady, predictable earnings trajectory. And today we're initiating guidance for 2017. We're also affirming our three-year utility parent and other adjusted earnings outlook, targeting a 5% to 7% growth rate, acknowledging that some years may be above or below that range. This morning, I will provide more detail about our longer term initiatives and the progress we made toward them in 2016, as well as our plans for the future. As I mentioned at the outset, 2016 marked a critical milestone in our exit from EWC and the risk associated with the merchant power business. We have finalized plans to sell or shut down all remaining nuclear plants in the EWC portfolio through a deliberate, planned and orderly process to cease all merchant nuclear operations by 2021, effectively exiting the merchant space. We began this process with the shutdown of Vermont Yankee at the end of 2014, followed by the sale of EWC's Rhode Island CCGT in 2015. In 2016 we sold EWC's interest in the wind assets in Iowa and Texas. The proposed sale of FitzPatrick to Exelon is on track to close in 2017. In 2018 we expect to close Palisades followed by Pilgrim in 2019. And finally, in 2020 and 2021, we will close Indian Point Units 2 and 3. This orderlywind down of EWC will provide us sufficient time to look for ways to integrate employees into other areas of the business and right-size our corporate organizations. With a sustained low wholesale energy price environment and increased operating costs, exiting our merchant power business is a sound, strategic decision. Looking back at some of our more significant announcements this year, we reached an agreement in August with the state of New York and Exelon for the sale of FitzPatrick. In January, the NRC approved the transfer to Entergy of the decommissioning trusts for both FitzPatrick and Indian Point Unit 3 and we remain on track to close the transaction in the first half of this year. For Palisades, we reached an agreement in December with CMS Energy on early termination of the long term purchase power agreement subject to approval from the Michigan PSC. We plan to shut down that plant in 2018. And as you are aware last month, we announced the planned shutdown of the two operating units at Indian Point in 2020 and 2021. The shutdown is part of a settlement under which New York will drop legal challenges and support the renewal of the NRC operating licenses for Indian Point. The plan will run for seven more years, allowing time for the New York ISO to replace this key generating resource which currently provides roughly 25% of the electricity for New York City and the Hudson Valley. We appreciate the commitment to safety and operational excellence of the nearly 1000 employees at Indian Point. They have enabled the site to run at greater than 90% capacity factors under Entergy's ownership compared to roughly 60% under its previous owners. The NRC has placed both units in its top regulatory column for safety. Our plans to mitigate the risk of our merchant business extend beyond operational risk. We reached an agreement this past November to transfer Vermont Yankee's decommissioning liability and trust funds to NorthStar, conditioned on regulatory approval by the NRC and the Vermont Public Service Board. This transaction will eliminate the residual risk from decommissioning and is targeted to close in December of 2018. There are many advantages to this kind of transaction and we view this as a model to pursue for future risk reduction as we move forward with the shutdown of the remaining nuclear plants. Finally, I would note that the decision to close our merchant nuclear plants was a difficult one. We cannot overlook the impact these shutdowns will have on the lives of our employees and the communities they serve. Despite these challenging circumstances, our employees remain dedicated to the safe operation of these plants through shutdown and I thank them for their ongoing hard work and professionalism. Our decisions were driven by adverse economics and are not a reflection in any way of the quality of our work force. The Company remains committed to supporting them as they manage this difficult transition. With the orderly winddown of our merchant business underway, I will now talk about our strategies to grow the utility for the benefit of our customers. Beginning with our generation fleet, we're delivering on our promise of portfolio transformation as part of our ongoing Environment 2020 commitment. Recall that in 2011, we made a voluntary pledge that by 2020 we will maintain our carbon dioxide emissions at 20% below year 2007 levels. We're meeting this goal in part by replacing older, less efficient legacy units with a cleaner, more efficient portfolio. Additionally we had begun to add renewables to our portfolio, along with a greater emphasis on energy efficiency programs, as well as completed upgrades to our nuclear capacity. This transformation began about a decade ago and to date we have deactivated roughly 5100 megawatts of older generations since 2005. Currently over 8000 megawatts of our legacy generation is over 40-years-old. We've added nearly 6000 megawatts of generation through acquisitions, including our most recent acquisition of Union Power Station which received final approval in 2016. We're now transitioning from acquisitions to building new plants, beginning with Ninemile 6 in late 2014. After receiving approval from the Louisiana Public Service Commission in November, we're moving forward with the construction of the St. Charles CCGT expected to come online in 2019. We also have applications pending for the construction of the Lake Charles CCGT in Louisiana and the Montgomery County Power Station in Texas, as well as the New Orleans Power Station. All combined, this will represent nearly 4000 megawatts of new generation to replace older, less efficient plants. These plants will improve the reliability of our system, increase our environmental efficiency and reduce costs for our customers by using less fuel and improving our average fleet efficiency by roughly 800 BTUs per kilowatt hour. Additionally, new units will have lower maintenance costs and produce up to 40% fewer carbon emissions. These critical attributes provide significant benefits to our customers and support our environment 2020 commitments. Nuclear generation also continues to be a key component of our cleaner generation portfolio. It's an important source of clean, low-cost, reliable baseload power. These plants provide fuel diversity and reduce fuel price volatility for our customers. Prudently investing to preserve these valuable resources for our stakeholders is an important part of our utility strategy. Our transmission system is critical to deliver -- to the delivery of this newer, cleaner generation and in 2016 we completed projects like upgrading the 230 kv lines from the Ninemile generating facilities for Entergy Louisiana and Entergy New Orleans. Transmission is also needed to support economic development by serving new customers. In 2016, we invested in projects like substations to serve new industrial customers, particularly in Arkansas and Louisiana and we're on schedule to deliver the Lake Charles Transmission Project in $160 million investments supporting industrial growth in the region by June of 2018. Finally, our transmission grid is critical for system reliability and efficiency. In 2016, Entergy Texas completed three major projects to comply with NERC reliability standards and reduce congestion in its service territory. We added three new 230 kV lines, as well as a new 230 kV substation which will not only enhance reliability and efficiency but also reduce costs to customers. And there are four large transmission projects underway in Entergy Mississippi which will increase the reliability of the electric systems in Vicksburg, Natchez and Madison areas and provide opportunities for those regions to grow and develop. We continue to work with MISO on future transmission projects. We received final approval in early December from the MISO board for MTEP 2016. MISO approved all 48 of our projects which were remaining for final consideration, totaling roughly $480 million of transmission investment to serve our customers over the next few years. Beyond these traditional generation and transmission investments, we're also looking at the future by modernizing our grid to incorporate technologies to improve efficiency and reliability. In 2016, we started to lay the foundation for our integrated energy network. We have begun the process for our advanced meter infrastructure, the gateway technology that will allow us to be more responsive to emerging issues, reduce outage restoration times and improve system reliability. This technology will also provide timely information to our customers so they can better understand and control their usage. We have now made filings with our regulators in four jurisdictions for approval to implement advanced metering and we expect to file in Texas our final jurisdiction in 2017. We anticipate beginning meter deployment in 2019. Investment in this technology, along with other grid technologies such as meter data management, outage and distribution management and communication network infrastructure are a key focus for us in 2017 and for several years beyond. To that end, we've created a dedicated team to provide constant focus on evaluating and integrating new technologies into our operating model. These include distributed generation, utility and community scale solar, microgrids and battery storage. In 2016, we completed and initiated a number of projects to explore the use of some of these evolving technologies. Our success with all of the utility initiatives I have just mentioned has been facilitated by the work we've done with our regulators to implement progressive regulatory mechanisms. We have come a long way in the past two years. We now have three jurisdictions utilizing Formula Rate Plans with Entergy Mississippi utilizing forward-looking features and Entergy Arkansas having adopted a full forward test year. In December, the Arkansas Public Service Commission approved our first forward test year FRP filing with new rates in effect last month. In Texas, we're now utilizing two writers for more timely recovery of distribution and transmission investments. We have reached a settlement agreement in our most recent transmission cost recovery factor filing and are awaiting final approval from the Commission. Where available, aggressive regulatory frameworks will facilitate investments that enhance the efficiency and reliability of our system to benefit our customers, provide access to capital at a reasonable cost our customers and facilitate infrastructure investment that supports economic development and creates jobs in our regions. We will continue to work with our regulators and others to improve existing constructs to ensure that we have the financial flexibility to execute on capital investments in response to our customers' needs. Our objective in concert with our regulators and other key stakeholders is to assure the access, affordability, reliability and sustainability of the services we provide. Many of you have heard about last week's tornadoes that struck multiple areas across Louisiana, including a confirmed F-3 tornado that touched down in New Orleans East. Supporting our customers and communities in times of need is central to our mission as a Company. Our crews work tirelessly to restore power to thousands of our customers and many of our employees volunteered their time to support recovery efforts. The success of our utility business is dependent on making sure that the communities we serve are thriving. As part of our five-year initiative supporting job-training opportunities, we have begun making grants to promote economic growth and workforce development across our service territory. Through economic development activities such as these, Entergy has contributed to the creations of tens of thousands of new jobs in our region since 2005. We're pleased to have been recognized through several awards in 2016 for our efforts in corporate stewardship and community development. For example, our major upgrade to transmission service in New Orleans was named as a top 10 finalist for Construction Project of the Year by Platts Global Energy Awards, recognizing innovation, leadership and superior performance. Site Selection Magazine named us one of the top 10 utilities in economic development for our integral role in capital investment and job creation in our service territory. And for the 15th consecutive year, we were named to the Dow Jones Sustainability Index for performance in corporate citizenship and philanthropy, environmental performance, biodiversity and climate strategy. Before I wrap up my remarks this morning, I would like to thank Bill Mohl, who is retiring at the end of this month after more than 35 years in the industry. Throughout his career at Entergy, Bill has led major initiatives which have been key to enabling us to achieve our objectives. His leadership, business perspective and high professional and personal standards are characteristics which have made him an important member of our senior leadership team. More importantly, we will miss having his trusted counsel and friendship as we accomplish the objectives he has helped to shape. We wish him all the best as he moves into this next chapter in his life. As I said at the outset, this year was a pivotal year for our Company, a year in which we fundamentally repositioned our business on a path of steady predictable earnings by growing our core business with our utility, parent and other adjusted earnings increasing by more than 40% year over year and completing our plan to exit the merchant power business and transition to a pure play utility. 2016 was an ambitious year when our results and achievements have made us a stronger company and have set us up for success in the years to come. And now I'll turn the call over to Drew.

Thank you, Leo and good morning, everyone. As Leo mentioned, 2016 was a pivotal year for Entergy. We continue to execute on repositioning our Company towards a steady, predictable, earnings and dividend growth trajectory. Today I will discuss how our core utility, parent and other adjusted EPS grew by over 40% in 2016 and I will provide an overview of our guidance for 2017. I will also provide our perspective on EWC going forward and potential tax reform. Now let's jump into 2016. I will start with the key takeaways from fourth quarter consolidated results on slide 5. On the left, Entergy's as reported loss of $9.88 included special items totaling $10.19 related to the decision to sell or close each of EWC's nuclear plants. The majority of that was for previously disclosed impairment charges for Indian Point and Palisades. On an operational view, our consolidated earnings were $0.31 per share in 2016. This compares to $1.58 a year ago. Remember that 2015 results included significant income tax benefits, largely from the business combination of the two Louisiana operating companies. Turning to utility, parent and other on slide 6, operational earnings-per-share decreased $1.07 quarter over quarter. 2015 income tax items net of customer sharing were $1.15 -- excuse me, $1.57. Conversely, weather was favorable in 2016. Adjusted EPS normalized for tax items and weather improved year over year. This was partially due to rate actions to recover investments that benefit customers and improve returns. Specific drivers include Entergy Arkansas's rate case, Union Power Station acquisition, Entergy Mississippi's Formula Rate Plan and Entergy Texas transmission cost recovery writer. Results also included lower write-offs and reserves related to regulatory proceedings. We reported an $0.08 charge in the fourth quarter of 2016 related to the Waterford 3 steam generator replacement project which I noted last quarter is something we were monitoring. Billed retail sales on a weather adjusted view increased 0.8%, driven by residential and commercial segments. Industrial sales were slightly positive with expected refining outages offsetting continued growth from new and expansion customers. UPO earnings also reflected higher nonfuel O&M from the aforementioned Union acquisition and nuclear. Turning to EWC's fourth quarter results summarized on slide 7, an operational loss of $0.04 in the most recent quarter was lower than earnings of $0.16 a year ago. Net revenue from nuclear plant declined on lower price and volume. FitzPatrick's generation volume was lower because of its ramp down before its refueling outage. Decommissioning expense was higher due partly to the establishment of decommissioning liabilities for Indian Point 3 and FitzPatrick as a result of our agreement with NIPA to transfer the decommissioning trucks and liabilities to Entergy. On the positive side, DOE litigation awards reduced EWC expenses approximately $0.10 in the quarter. Slide 8 shows operating cash flow in the quarter was approximately $750 million. This quarter was lower than last year, due primarily to deferred fuel timing at the utility. Now I will quickly go through the full-year results summarized on slide 9. Consolidated operation earnings for 2016 were $7.11 per share, higher than the $6 reported in 2015. It was also above our guidance midpoint and better than our expectations in November. Drivers to the change versus our expectations included cost management of utility which we noted as an opportunity last quarter, favorable weather and the DOE awards at EWC. The year-over-year growth in operational EPS was driven by growth in core utility earnings. Both years included income tax items, but the earnings benefit was $0.25 higher in 2016. As shown on slide 10, utility, parent and other adjusted EPS was $4.38 in 2016, slightly higher than the $4.35 guidance midpoint. The approximately 40% increase compared to $3.08 at 2015 was due largely to higher net revenue from the same rate action mentioned in the quarterly drivers, as well as industrial sales growth and lower nonfuel O&M. Slide 11 summarizes EWC operational earnings which increased year over year to $2.01 per share in 2016 from $1.03 per share. Income tax items and reduced operating expenses from 2015 impairments were the main drivers. Expense reductions associated with DOE litigation awards also contributed. 2016 results also reflected lower nuclear revenue from lower average prices and capacity factors. Full-year 2016 operating cash flow shown on slide 12 was just under $3 billion in 2016, around $300 million lower than the prior year, again due largely to timing and the recovery of fuel and purchase power costs and lower EWC net revenue. Now that we have wrapped up 2016 results, let's look forward. I'll start with a framework for our EWC expectations shown on slide 13. As Leo discussed, we now have plans for an orderly winddown of the nuclear assets within EWC, but we plan to have nuclear plant operations through 2021. As such, EWC does not meet GAAP criteria to account for the business as a discontinued operation. We will continue to report the results of the business consistent with our practice for the past few years. We will classify severance and retention expenses, as well as impairments, including capital, fuel and refueling outage costs and special items and we will exclude them from operational earnings. Our 2017 guidance and operational adjusted EBITDA outlook is reported using this framework. That said, we acknowledge the changing risk profile of our business. Therefore, we're providing additional disclosures to help you better understand the financial expectations as we exit the merchant power business. First, we're providing a five-year operational EBITDA outlook, as well as estimated special items. Taken together, these discloses should give you an approximation of the cash position of the business over this time period, excluding any potential amount for top off of nuclear decommissioning trust. Our current NDT top-off estimates are per limitary, as well as commercially sensitive to pursue additional VY-like transactions. They are included in our long term planning. In addition, we're pursuing other opportunities at EWC that could result in an incremental $100 million to $200 million of cash over the next five years. Second, we're providing you with a view on what remains after the end of merchant nuclear operations in 2021, namely decommissioning expense and trust income for our decommissioned nuclear assets. A few small, thoughtful assets and the Cooper contract. Turning to slide 14, we're initiating 2017 consolidated operational EPS guidance of $4.75 to $5.35 per share with a midpoint of $5.05. You'll notice that this range is narrower than previous years to reflect the change in risk profile of EWC. As of last year, the possibility exists for significant tax items at EWC in 2017 as early as the second quarter. If they do materialize, it could be valued roughly in the range of the EWC tax items recorded last year. Of course, there is also a possibility for tax reform which I will discuss in a minute which could affect the magnitude of those items. But despite the fact that resolution is only a few months away, there is still too much uncertainty to put this potential item into our guidance at this time. We're also issuing our utility, parent and other adjusted EPS guidance range of $4.25 to $4.55 per share with a $4.40 midpoint, consistent with our outlook at EEI. Both our operational and adjusted guidance assume normal weather and the current statutory income tax rate. Our $4.40 midpoint expectation in 2017 is up slightly year over year. Rate actions and sales growth are expected to offset higher nonfuel O&M and depreciation expenses. Growth from rate actions is largely attributable to rates already in effect, while projected retail sales growth in 2017 is about 1.4%, in line with our expectations at EEI. This increase includes approximately 3% industrial growth and less than a quarter of a percent increase for residential and commercial sales. Our industrial sales growth in 2017 continues to be driven by new and expansion projects. Sales to existing petroleum refiners are expected to decline year over year due to anticipated customer outages in the first half of 2017. We're projecting nonfuel O&M to be about $2.6 billion which represents a $0.45 per share increase over 2016, due primarily to higher nuclear spending. Pension and OPEC costs are expected to be slightly higher than 2016, reflecting a 4.39% discount rate. EWC's guidance midpoint is $0.65 per share. Our guidance assumptions isolate FitzPatrick which we assume is sold in the first half of this year. Average energy and capacity revenue is just over $50 per megawatt hour based on year-end prices. Another driver is decommissioning expense, partially due to a full year of decommissioning expense for Indian Point 3, as well as the liability adjustments for Indian Point and Palisades in the fourth quarter of 2016. Projected year-over-year decline due to EWC income tax expense is due to the income tax item recorded in the second quarter of 2016 and assumes no income tax benefits in 2017. Although, as I said, there could be some. Slide 15 summarizes our utility, parent and other financial outlooks which is unchanged from EEI. Our outlook reflects continuation of our strategy to grow the utility through investment that benefits customers and recovery through our normal ratemaking mechanisms. Our cash and credit metrics are summarized on slide 16. The year-end results are all within our targeted ranges. In addition, S&P recently changed Entergy and operating company outlooks to positive, while Moody's placed Entergy under review for upgrade. These actions are the result of our efforts to change our business risk profile to focus on our core utility business. As Leo said, we got a lot done in 2016 and we will continue those efforts through 2017. Now I would like to outline our current thinking on potential tax reform. Similar to what our peers have noted, given the early stage of discussions, it is premature to draw any firm conclusions. However, overall, while EWC and the parent could see an earnings impact, cash impacts there should be minimal. At the utility, we believe that impacts on investors are manageable while customers could see a benefit. As many have already discussed, there are a variety of potential outcomes, some positive and some negative depending on the result of reform efforts. We provided a framework on slide 17 for the near term effect of the major components. To be clear, this high-level view is illustrative for certain potential components and does not take into account all the complexities of how the various issues would work together. Under both high-level proposals, the House blueprint and the administration's plan, customers would have lower rates driven by the lower corporate tax rate. How much of a benefit depends on the new tax rate, how access ADIT is managed and how other items gain or lose status as deductions. If the tax rate were lowered to 20%, that would create about $2.6 billion in excess ADIT and roughly $700 million of that would be unprotected as defined under the 1986 tax act. And 100% expensing of the capital scenario in isolation would reduce rate base. But with our NOL positions, we would expect our rate base outlook to remain relatively unchanged. If interest were no longer deductible, revenue requirements would increase for customers, but we would expect no change in earnings. We also have deferred tax assets at the utility, as well as at EWC for that matter which are outside of ratemaking. These are currently valued using a 35% federal tax rate. If the corporate tax rate declines, the value of these deferred tax assets would be correspondingly lower. For example, if the tax rate were to move to 20%, this would result in a one-time reduction to those assets of approximately $580 million. About $180 million of that at the utility. However, the taxes due on future earnings would also be lower. So the net cash impact from the revaluation of these tax assets would be zero. Our EWC and parent and other segments are expected to have as reported losses in the future and a lower tax rate would provide a lower tax yield from those losses. Loss of interest deductibility would further impact the parent holding company. The magnitude would depend on whether this change would affect only interest on new debt, existing debt or net interest. Although there will be earnings impacts in these segments, we still expect to be in an NOL position for the foreseeable future. So our cash flow expectations should not be materially affected. But obviously the details matter and potential financial implications for Entergy and our customers would depend on exactly what is enacted. Our objective is to continue to work with our peers at EEI and other stakeholders to reach a final construct which is equitable, continue to closely monitor this issue and we will provide more specifics when we can. But now, the Entergy team is available to answer questions.

[Operator Instructions]. The first question is from Stephen Byrd of Morgan Stanley. Your line is open.

I wanted to go through the tax reform updates that you provided. For the reduction income tax rate from -- to 20% from 35%, is there a sense of the magnitude of the EPS impact from that? I'm thinking really more for parent and other, not as much for EWC. But is there an approximation that we should be thinking about in terms of the magnitude there?

Sure. Just from the tax rate change in isolation, it is probably $0.10 to $0.15 if you went from 35% to 20%. But, again, as I mentioned, we would still have the NOL in place. So we wouldn't expect any real cash impact near term for that.

Understood, understood. And then just as a follow-up in terms of thinking about EWC and its cash flow over time, would you mind just giving us your latest thoughts on what is the likely cash flow profile for that business through this period of time overall?

Stephen, our expectation through 2021 is that we would be able to get back to about flat from a cash flow perspective and you can see where the EBITDA is. And net of all the specialized -- and that includes all of the -- the special items include all of impairment expectations and the capital expenses and everything else. It doesn't include the ND team which I mentioned is sensitive which would take us a little further negative. But we have opportunities operationally and in some of our balance sheet items like working through the working capital and other things to bring us back to negative. And if we're successful, we can get a little higher than that.

Understood. So you would be neutral by 2021 and any guidance in terms of the cash flow position prior to 2021?

I'm sorry. Say that again, Stephen?

So it sounds like you are on track to be neutral by 2021. But prior to 2021, is there any guidance in terms of the cash flow position for EWC during 2017 through 2020?

2017 through 2020? I think this year will probably be probably a negative cash flow year because we have three refueling outages in the business and as we move forward, it would be a little bit better than that. And then as we get toward -- we will have expenses associated with severance and retention that we incur as each plant shuts down. I think most of that is detailed in the back in the appendix.

The next question is from Praful Mehta of Citigroup. Your line is open.

So a question firstly on the utility group and with the Trump growth and infrastructure plan, there seems to be lots of talk on the spend and one benefit could be your service territory. So I wanted to understand given you haven't really changed your utility group profile, if you expect to see anything and if you do, how will that translate to utility growth?

Well, I will start and then I will let Theo or Rod jump in. But our growth profile right now, particularly over the term that we give the outlook through 2019, is pretty set as it relates to the modernization of our infrastructure across all segments of the business, whether it is generation, transmission or distribution. And recall that a lot of what we're doing on the generation and transmission side is both catching up to a short position plus modernizing aging and less efficient infrastructure on both sides. So changes in growth profile that would be caused by anything that's coming up with Trump would probably not happen fast enough to have any kind of impact on our growth strategy as it stands right now. If we were to start to see things happen that -- particularly in the energy sector that started to provide a stimulus for growth where we started to see our existing customers expand or new customers show up, that would really be more of a continuation of the existing story. We've got the 3% industrial growth that we had in 2016 that we're looking at again in 2017. That just might continue that path, but that most likely would be in projects that would show outside of the 2019 timeframe.

Got you. Thank you. The next question I had was on just the decommissioning. On slide 49, you lay out the decommissioning status and just, for example, the Vermont Yankee trust assets are higher than the liability, but the sale of the asset is basically at no cost or no price. So I am trying to figure out how do you think about decommissioning funded status relative to your strategy to sell these assets to somebody else to decommission? Shouldn't there be some value in the decommissioning trust relative to the liability?

Well, that is true and I can just talk to the balance sheet items and what is going on there. I will let Bill talk to the commercial element that I think is associated with your question. The trust -- the liabilities and the trust -- well, let me say the liabilities are accreting over time. I'm not sure I understand if there's a question in there about the liabilities. But they are accreting over time and we're seeing some expense associated with that. The trust assets -- and our seed minimums are all met. The trust assets are growing at about -- we're assuming the growth is around 6.25% over time. By the way, there is a rule change in 2018 about how much income we may recognize because we moved to mark-to-market on the equity portion of our trust. But I think that we're anticipating and our current plan is profitable that we would put some money into the decommissioning trust. We talked about that. There is some we're expecting to put in for both Palisades and Indian Point, but the Pilgrim trust is pretty well funded at this point, as you can see in that table. It's at $960 million. So I will turn it over to Bill to allow him to talk a little bit about the commercial implications of where the trusts are and how we might disposition them.

Yes, I mean essentially -- if you take the VY deal, the way it was looked at is you've got the -- obviously we've got our projected liabilities and you would compare that to what the NDT is. What we're looking at is folks who have the capability to do this on a much more aggressive schedule and a much more efficient schedule. So while there could be a small top-off with something like VY, that has all been taken into consideration in the negotiation of the commercial deal. If you look at what we're looking at in terms of the transaction with Pilgrim and Palisades, you're looking at one which is overfunded, one which they would look at as being underfunded, but they have the ability to look at that on a combination basis and that's why we packaged those together to do some -- do preliminary due diligence to look at doing a very similar transaction.

The next question is from Michael Lapides of Goldman Sachs. Your line is open.

Couple of questions. First of all, Leo, you commented briefly about opportunities in terms of rightsizing the corporate organization. Can you give us a little bit of detail about that in terms of how big of an opportunity from a cost saves prospective and kind of a timeline that -- when -- how long do you think it would take you to achieve and when do you think you'd be at a more normal run rate?

And I guess we're at a normal run rate right now and if you think about it, Michael, we're actually in the -- and I was talking that section of my script around the nuclear corporate organizations, as well as the corporate organization as it relates to overhead inside EWC. We're -- as we have said here over the course of the last several months, we're running somewhat of a lean shop strategy. So we've got that going for us to begin with as we start to ramp up to get more towards industry benchmarks at the same point in time the EWC is shutting down. The whole point there is we made the decision to shut down Vermont Yankee in 2014. We started looking at the issue in terms of rightsizing the organization then with an eye towards recognizing that a lot of this stuff has been in the works for a long time. From 2014 to 2021, we had a seven-year period where the plants will sequentially go away and we have already started working on that organizational size. The question comes up from time to time about the overhead as if it's an issue. It is just not. That was the point I was trying to make.

Okay. Super helpful. One, if you don't mind one quick follow-up. At what point -- like the deal with the state of New York regarding the retirement of Indian Point and the planned retirement is 2020, 2021, but there's the potential the plant could live out to 2024, 2025. At what point would you know? How does the decision-making process happen in terms of the state decides or some combination of other and how early do you need to know? Like at some point, refueling decisions or other similar decisions have to get made if the state decides to play it and wants to operate beyond 2020.

Yes, Michael. This is Bill. So, really, the responsibility for the resource need will fall with the New York ISO. So what you need to be watching for is they will do an updated load and resource study probably the second half of this year where they will start to incorporate the shutdown of Indian Point, as well as any other additional resources that may be coming online. So that will start to paint the picture of what 2021 looks like. And so that will look at overall capacity needs, as well as specific reliability needs in terms of system security. And then that will be updated on an annualized basis. What we're going to need to be watching for -- and the state will be watching for -- is that we will have to likely make a decision sometime in the second half of 2018 if we want to extend the operations of that unit. And then we would have to enter into negotiations with New York State because, remember, that is a mutual option. We both have to agree, so obviously they have to recognize the need for reliability and we have to ensure that we fully recover all of our costs.

Got it. So, in other words, post 2020, if there is in operation, it is likely under some form of PPA or some other agreement that probably looks, smells and acts a little bit like an RMR because it is actually needed for reliability purposes?

Yes, sir. That's correct.

The next question is from Steve Fleishman of Wolfe Research. Your line is open.

Just didn't hear much of an update on the nuclear improvement program. Could you just maybe talk about how that is progressing? Any update on the cost levels that you gave before those? Should we just assume those are the same? And just how do you plan to update us on how that is going, kind of going in the future?

Steve, I would say that right now there is no update on the costs. You should assume that they are what we have outlined in originally and continue in the numbers today. As far as updates, right now the nuclear strategic plan is all wrapped up in our expenditures. They are in all of the guidance that you have got right now. We're beginning to see improvements in the operations of the facilities. So I think it would just be on a regular basis and probably more by exception than anything else as far as what we would be updating you on. As far as where it sits in the regulatory process, as Drew mentioned, everything that we've got going on at the moment is just running through the normal regulatory processes that we've already got in place, particularly given the fact that we've put some pretty good mechanisms in place over the course of the last several years to adjust things on a regular basis. And, as you know, we're in the process of reviewing some of those costs that were in the 2017 -- or the 2016 filed Formula Rate Plan. There is no procedure in Arkansas. There is no procedural schedule for that at the moment. We would anticipate that that will get done if not before, at least within the same context as when we make the next filing of the FRP in Arkansas.

That last point is that you are referring to the small prudence thing that was opened up on the last -- on your settlement on the filing there?

Really what that is the fact of the matter is the process is a brand-new process, the Formula Rate Plan with the forward-looking test year. And so we're just going through the process and the Commission just wants to make sure they got it right, that's all.

Okay. But, operationally, do you feel that the nuclear performance improvements are going on plan? Ignoring cost, just operationally. Okay.

Both. Both. Not ignoring costs. Everything is on plan.

Everything is on plan. Okay. One other question. Just to clarify, I know you give the three-year utility guidance, but the 5% to 7% that you mentioned at the beginning of the call and I think you said something about that being some years above, some years below, what are you now using as the base for that 5% to 7%?

Well, we're still -- this is true. We're still thinking about, I guess either place you could base it off of where we're for 2016 or if you went back to an adjusted view of 2015, it would be a little bit higher than that. But either way, I think our objective is to try and get in that range each year, although at times it will be a little lumpier than most. So I think it doesn't really matter, Steve, where you would start from is our objective, but we should be able to get in there over time.

Right. Because obviously 2016 -- 2017 is below, but then I think 2019 is well above based on your guidance. So that's what you mean by the back and forth. That's kind of --

That's right. That's right. If you recall, last year before we put the nuclear costs in, we were expecting to be more steady in that. And now we've got the nuclear costs in. But as time moves forward, we would expect to get recovery of those costs and we would get back on track to our original plan. So that's why 2019 is still where we would put it, I guess, a year ago. And the other, 2017 and 2018 moved down slightly, but we expect to get back on track.

Okay. One last thing, Leo. I think you are on the EEI tax committee -- the tax reform committee. Just maybe any just more color on how we should think about tax reform given the discussions that you have had and just where it might go?

Well, I mean I think, as Drew mentioned and I think everybody else in the industry has probably mentioned, it's pretty early in the process as it relates to what's going on in the dynamics. Then I think what will be the most determinative over time are the interplays of all these different items, not only how they impact our industry, but others as well. But I would say that the dialogue that the industry has had with folks at the White House and on the Hill has been constructive. I think the history the industry has in terms of the way our rate regulated regimes work is understood by a large number of folks. And so I think that we're in a position where we're talking to the right people. We're having a lot of dialogue. Everybody's doing it with a pretty aligned point of view and we hope that things constructive come about because of it. And, again, the nature of our business being rate regulated certainly does provide some nuances that are important to us. It may not be important to other industries, but that has been provided for in the past when there's been tax law changes. And, also, the fact that we're rate regulated gives us some ability to make sure that we have rational regulation around the way the law turns out, just like we do today in terms of normalization practices and things like that.

The next question is from Julien Dumoulin-Smith of UBS. Your line is open.

Just wanted to follow up a little bit on some of the last questions here. Can you talk a little bit about some of the costs associated with EWC and how that might get allocated out in the future vis-a-vis the regulatory business? It might somewhat dovetail with your talk about spreading down costs overall, but just wanted to understand how that process plays out. Then I've got a follow-up.

Well, the way the process falls out is we have corporate organizations that allocate costs to EWC. Again, a seven-year period over which plants go away one at a time to be able to manage that process. We have already begun managing it on Vermont Yankee which is over -- we have already gone through the process of shutting down Vermont Yankee. We have already managed it as it relates to the Rhode Island plant which we have already sold. We have already managed it as it relates to the wind assets which we have already sold. We will manage it as it relates to Fitzpatrick which will be sold this year. We will manage it as it relates to Palisades which will shut down in 2018 and Pilgrim in 2019 and then in 2020 and 2021. It is just -- it's a process that has to be managed as it relates to what those costs are. But to right-size the organization over a seven-year period is something that we will be able to manage. So I guess, Julien, it's just not an issue of significance that I would say.

I can throw in some modeling elements, too. This is Drew. From a modeling perspective, when we started we had about $35 million per plant of overheads. And we've had direct costs for each plan. I don't have the percentages in front of me right now for each plant going back to Vermont Yankee. But each one of those is going to peel off as those plants are shut down. And I think there may be about 40% or so left that is indirect costs and those are the ones that we will have to work down over time that Leo is talking about and we've got a really good headstart. So I think at the end of the day, what we're going to end up with is the costs that are reasonable and necessary to operate the business going forward. And that should make sure that we have reliable and safe operations of our nuclear plant. So I think that's the -- from a modeling perspective, those are the things that you would look at as it winds down over time.

But just to follow up here just quickly, you talked about the non-nuclear assets and Cooper contract being generally earnings neutral. But just outside of that on a go forward basis, 2021 onwards, you're talking about ramping down the costs. There should be no other costs outside of decommissioning and NDT that need -- that are ongoing. The remainder is either cut and/or allocated out and largely there is no other cost EPS that you are going to [indiscernible] the business.

That's correct. And in the slide in the front, we talk about the NDT earnings and the decommissioning expense that is on slide 13. And you see initially, there's a pretty big gap between the decommissioning expense and the NDT earnings. I think one thing that is important to know there is, for the earnings part of that, we're assuming that we're realizing only about 45% of 6.25% of the earnings in 2017. And so it is effectively showing you a 3% return on your NDT earnings. The rest of it is going straight to the balance sheet. And then in 2018, we will have an accounting change which would cause us to mark-to-market much more of the equity portion of the trust. And so our return will go up substantially, not from 6.25%. It's going to stay there, but we will just acknowledge more of that in the income statement which will close that gap. And then over time, if we're successful, of course, in doing more VY-like type transactions, that should shrink as well.

Sorry. Just a quick follow-up on Arkansas Nuclear One, what is the timeline for filing for and/or process to just get recovery on the regulated expense there? Just a quick one.

I think as it relates to -- there is no filing around Arkansas Nuclear One. There is a Formula Rate Plan filing that we had, the one that is already in place. There is the review that is going on where there is no procedural scheduled for yet and then we will just make another Formula Rate Plan filing. Is that what you're asking about, the recovery?

Yes, I was presuming it was part of the FRP, but I wasn't 100% sure.

Yes, yes. It was part of the FRP as it relates to the rates that are in effect today and that's where we're going through the process where the Commission wanted to go back and review some more information on those costs. There is no procedural schedule around that at the moment, but then there will be another FRP filing this summer. And so there will be more costs associated with every -- the whole business, including ANO, at that point in time. So we would anticipate that the one that is out there today will either get a procedural schedule before that time or it will get wrapped up at the same point in time. That's the next step --

The next question is from Jonathan Arnold of Deutsche Bank. Your line is open.

Hey, Leo. Actually I wanted to clarify just on the question you were just talking about. Firstly, are those costs likely to get recovered in 2017 under the 16 FRP if they wrap it up sooner or are they sort of -- I think they set them aside, so they wanted more information, but would it be retroactive to the beginning of the year if decided on a more timely basis than next year's filing?

They are in rates now.

Okay. So the question is whether they stay in or you are collecting it today?

Correct. They are just reviewing them. They didn't set them aside out of the pricing. They are all being recovered today.

Great. Okay. Thank you for that. And secondly, I know you gave a number on what you thought the potential utility or parent and other exposure to tax reform at a lower tax rate would be. If you layered in losing interest deductibility as well, in that kind of scenario, would you guys still see yourselves in the 5% to 7% range? Does it move you in the range? What's the -- how should we think about that kind of incremental scenario?

Jonathan, this is Drew. Clearly we have a fairly narrow range out there for utility, parent and other. And if you were to layer on the change in tax rate and the interest expense, that -- assuming that was the scenario you ended up with, it would probably move you close to the bottom of that range. It's too early to tell about what we decide to do with the ranges at this point. But if you just were to take those two things in isolation, that would probably bring it to the bottom of the range. But it's not clear yet that we would move the range or change our guidance or anything at this point.

Thank you and at this time I would like to turn the call back over to David Borde for closing remarks.

Thank you, Latoya and thanks to all for participating this morning. Before we close, we would remind you to refer to our release and website for Safe Harbor and Regulation G compliance statements. 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. Please note that events that occur prior to the date of our 10-K filing and provide additional evidence of conditions that existed at the date of the balance sheet would be reflected in our financial statements in accordance with generally accepted accounting principles. The call was recorded and can be accessed on our website or by dialing 855-859-2056, confirmation ID 52887956. The telephone replay will be available until February 22 and this concludes our call. Thank you.

Thank you. Ladies and gentlemen, this concludes today's conference. You may now disconnect. Good day.