Entergy Corporation (ETR) Q3 2014 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the Entergy Corporation Third Quarter 2014 Earnings Release Conference Call. Today's call is being recorded. At this time, for introductions and opening comments, I would like to turn the call over to Vice President of Investor Relations, Ms. Paula Waters. Please go ahead, ma'am.

Good morning, and thank you for joining us. We'll begin today with comments from Entergy's Chairman and CEO, Leo Denault; and then Drew Marsh, our CFO, will review results. [Operator Instructions] In today's call, management will make certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to a number of risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Additional information concerning these risks and uncertainties is included in the company's SEC filings. Now I'll turn the call over to Leo.

Thank you, Paula, and good morning, everyone. As many of you know, the Annual Edison Electric Institute Financial Conference is just around the corner, so we'll try to keep our comments today relatively brief and save longer-term and more strategic updates for our meetings in Dallas. I'll start with the bottom line. Our plan and strategy remains sound and our progress against that strategy is both measurable and clear. As it often does, progress incurs a cost, and we saw little of this in the third quarter. But in fact, overall performance for the company was squarely in line with expectations. We're pleased to report that the utility posted its fifth straight quarter-over-quarter of industrial sales growth and the second straight quarter over 5%, exceeding our expectations for the year. Our nuclear plants operated well. We had fewer unplanned outage days, posting a 90% capacity factor at EWC. Vermont Yankee entered its final months of operation, and as difficult as that decision was, we are more confident than ever that it was the right one. We also made progress on our rate case in Mississippi, reaching a constructive settlement with the Mississippi Public Utilities Staff, one which aligns customer regulator and state objectives with our own. Let me elaborate a bit on all fronts. As I just mentioned, utility posted quarter-over-quarter industrial sales growth of more than 5%. As you've heard us say many times, this kind of growth isn't by happenstance. At Entergy, we're doing everything we can to drive it. Doing so requires many things but one is having strong working relationships with the people who serve our utility states, certainly our regulators, but also state and local policymakers, economic development officials and our customers themselves. Together, we've been able to find solutions that work for everyone. For example, in Louisiana, this past August, we completed cost recovery for damage caused by Hurricane Isaac. We were pleased that the efficient structure by which we did so allowed us to share the savings with our customers. Cost recovery of Ninemile 6 begins when the unit comes online through a formula rate plan adjustment mechanism, which was part of the Entergy Louisiana rate case settlement approved last year. We are pleased that the plant, which will allow us to better meet the state's growing demand is scheduled to be completed early, before the end of the year, and under budget. Partly as a result of actions like these, we are in a good position to make the kind of investment our states need to support economic growth, even as we keep the cost of power low. The Mississippi rate case is another great example. As I just mentioned, last month, we reached a settlement. It's true that this settlement requires us to forgo recovery of costs associated with the development of a new nuclear option at Grand Gulf. It would also allow Entergy Mississippi to maintain a competitive ROE, better meet anticipated demand and continue to attract capital on reasonable terms. Perhaps, most importantly, by developing the state's transmission infrastructure, we believe it will help Mississippi attract industry and create new high-paying jobs. The MPSC hasn't approved the settlement yet and we don't want to get ahead of either ourselves or the commission, but we think it's reasonable and balanced and hope our commissioners will agree. We expect a decision in December. Driving growth in our service territory also requires operational and financial discipline. So in the third quarter, we saw progress on another important front. In a move designed to attract industry and jobs to the state, Entergy Louisiana and Entergy Gulf States Louisiana asked the Louisiana Public Service Commission for permission to become a single utility. Initiatives are different, but as in Mississippi, combining the 2 companies will make it easier for us to make needed investments in Louisiana power infrastructure, MBA-expanded rate options to sustain and propel the state's industrial renaissance. It will, for example, allow us to streamline investment by creating a stronger balance sheet. It will improve our ability to attract capital and it will give us more flexibility. By 2019, the 2 companies expect up to 1,600 megawatts in industrial load growth. Both are already making substantial investments to meet demand and replace aging infrastructure, which, together with other ongoing capital needs, will require more than $5 billion in capital investment in generation, transmission and distribution by then. Our business combination proposal to the LPSC reflects significant input from stakeholders across the states, in particular, our industrial customers. And we are pleased to see positive feedback from the market. As some of you may have seen, on October 10, Moody's issued a report saying this business combination is credit positive, reinforcing our case. Let me give you just a couple of other highlights from the quarter. Entergy Texas filed for nearly $7 million in revenue requirements associated with incremental distribution investment under a rider, becoming the first Texas utility to do so since legislation was passed in 2011. The decision is expected early next year. Some of our biggest customers also made progress. Big River steel in Arkansas completed financing and broke ground in September. Cameron LNG in Louisiana, also had its groundbreaking just last month. And last week, Sasol announced their final investment decision on the $8 billion investment in the Lake Charles Louisiana area. Entergy Wholesale Commodities operational performance was once again strong. As I noted earlier, our plants ran well. For example, the extended outage at Fitzpatrick came in below the shorter end of our expectations. And at VY, our employees have kept the plant running for nearly 670 consecutive days now. Remarkably, they are on their fourth breaker-to-breaker run. And in fact, all of our EWC plants play important roles in their respective regions and communities. Pilgrim provides fuel diversity in a part of the country, where infrastructure constraints are most severe. Without the on-site fuel benefits it provides, New England would be even more vulnerable to price volatility. As I noted a minute ago, Fitzpatrick completed its refueling and maintenance outage, a very complex undertaking, in just 44 days. A great example of what happens when a solid plan comes together with our employees' tremendous dedication. And with respect to Palisades, although it has a PPA through early 2022, it's long-term post-PPA outlook is improving. For example, the MISO region, where it is located, has recently seen 3 gigawatts of coal-fired generation retire and another 5-gigawatts is scheduled to retire in the next few years. So keeping highly reliable sources of baseload power like Palisades online will become even more important. Let me now to Vermont Yankee, since I know a lot of you will have questions about its closure. As you may know, in September, the plant began its coast down to permanent shutdown, which will occur at the end of the year. Last month, as we said we would, Entergy delivered a first-of-its-kind site assessment study to the state of Vermont. While decommissioning costs articulated in the study are higher than earlier estimates, they are more precise, allowing us to develop plans with much more certainty. Under the terms of our agreement with the state of Vermont, we had said we would periodically evaluate the cost of decommissioning, together with the trust, to determine when we would have the resources needed to begin major activities. Using conservative estimates about growth of the trust, we think it will have enough money to begin such activities in the next 25 to 35 years. At this point, we don't expect to add funds into the trust to meet NRC financial assurance requirements. The decision to close the plant was tough, it came with certain risks and challenges, but we planned to meet and manage these services thoughtfully, which I think we have. For example, we obtained an order from the Vermont Public Service Board authorizing VY to operate through the end of the fourth quarter. We targeted elimination of overhead associated with the plant and we placed the majority of Vermont Yankee employees wanting to stay with the company in new roles. It's worth reiterating that this was the right decision. First, we now see an incremental benefit of shutdown versus continued operation of an additional $50 million through 2017. And second, despite the upturn in forward power prices in New England over the past year, the economics for VY would still not be sustainable in the long run. Forward capacity market improvement through the newly defined constrained zones that spans Southeastern Massachusetts and Rhode Island, is improving the revenue outlook at Pilgrim and RISEC, but VY would not have benefited from this new capacity zone. Indian Point also continues to operate safely and reliably. That plant's importance to the regional electric grid was recently reaffirmed by the New York ISO, which confirmed that, and I quote, "Significant violations of transmission security and resource adequacy criteria would occur in 2016 if the Indian Point plant were to be retired as of that time." As most of you know, the state of New York is currently scheduled to determine Indian Point's compliance with the coastal zone management act or CZMA by year-end. To date, we have submitted thousands of pages of information demonstrating that Indian Point operations are consistent with state coastal policies. There's at least one more environmental impact study the NRC has said it would submit likely late next year. And we think that, that study would be important to complete the record. We also have 2 other paths for resolution to establish that the NRC does not need this consistency determination to issue a renewed license. As we have made clear, we believe that it does not. Regardless of the outcome, we expect appeals to be filed. It is also possible that we will take other procedural steps to support our position. With that said, we don't expect license renewal to be decided any time before 2018. I think we can say with some assurance, that while Entergy may differ with some on the future of Indian Point, we can all agree that what it offers: reliable baseload power, high paying jobs, and stable prices, that these are attributes that benefit Westchester County, New York City and the state of New York, as a whole. And that's why we say that Indian Point is and will remain a critical part of the generation mix of New York and why we are committed to ensuring its continued safe operation. Finally, as we look to winter, infrastructure constraints in the Northeast are expected to continue to challenge the region at least for the foreseeable future. As we've said before, various changes in the structure are required to ensure these markets function properly, not only with respect to reliability, but also, economic and environmental sustainability. Building new capacity is one option, but it can be expensive to build any kind of new energy infrastructure, whether pipelines or wind farms in the North East. This past quarter, Massachusetts stakeholders would choose support for proposal to recover costs for new gas pipeline capacity via a FERC-regulated electric transmission tariff. We believe that recovery for this type of investment is better addressed through competitive markets and market-based signals and mechanisms, as opposed to being subsidized through a transmission tariff. Although forward markets indicate these constraints will be partially addressed in the coming years, it's unclear when or if projects will actually get built. In any case, it will take time. So we expect more of these markets to continue to be premium markets for the foreseeable future, especially during the winter. Before I conclude, I'd like to note that next week, America celebrates Veterans Day in honor of the generations of men and women whose service and sacrificed embody the ideals, upon which, this country was founded nearly 2.5 centuries ago. We live in a world in need of heroes. But at Entergy, we get to work with nearly 2,000 people, who when their country called, they said send me. They work at our nuclear plants and at utility operations, they are line men, engineers and accountants. They sit across the hall or across the table, and we are fortunate to call them colleagues, bosses and mentors. Words may never be enough, but on behalf of this company, to those who served and those who continue to serve and to their families, let me just say thank you. So that concludes the overview of the third quarter. We'll be seeing many of you in a week or so, and I know Drew will expand on this. So I'll just say that at EEI, we plan to address what Entergy is doing to meet the needs of our stakeholders, from adding new capacity at the utility to maximizing value at EWC. Some of you know that I've been in this business for more than 30 years. It's never easy going. But for all of us here, there has never been more an exciting time. So today at Entergy, we can say that our fundamentals are strong, the path forward is clear and most importantly, our long-term value proposition remains intact. Let me now turn the call over to Drew. Drew?

Thank you, Leo, and good morning, everyone. Today, I will review the financial results for the quarter, provide highlights on how we see 2015 shaping up and preview what we'll discuss at the EEI. Starting with Slide 2. Our third quarter results for the current and prior years are shown on as-reported and an operational basis. Operational earnings per share were $1.68 in the third quarter 2014 compared to $2.41 in 2013. Operational results excluded special items from the decision to close Vermont Yankee, HCM implementation and the transmission spin-merge effort last year. Turning to operational results by line of business on Slide 3. Entergy's operational earnings decreased quarter-over-quarter. One key driver was income tax expense, which affected each of the segments. The effective income tax rate was approximately 40% in the third quarter of this year compared to approximately 25% in the comparable period last year. Details underlying the income tax expense variance are discussed in Appendix A of our earnings release. Moving to the segments. At the utility, operational earnings per share were $1.72 in the current period compared to $2.04 in the prior period. Utility net revenue was higher than last year, led by weather-adjusted retail sales growth for the quarter at 2%. Once again, the industrial customer class had the strongest gains at 5.3%. And as Leo noted, this is the fifth quarter in a row for positive industrial growth, which was due largely to expansions in the chemicals, refining and primary metals segments as well as growth from small industrial customers. Substantially, all of the growth occurred in Louisiana and Texas. The quarterly net revenue increase also reflected higher price, resulting of rate actions, a portion of which was offset by other line items. Sales growth was partially offset by a very mild summer, leading to negative $0.11 of weather. Also, OEM was higher quarter-over-quarter. Benefits from our ongoing cost management efforts were offset by nuclear spending to improve operations as well as other items, some of which were offset elsewhere in the income statement. As Leo noted, utility results were also affected by a charge related to the proposed settlement of Entergy Mississippi's general rate case. The charge reduced current period earnings by $0.23 per share. Moving on to EWC, where operational earnings were $0.23 per share and were lower than the $0.46 earned a year ago, primarily driven by income tax benefits in the third quarter of 2013, as well as the depreciation change we have discussed in the past. EWC EBITDA for the quarter summarized on Slide 4, was $165 million, the same as last year. EWC's O&M was lower compared to the same quarter last year, and driven by our cost-management efforts. While the overall net revenue variance was not significant, there were a few important items within that line item. Third quarter results reflected 37 refueling outage days for the Fitzpatrick plant. You may recall that, that outage was originally planned for the fourth quarter. The net revenue effect of the refueling outage was partially offset by an approximately 40% improvement in unplanned outage days quarter-over-quarter and a higher average realized price of the nuclear fleet quarter-over-quarter. Moving on to operating cash flow shown on Slide 5. OCF was around $1.4 billion in the current quarter, up nearly $300 million from 2013. The primary driver was $310 million in securitization proceeds to reimburse Hurricane Isaac costs. Before we move on, Slide 6 highlights our credit metrics compared to a year ago. Let me just take a moment to note that we've seen credit improvements across several metrics, which shows progress in the right direction. I'll now turn to forward-looking information. Today, we affirmed our 2014 operational earnings per guidance of $5.55 to $6.75. Recall that the midpoint was revised upward in April this year by approximately 23% to $6.15 per share from the original guidance midpoint. Current expectations continue to be on track for the -- round the midpoint of our range, but for the unplanned charges associated with the Mississippi settlement. Similarly, as with that charge, expectations for the utility continues to be around the $5 midpoint we discussed in April. Next week, we'll see many of you at the EEI's annual financial conference. In advance of the conference, we surveyed some of you in the investment community to get opinions on where we can enhance our communications. One specific point of feedback was on our practice of pre-releasing earnings. It was clear that most of you do not find this practice useful. Therefore, going forward, we will discontinue it. You also provided feedback on what you wanted to hear at EEI. At the conference, and on Slide 7, we'll be prepared to talk about 2015. As you know, we will issue our official guidance with supporting details on our fourth quarter call. The good news is that our current expectations and the street consensus appeared generally aligned, based on commodity prices, as of September 30 and other factors, which I'll discuss now, with more details to follow next week. For the utility, we expect weather-adjusted sales growth in the range of 3% to 3.5% to be a significant driver. Industrial sales are expected to be the major component, increasing approximately 6%. We don't expect actions to have significant earnings impact. For EWC revenues, the capacity in generation table, the Table 7 in our release, provides details underlying our revenue assumptions. We also provide our current EBITDA estimate, assuming market prices as of September 30 in the accompanying slides. Because New York's Lower Hudson Valley capacity market is illiquid, the table, once again, utilizes point of view pricing for LHV. Next year, the assumed average price is approximately $6 per kW month per LHV. Staying with EWC, the closure of the Vermont Yankee will affect year-on-year results. This year, VY is expected to contribute approximately $55 million to EWC earnings and approximately $165 million to operational adjusted EBITDA. Keep in mind the year-over-year impact as the VY closure goes beyond simply removing 2014 earnings. To this end, EEI materials will include information on line item drivers for VY. Updates on other typical drivers will include interest expense at the utility and depreciation in both businesses, resulting from capital investments. Non-fuel O&M will also be a driver for 2015 and one component is pension expense. We will not know the final pension assumptions, including the discount rate, until early next year. For now, we are assuming a pension and OPEB expense increase of approximately $70 million, which includes updated actuarial and experience studies as well as a discount rate of 4.75%. We also expect our overall and utility effective income tax rates to be in the range of 32% to 34% compared to approximately 37% overall this year. Beyond 2015, we will discuss the longer-term view, and we'll roll forward many of our Analyst Day financial outlooks and aspirations by 1 year. Finally, for content, we'll cover the utilities growth story, which includes robust growth at industrial demand as well as the case for investment opportunities in generation, transmission and potentially natural gas reserves. For EWC, we'll focus on its long-term strategy as well as our efforts to improve clarity for Indian Point. We look forward to seeing you at EEI, where you know, we'll have a lot to talk about. And now, the Entergy team is available for questions.

[Operator Instructions] And we will take our first question from Paul Patterson with Glenrock Associates.

Just to sort of a follow-up on the EEI PD with the Vermont Yankee decommissioning. How should we think about the ongoing expense item associated with that? Can you give us a little bit more before EEI?

Yes. For the next couple of years, we expect it to be about a negative $0.20 to $0.25. And then after that, it would trail off to about -- excuse me, millions -- sorry, $20 million to $25 million of net income impact, and that trails off to about $12 million.

I'm sorry...

There are several ups and downs in there. We'll have the line item drivers for you on a slide at EEI.

Okay. And then, does the change in the Vermont Yankee decommissioning cost, in total, have any impact on what you guys are thinking about with your other plants? And I recall you guys taking some significant tax positions associated with that. Could those change as well as a result of your update updated Vermont Yankee decommissioning study?

I'll answer the second question first. No, it doesn't affect our tax positions. And on the first question, we did learn quite a bit, because we did the detailed study of Vermont Yankee. But it doesn't change our current expectations for funding or expense at either -- or any of our remaining of nuclear facilities.

And we will take our next question from Julien Dumoulin-Smith with UBS.

So quick question here, as you're thinking about New England and all the latest developments, what's your fundamental view '15 through '17 on the forward curve? Do you think or is it your expectation to continue to use options to leave some upside there?

Yes, Julian, we plan to continue to use the same hedging strategy we have in the past, keeping in mind that there are certain limitations, depending on what the market offers. But -- so we continue to use a number of structured products. Those structured products change -- a number of counter-parties change, but we're still working to maintain that optionality in the book.

Great. And then looking at the capacity side of the equation there, obviously, we've seen a few new newbuild or potential newbuild announcements in the last few months. How has that, if at all, changed your expectations or pricing in the subsequent auction? And then, specifically, are you expecting the SEMA region to breakout separately? And do you have a price expectation therein?

Yes. So we have seen more a lot more activity in terms of proposed projects. Our expectations on pricing associated with capacity really hasn't changed. We think that for the rest of pool in England, that's still somewhere around an $11 cone. We do expect ISO New England to put in place the SEMA pricing zone that has -- will hopefully be resolved by the end of this year. As it relates to pricing in that specific zone, where RISE and Pilgrim reside, that will depend on the amount of capacity that's actually bid. I think you're familiar with the rules up there, in terms of limitations on capacity pricing for insufficient offers, that type of thing. But we are somewhat bullish in that area, but it's going to -- the final pricing will depend on the amount of capacity actually bid in FCA 9.

Great. Just to be make sure I heard you correctly, there's a potential for an insufficient capacity in SEMA?

Yes. So with rest of pool, there's a slope demand curve. I don't believe that slope demand curve has been implemented in SEMA, so we would revert back to the insufficient competition, which would go back to net cone.

And we will take our next question from Neel Mitra with Tudor, Pickering. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I had a question on the New England capacity market as well. Obviously, of the winter reliability program, which is kind of a temporary fix, do you see anything progressing, going forward, similar to what PJM is doing with the capacity performance proposal to make sure that there's adequate fuel for the plants in that region or in the winter?

Well, Neel, I think, we were hopeful to see that actually change for this winter. Frankly, we were disappointed with the fact that they rolled the existing plan forward a year. But I believe, FERC gave made some pretty clear guidance on that issue for the '15, '16 winter timeframe needs to be addressed. So we are hopeful that we see some progress there that we move beyond something such as the oil backup reliability to a more market-based approach, which properly values all resources that have adequate fuel supply. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. And then, at your Analyst Day, you laid out the kind of the lack of pipeline capacity going into New England. Has your view changed with maybe some of the bigger projects that are being proposed out that would come on late 2018, early 2019? Or do think that there's still a long shot for a lot of projects that would actually bring gas into New England?

I don't think our overall point of view has changed. You've got the Spectra Northeast Utilities JV, you've got the Northeast Energy direct. And you have to keep in mind that those have not been subscribed. So we believe that, that could be a challenge, just given overall economics. So we believe, at least in the foreseeable future, nothing is going to change significantly. We'll continue to see a lot of volatility up in those markets. And at this point, those projects that have been proposed are very questionable, from our perspective.

And we would take our next question from Stephen Byrd of Morgan Stanley.

I wanted to discuss transmission growth as you join MISO. I wonder if you could just talk at a high-level. I know this is an evolving situation, but are there certain signposts or upcoming things we should be looking for to get a better sense of what's really going to be required to integrate your system into MISO?

Stephen, I'll start and I'll let Theo kind of jump in with the details. From a transmission standpoint, we've -- and obviously, we'll be giving updated investment opportunities and everything when we get out next week, but we still see, based on our internal business, which is from all reliability projects, projects associated with the industrial growth and demand that we see down here, projects that will be required when we build or acquire new generating capacity and everything, obviously, we've had a significant uptick over the last several years on our transmission investments and we would think that continues. And that is before you get into the idea of what we've got now that we're in MISO. And there's really 2 broad areas where, at least, where we see things, we're already seeing some things that are there because now we've got a bigger footprint and more generating capacity we have access to that we can count on, given the way it's dispatched in MISO, plus, then, there'll be the Order 1,000 issues and then, even things that show up to integrate us with -- or MISO with the region. As far as -- so we do see that there are some opportunities out there that we're already looking at, but more to come on that front. Obviously, some of those are farther out in the picture than near-term investments we have in our own system, which are pretty substantial. And Theo, I don't know if you want to add to that?

Well, I mean, yes, I'll add a little bit to that, Leo. I mean, you made a comment in terms of the path about our transmission spending. I mean, if you look back in 2010, we were probably spending somewhere around $280 million or so in transmission. I think if you go forward, we've kind of more than doubled that. So obviously, our level of transmission spending is increasing, as it relates to MISO. MISO does have the study out around their voltage and local reliability and mitigation that could potentially drive transmission investment as well. We've gone through the MTEP process for 2014. There were some projects that were identified within that process. That process will also occur in 2015, and you could see some projects that were proposed in 2014 become part of the 2015 MTEP process as well. But yes, I think one of the major drivers for us may not be so much MISO, but as Leo mentioned, just the transmission associated with the economic development opportunity that we have. If you look at our EGSL, ELL business combination filing and some of the details and how we talk about some of the opportunities that might require transmission investment within the context of that. So while there could be opportunities relative to MISO, I think we see our transmission opportunities somewhat broader than that.

That's very helpful. I wanted to shift gears to Indian Point. Of late, has there been a dialogue between Entergy and the state over approaches that can be taking compromises, et cetera? Or is this playing out primarily in the legal arena?

Stephen, we've had a number of discussions with various representatives of the state, but obviously, we continue to aggressively pursue our legal paths. But I think, that's all I can say at this point in time.

And we would take our next question from Dan Eggers with Credit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: You had another really good quarter on the industrial demand side, even relative to probably expectation to spring. How much of that is -- you kind of maybe situational timing, relative to what you would've expected. And at what point in time are you guys going to be in a spot to reconsider that underlying growth trend?

Dan, I'm not -- this is Theo. I'm not sure I understand your question in terms of situational. But yes, I think, when we look at where we are, from an industrial growth perspective in the quarter, I think it's coming from where we would somewhat expect it to. It's primarily coming from expansions in the kind of the petrochemical refinery area. And that's what we really expect it to be at this point in time. If you look at one of the slides, I'm not sure exactly which number it is, on the 1,700 megawatts we laid out at Analyst Day, I think in terms of completed and signed projects, we're about 300 megawatts. And so we're really just getting started in that regard. As it relates maybe to the second part of your question, in terms of maybe changing expectations, I think, we, right now, we still feel good about the $3.05 to $3.75 earnings growth through 2016. And while we continue to firm that up in terms of what we see, as it relates to the 1,700 megawatts, obviously, we see movements in, we see movements out. We're still comfortable with that. The question of multiplier effect, the issue of potential energy efficiency impacts on the underlying intrinsic growth, we still think about. But with the puts and takes and ins and outs, I think from our perspective, we're still comfortable with the $3.05 to $3.75 at this point in time. Daniel L. Eggers - Crédit Suisse AG, Research Division: And I guess, correlated to that is the residential load is -- hasn't been nearly as impactful, right? And when do you guys see -- or do you see the prospects for kind of the multiplier effect starting to show up in numbers, as these projects get done? And what should we be watching from the outside to see more uptake on that side?

I don't think we're really seeing the impacts of the multiplier effect at this point. Again, I mean, if you look at the slide, we've only got 300 of 1,700 megawatts that are signed and completed. I think, if you look at, historically, other areas where they've experienced, I wouldn't say this type of industrial growth, because I'm not sure anybody's experienced it in recent history, but some type of industrial growth. Generally, the lag that you see, in terms of multiplier effect, happens maybe within a year, couple of years, 1.5 years after, you really start to see the impact of the industrial growth. So we're not quite there yet, and I think that's still to come. We'll see more signed than completed projects as we move forward into '15 and '16. And so I think you'll start to see the impacts of kind of trickle-down the multiplier effect, more so '15, '16, time frame. But again, we're also going to continue to see impacts of our energy efficiency programs, as those are broad, within our service area.

And we would take our next question from Steven Fleishman at Wolfe Research.

Question, just on -- and thinking about the huge industrial growth. When you're signing contracts up with Cameron or Sasol or these different large customers, are you -- is it mainly a demand fixed payment no matter how much the facility runs? Just thinking about -- we don't know if, one day, these plants, if conditions could change, they may not run much or less. Just how are you kind of locking in the risk of that?

This is Theo. I mean, clearly, there is a demand element to most of our larger industrial contracts, and that's probably about as far as I'll go as it relates to that. A lot of those contractual arrangements differ from customer-to-customer. There are rate tariffs that are in effect for some of those service contracts. We also, in some cases, we get facilities charges relative to the particular customer. But clearly, there's kind of a little bit of a demand-based type element to rate structures when you talk about those types of customers.

Okay. As opposed to like a fixed payment?

Again, and some of it is just contractually specific to the customer.

Okay, okay. And switching gears, and one thing we started hearing from a couple of companies is some interest in looking at E&P reserves as something to put in rate base, and maybe it's like a hedge for customers relative to gas prices, as they're very low right now. Given that you guys have a pretty heavy gas fleet, is that something you've considered and something that might have interest in?

This is Theo, again, Dan. It's something that our regulators have historically looked at ways on a hedge volatility of gas -- I'm sorry, I meant Steve, I'm sorry. I still had Dan Eggers on my mind for some reason. And as a matter of fact, the LPSC has an open docket right now to look at long-term gas hedging opportunities. And one such opportunity might be to invest in gas and ground. And that can provide an economic long-term physical hedge for our customers. So yes, it is something that, historically, we've had discussions with regulators about, and I think, we'll continue to have discussions around.

We would take our next question from Angie Storozynski with Macquarie.

So I have question about the growth in regulated earnings because I understand that you're going to be providing us updates during the EEI. But I was just wondering this write-down of expenses associated with the new nuclear plant. Does it have any impact on the rate base? And should we have any worries that your former or current growth trajectory for regulated earnings is going to be lowered?

I guess Angie, I'll answer the question, in terms of impacts on rate base. The asset that was written off was not in rate base in the Mississippi jurisdiction. So, no, it would not have any impact on our views of rate base going forward. It really wasn't, I think you used the term plant. I wouldn't describe it as a plant. I would really describe it as more of some additional -- some early stage cost associating with permitting and licensing processes as we were looking at new nuclear opportunities in earlier years. So clearly, not a plant that was in service, per se, and not an element of rate base. So we'd not expect it to have an impact on our views of rate base growth.

The reason I'm asking -- I'm asking because we're missing the slide that you usually have with the earnings growth for the regulated utilities.

I'm not sure which slide that is, Angie, but we'll certainly have that for you at EEI.

Okay. And then my other question, so there's been clearly a movement, a nominal movement in forward power curves. Could you give us, roughly a sense, if we were mark-to-market the EWC's earnings power, how much of a change would we see on these bars that you're showing for '15 and '16 EBITDA for EWC?

Angie, I don't know if I can comment specifically on the dollar value. I think, from our perspective, what we see is that for '15, it's in line with our POV, '16 maybe slightly lower than our POV and that widens as you move further out in the curve. So essentially, I don't think our point of view has changed much from what we provided you earlier in the year.

And we would take our next question from Michael Lapides with Goldman Sachs.

A couple of questions. First of all, tax rate going forward, you talked about the 32% to 34% for 2015. Do you view that as a normal number? Or do you see kind of taxes migrating back towards the higher historical level overtime?

This is Drew. So we see it as -- we have -- as we've talked about in the past, we have a portfolio of activities going on with the IRS and at the state levels. And it depends on the timing of audits and things like that. So next year, we see 32% to 34%. Beyond that, I think we are still talking about a statutory tax rates in our guidance and our aspirations and outlooks and those types of things. So that's where we are for now.

Got it. And on the regulated side, 2 questions, one with Ninemile. How significant -- what's the best way to think about what that level of rate increase would be? And when is the earliest you could see that actually go into effect?

Michael, this is Theo. I don't -- right off the top of head, I don't have specific number, as it relates to revenue requirements around Ninemile. We'll probably have to get that for you later. But clearly, we would expect that any rate change relative to that would go in effect at the time we see the plant coming online.

And I'll just add that we've got lot of AFUDC in the earnings this year, and so you're not going to see a big pickup next year when that plant comes online. It'll be maybe $0.05 or so.

Got it. And last question, Mississippi, as part of the rate deal and some of the other negotiations with staff in the Public Service Commission, are you moving to more of a forward-looking formula rate plan kind of similar to what one of your large neighbors in the state has? Or is that formula rate plan kind of some kind of hybrid or still historical looking?

No, I think -- again, Michael this is Theo, what we have arrived at in agreement in the stipulation is an FRP with what we call forward-looking features, which does allow us to look forward, to some extent, to kind of calculate and set what we would view as revenue requirements associated with the period of time in the future.

And are there any restrictions on when you can next file to get an FRP-related revenue increase?

Not certain. I'll have to get back with you on that. I don't -- obviously, we're going to operate within the formula rate plan constructs that have been in place in Mississippi for years. I mean, that's what we would expect. And my recollection is they don't necessarily have specificity as to whether you can get a rate increase. By the same token, that formula rate plan has -- obviously, it goes both ways. You could see rate decreases. So I'll have to verify that. But just off the top of my head, I don't believe there's any specificity in the stipulation around not being able to obtain a rate increase, or on the contrary, not necessarily having an -- experiencing a rate decrease.

Got it. And my apologies, one last one, cash levels at the end of the quarter were actually pretty high. I mean, roughly $1 billion, if you just assume short-term investments as well. Is that just a timing issue in terms of time line of CapEx? Or do you have a greater-than-expected cash balance that you can deploy to either the balance sheet or investment opportunities?

This is Drew. So it was a little bit elevated. We have a couple of big tax payments coming up, I think that's probably part of it.

And we would take our next question from Jonathan Arnold with Deutsche Bank.

Just picking up on something you just said, are you saying that you'll -- when you do your guidance, you're going to guide to a normal tax rate, and you were just sort of mentioning the lower tax number? Or is that sort of going to be a part of 2015 number you guide to?

No, what I was referring to for 2015, when we provide that guidance on the fourth quarter call, we would expect, at least, as we look at it right now, we'd expect the tax -- the effective tax rate reflecting that to be in the 32% to 34%. As we'd talked about 2016 as an outlook, we've been talking -- we've been using a normalized tax rate for that time frame.

Okay. So you're not changing your practice in terms of guidance on that front?

Right.

Okay. And secondly, so you just give us -- you gave a number of $70 million on pension and you mentioned the updated actuarial, I guess, mortality studies and then the discount rate. How much of the $70 million, if you can say, has to do with the new actuarial study?

Off the top -- it's probably -- I can't remember the exact number, but it's around half, I think. I mean, roughly half. We usually give a rule of thumb around interest rates and if you're trying to get to that $70 million increase off of our expectations for pension expense this year, you're not going to make it. And that's why we're talking about that piece.

And we would take our next question from Greg Gordon with Evercore ISI.

I'm all good. My questions have been answered.

[Operator Instructions] We would take our next question from Paul Fremont with Jefferies.

I'm looking, I guess at your Slide 24, which is the EWC EBITDA outlook, and it's very close or right on top of the numbers, I think, that you provided on the second quarter conference call. But at the time of your second quarter conference call, when you were talking about LHV capacity prices, you were sort of showing a flattish outlook going into the fall. This time, you're showing a fairly significant decrement. Is there something to offset the decrement that we should be assuming that are keeping sort of these numbers equal to where they were on the second quarter conference call? And if so, what would that offset be?

I think we'll have to get back to you. I don't have that -- honestly, I don't have been that in my head, Paul, in terms of what that reconciliation would be, but we can follow up with you on that.

And we would take our next question from Andy Levi with Avon Capital Advisers.

Just 2 clarifying questions. Just on Vermont Yankee on the $25 million. So that we should consider operating earnings?

Yes, yes, we're going to call that operational earnings next year. There will be some special items associated with Vermont Yankee next year and that related to the decommissioning activities themselves, but it will be a small amount, and we'll highlight it. But on an ongoing basis, we will be living with the decommissioned facility. And so we're going switch that to operational.

Okay. And then, also, around Vermont Yankee, you mentioned, I guess, in prepared -- I don't know if it's prepared statements, but you said that at this point, I think, you didn't expect any escalation in prices. And I just want to understand what that meant.

Escalation of contributions to the trust fund, is that what you're referring to or...?

Exactly. And what's the definition of -- at this point, meaning, is that at this point, the next 10 years ago or at this point...?

Well, as we look at where we sit with the trust and the expenses and our financing strategy associated with all of that, we believe that we won't need to contribute anything to the trust. But that is -- we have to still submit, here at the end of the year, our post shutdown decommissioning activities report to the NRC and then they have to sign off on it. So as we look at it, today, we think that we're going to be just fine. But we still have to go through that process.

Okay. And one last question. Just on the pensions, on the $70 million. And I would, I guess, put the $25 million on Vermont Yankee on that, too. When you did your Analyst Day earlier in the year, were these expenses contemplated when you kind of talked about your longer-term outlook?

I think the Vermont Yankee mostly was and some of the pension piece was. But interest rates have fallen further since then. And so I think the pension expense is probably up a bit since then.

We would take our final question from Mr. Charles Fishman with Morningstar.

Just one question. Is the -- will the economic development pipeline slide, that's cumulative through '16? Will you rolled that forward next year -- or next week?

You're talking about the 1,700 megawatts slide?

Right.

Yes, so we've been looking at that particular slide. We've gotten a lot of questions about how to actually make that more useful. And so we're rethinking it. We're not going to update it right now and roll it forward another year because we haven't completed -- it's a '13 to '16 view, and so we want get through '14 before we roll it forward. But we're still trying to figure out how we want to use that slide, if at all, or if in a different format going forward.

And that concludes today's question-and-answer session. Ms. Waters, I would like to turn the call back over to you for additional or closing remarks.

Thank you, Alan, 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. The call was recorded and can be accessed on our website or by dialing (719) 457-0820, replay code 6761108. The telephone replay will be available through 1:00 p.m. Central Time on Tuesday, November 11. This concludes our call. Thank you.

Ladies and gentlemen, that does conclude today's call. We like to thank you for your participation. You may now disconnect.