安特吉 (ETR) 2014 Q3 法說會逐字稿

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. In an effort to accommodate everyone with questions this morning we request that each person ask no more than two questions.

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 will 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 will try to keep our comments today relatively brief and save longer-term and more strategic updates for our meetings in Dallas.

I will start with the bottom line. Our plan and strategy remain sound and our progress against that strategy is both measurable and clear. As it often does, progress incurs a cost and with saw little of this in the third quarter. But in fact overall performance for the Company was squarely in line with expectations.

We are pleased to report that futility 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 in 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, the utility posted quarter-over-quarter industrial sales growth of more than 5%. As you have heard us say many times, this kind of growth isn't by happenstance. At Entergy we are 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 from 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 is 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.

The initiatives are different, but, as in Mississippi, combining the two companies will make it easier for us to make needed investments in Louisiana power infrastructure and via 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 two 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 state, in particular our industrial customers. And we were 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 the incremental distribution investment under a rider, becoming the first Texas utility to do so since legislation was passed in 2011. A 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 an $8 billion investment in the Lake Charles, Louisiana area.

At 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 600 consecutive days now. Remarkably they are on their fourth breaker to breaker run.

But 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, its 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 turn 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 the 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 challenges 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 replaced the majority of Vermont Yankee employees wanting to stay with the Company in new roles. It is 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, economics for VY would still not be sustainable in the long run.

Forward capacity market improvement, through the newly defined constrained zone 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. The plant's importance to the original 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, end of quote.

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 is 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 two other have 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 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 anytime 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 is 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 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 Northeast. This past quarter Massachusetts stakeholders withdrew support for the 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 is unclear when or if projects will actually get built. In any case it will take time. So we expect Northeast 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 who serve us and sacrifice and embodied 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 the utility operations; they are linemen, 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 for 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 will be seeing many of you in a week or so. And I know Drew will expand on this, so I will 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 is never easy going. But for all of us here there has never been a more exciting time. And 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 will discuss at EEI.

Starting with slide 2, our third-quarter results for the current and prior years are shown on an as reported and an operational basis. Operational earnings per share were $1.68 in the third quarter of 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 variants 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 metal 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 from rate actions a portion of which was offset by other line items. Sales growth was partially offset by a very mild summer leading to a negative $0.11 of weather. Also O&M 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 statements. 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 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 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 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 onto operating cash flow shown on slide 5, OCF was around $1.4 billion in the 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 will now turn to forward-looking information. Today we affirmed our 2014 operational earnings per share guidance of $5.55 to $6.75. Recall that the midpoint was revised upward in April of this year by approximately 23% to $6.15 per share from the original guidance midpoint.

Current expectations continue to be on track for around the midpoint of our range but for the unplanned charges associated with the Mississippi settlement. Similarly, absent that charge, expectations for the utility continue to be around the $5.00 midpoint we discussed in April.

Next week we will see many of you at 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 will 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 appear generally aligned based on commodity prices as of September 30 and other factors which I will discuss now with more detail 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 rate actions to have a significant earnings impact.

For EWC revenues the capacity generation table, table 7 in our release, provides details underlying our revenue assumptions. We also provide our current EBITDA estimates 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 for LHV.

Staying with EWC, the closure of 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 of 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 P&L 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 one year.

Finally, for content we will cover the utility's growth story which includes robust growth and industrial demand, as well as the case for investment opportunities in generation, transmission and potentially natural gas reserves.

For EWC we will 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). Paul Patterson, Glenrock Associates.

Just to sort of follow up on the EEI preview 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 years we expect it to be about a negative $0.20 to $0.25. And then after that it will trail off to about minus -- excuse me, millions. Sorry -- $20 million to $25 million of net income impact and that trails off to about $12 million.

I'm sorry, and --.

And there's several ups and downs in there. We will 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 updated Vermont Yankee decommissioning study?

I will 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 -- any of our remaining nuclear facilities.

Okay, great. Thanks a lot.

Julien Dumoulin-Smith, UBS.

So quick question here. As you are thinking about New England and all the latest developments what is your fundamental view of 2015 through 2017 on the forward curve? Do you think or is it your expectation to continue to use options to leave some upside there?

Yes, Julien. We can -- 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. So we continue to use a number of structured products. Those structured products change, the number of counterparties change, but we are still working to maintain that optionality in the book.

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

Yes. So we have seen a lot more activity in terms of proposed projects. Our expectations on pricing associated with capacity really haven't changed. We think that for the rest-of-pool in New England that still is somewhere around an $11 cone. We do expect ISO New England to put in place the SEMA pricing zone that 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 is 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 is going to -- final pricing will depend on the amount of capacity actually bid in FCA-9.

Great. Just to make sure I heard you correctly, there is the potential for insufficient capacity in SEMA?

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

Great. Thank you.

Neel Mitra, Tudor Pickering.

I had a question on the New England capacity market as well. Obviously you have the winter reliability program which is kind of a temporary fix. Do you see any progressing going forward similar to what PJM is doing with the capacity performance proposal to make sure that there is adequate fuel for the plants in that region during 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 some pretty clear guidance on that issue for the 2015/2016 winter time frame 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.

Okay, great. And then at your Analyst Day you laid out 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 you think that there is 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 have got the Northeast Energy Direct. 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 will 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.

Okay, great. Thank you very much.

Stephen Byrd, 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 is really going to be required to integrate your system into MISO?

Stephen, I will start and then I will let Theo kind of jump in with the details. From a transmission standpoint we've -- and obviously we will 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 the reliability projects, projects associated with the industrial growth in demand that we see down here, projects that will be required with we build -- will require new generating capacity and everything. Obviously we've had a significant uptick over the last several years on our transmission investment and we would think that continues.

And that is before you get into the idea of what we have got now that we are in MISO. And there is really two 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 is dispatched in MISO. Plus then there will be the Order 1000 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 are already looking at, but more to come on that front. Obviously some of those are farther out in the picture than the 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 will add a little bit to that, Leo. I mean you made a comment in terms of the path of our transmission spending. If you look back in 2010 we were probably spending somewhere around $280 million or so on transmission. I think if you go forward we're going to more than double 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 mitigation that could potentially drive transmission investment as well. We have 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 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 in there, 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 is very helpful. And 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, etc., or is this playing out primarily in the legal arena?

Stephen, we have 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.

Understood. All right, thank you very much.

Dan Eggers, Credit Suisse.

Just another really good quarter on the industrial demand side even relative to probably expectations this spring. How much of that is kind of maybe situational timing relative to what you would have expected? And at what point in time are you guys going to be in a spot to reconsider that underlying growth trend?

Theo?

Dan, I'm not -- this is Theo. I am not sure I understood your question in terms of situational. But I think when we look at where we are from an industrial growth perspective in the quarter, I think it is coming from where we would somewhat expect it to. It is primarily coming from expansions in the kind of petrochemical refinery area. And that is 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 at about 300 megawatts. And so, we are 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 [$3.50] 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 are 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 are still comfortable with the $3.50 to $3.75 at this point in time.

Yes, Theo, I guess the corollary to that is the residential load is -- hasn't been nearly as impactful, right? And when do you see your 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 are really seeing the impacts of multiplier effect at this point. Again, if you look at the slide, we've only got 300 or [1,700] megawatts that are signed and completed.

I think if you look historically at other areas where they've experienced -- I wouldn't say this type of industrial growth because I'm not sure anybody has experienced it in recent history, but some type of industrial growth. Generally the lag that you see in terms of the multiplier effect happens maybe within a year or a couple of years -- a year and a half after you really start to see the impact of the industrial growth.

So we are not quite there yet and I think that is still to come. We will see more signed and completed projects as we move forward into 2015 and 2016. And so I think you will start to see the impacts of the trickle-down and multiplier effect more so 2015/2016 time frame. But again, we are also going to continue to see impacts of our energy efficiency programs as those have broadened within our service area.

Okay, thank you.

Steven Fleishman, Wolfe Research.

A question just on -- in thinking about the huge industrial growth. When you are 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 as much or less. Just how are you kind of locking in the risk of that?

Theo?

This is Theo. I mean clearly there is a demand element to most of our larger industrial contracts and that is 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 is kind of more 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. And switching gears and one thing we started hearing from a couple companies is some interest in looking at E&P reserves as something to put in rate base and maybe as like a hedge for customers relative to gas prices as they are very low right now. Given that you guys have a pretty heavy gas fleet is that something you have considered and something that might have interest in?

This is Theo again, Dan. It is something that our regulators have historically looked at ways -- our regulators have historically looked at ways to hedge volatility of gas. I'm sorry, Dan, I meant Steve, I'm sorry. I still had Dan Eggers on my mind for some reason. And as a matter 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 could provide an economic long-term physical hedge for our customers. So, yes, it is something that historically we have had discussions with regulators about and I think we will continue to have discussions around.

Okay, thank you.

Angie Storozynski, Macquarie.

So, I have a question about the growth in regulated earnings. (Inaudible) that you're going to be providing us updates during the EEI. But I was just wondering the write down of expense 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 costs associated 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 I would not expect it to have an impact on our views of rate base growth.

Angie, I would just add (multiple speakers).

The reason I am (multiple speakers) I am asking because we are missing the slide that you usually have with the earnings growth for the regulated utilities.

I am not sure which slide that is, Angie, but we will certainly have that for you at EEI.

Okay. And then my other question is so there has been clearly a movement -- a downward movement in forward power curves. Could you give us roughly a sense of if we were to mark-to-market the EWC's earnings power how much of a change would we see on these bars that you are showing for 2015 and 2016 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 2015 it is in line with our POV. 2016 may be 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 to you earlier in the year.

Okay, thank you.

Michael Lapides, 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 see kind of taxes migrating back towards the higher historical level over time?

This is Drew. So we see it -- 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. 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 rate in our guidance and in our aspirations and outlooks and those types of things. So that is where we are for now.

Got it. And on the regulated side, two questions, one with Ninemile. How significant -- what is 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 my head I don't have a specific number as it relates to revenue requirements around Ninemile, we'd 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 will just add that we have got a lot of AFUDC in earnings this year. And so you are not going to see a big pick up next year when that plant comes online, it will be maybe a nickel or so.

Got it. And last question, Mississippi. As part of rate deal in some of the other negotiations with staff and 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, an agreement and a 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 a 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 will have to get back with you on that. I don't -- obviously we are going to operate within the formula rate plan constructs that have been in place in Mississippi four years, I mean that is what we would expect.

And my recollection is they don't necessarily have specificity as to whether you can get a rate increase. Or by the same token that formula rate plan has -- obviously it goes both ways, you could see rate decreases. So I will have to verify that.

But just off the top of my head I don't believe there is any specificity in the stipulation around not being able to obtain a rate increase, [although] on the contrary, not necessarily having and 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 assume short-term investments as well. Is that just a timing issue in terms of timeline 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 big tax payments coming up, I think that is probably part of it.

Got it, okay. Thanks, guys. Much appreciated.

Jonathan Arnold, Deutsche Bank.

Just picking up on something you just said. Are you saying that when you do your guidance you are 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 part of the 2015 number you guide to?

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

Okay, so you are not changing your practice in terms of guidance on that front?

Correct.

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 is around half I think.

Okay.

I mean roughly half. We usually give a rule of thumb around interest rates and if you are trying to get to that $70 million increase off of our expectations for pension expense this year you are not going to make it. And that is why we were talking about that piece.

Okay, great. Thank you. That is my two. Thanks a lot.

Greg Gordon, Evercore ISI.

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

(Operator Instructions). Paul Fremont, Jefferies.

I am looking I guess at your slide 24 which is the EWC [MEDAI] outlook. And it is 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 are 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 will have to get back to you. I don't have that -- honestly I don't have that in my head, Paul, in terms of what that reconciliation would be. But we can follow up with you on that.

Thank you.

Andy Levi, Avon Capital Advisors.

Just two clarifying questions. Just on Vermont Yankee on the $25 million, so that we should consider operating earnings?

Yes, yes, we are 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 will highlight it. But on an ongoing basis we will be living with the decommissioned facility and so we are going to switch that to operational.

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

Escalation of contributions to the trust fund, is that what you are referring to or --?

Exactly. And then what is the definition of that at this point? Meaning is that at this point the next 10 years or is at this point (multiple speakers).

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 are 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 in 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.

Great. Thank you very much. I will see you for a beer down in Dallas.

Charles Fishman, Morningstar.

Just one question. Is the -- will the economic development pipeline slide that is cumulative through 2016, will you roll that forward next year -- or next week?

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

Right.

Yes, so we have been looking at that particular slide, we have gotten a lot of questions about how to actually make that more useful. So we are rethinking it. We are not going to update it right now and roll it forward another year because we haven't completed -- it is a 2013 to 2016 view. So we would want to get through 2014 before we roll it forward. But we are still trying to figure out how we want to use that slide, if at all, or if in a different format going forward.

Well, it is an interesting slide. Okay, thank you.

And that concludes today's question-and-answer session. Ms. Waters, I'd 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. Our call was recorded and can be accessed on our website or by dialing 719-457-0820, replay code 676-1108. The telephone replay will be available through 1 PM Central Time on Tuesday, November 11. This concludes our call. Thank you.

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