安特吉 (ETR) 2005 Q1 法說會逐字稿

Good day, everyone, and welcome to the Entergy Corporation first quarter 2005 earnings conference call. Today's call is being recorded. And at this time for opening remarks and introductions, I would like to turn the call over to the host, Ms. Michele Lopiccolo. Please go ahead, ma'am.

Good morning and thank you for joining us. We'll begin this moment with comments from our CEO, Wayne Leonard and then Leo Denault, our CFO, will review results. After the Q & A session I will close with the applicable legal statements. Wayne.

Good morning, in our last call, I told you we, you - we, we would be updating you each quarter on our results across a range of goals we set for 2005. I will review the status of each of our businesses and then I'll turn the call over to Leo for a review of the quarter's results. Let me begin with utility. In Louisiana, we obtained approval of the global settlement proposal to resolve 12 open dockets covering a range of issues for Entergy Gulf States Louisiana and Entergy Louisiana.

Pursuant to the settlement, retail electric customers in Louisiana will receive credits in the amount of $90 million and we agreed to forgo recovery of $5.5 million for other issues. Just as importantly, we eliminated the annual review and earnings cap mechanism and replaced it with a formula rate for Entergy Gulf States Louisiana that is similar to the RFP that was in place in Entergy Louisiana for the test years 1995 through 2000. The Entergy Gulf States Louisiana AFRP will remain in effect for at least three years with extension provisions and has a return on equity midpoint of 10.65% with a bandwidth of plus or minus 75 basis points, allowing the Company to earn up to 11.4% on equity before sharing.

Under the FRP, earnings outside of the band are allocated 60% to customers and 40% to the Company. In addition the FRP provides specific recovery for LPSC approved capacity additions in excess of the amount that's already included in base rates. This capacity provision eliminates regulatory lag by permitting the Company to recover the cost of new capacity agreements or previously deferred capacity costs when new rates take effect each September the FRP is in place. We will make our first filing under this FRP in May for the test year ended 2004.

Turning next to the Entergy Louisiana rate case. In March, Entergy and the staff of LPSC jointly proposed a contested stipulated settlement for a rate filing that was made in January of 2004. The settlement calls for an $18.3 million base rate increase and establishes the formula rate plan similar to the plan approved for Entergy Gulf States Louisiana. You may recall that our initial rate -- rate filing requested a base rate increase of $167 million. I know you are used to big differences between a utilities ask and a commission's final order, but in this case, it's a big gap between the ask and the proposed settlement. So let me reconcile that.

First, as we expected, any order would, the settlement set aside for later consideration the request for $65 million of the total $167 million rate increase for Perryville and two supply contracts that are part of the FERC TPA case have not yet been approved by the LPSC. I'll come back to this set-aside in a moment. Second, the proposed settlement has a return on equity midpoint of 2.5% with a bandwidth of plus or Minus 80 basis points allowing the Company to earn just over 11% before sharing. The change from the initial 11.4% ROE proposal reduced the initial rate request by approximately $24 million.

But, again, with the bandwidth and the sharing provisions in the FRP, there is the opportunity to earn that back. Third, the settlement includes life extension accounting for Waterproof 3. This change reduced the rate request by roughly $30 million without any ongoing negative impact on earnings.

Finally, the rate request was reduced further by roughly $30 million to reflect the affects of actual events since the filing and other miscellaneous adjustments. Given the rise to natural gas prices since the case was filed, the net impact on rate payers is a reduction in the total bill. For those how may not have followed all that, we have included a slide in the presentation appendix reconciling the ask of $167 million to the $18.3 million proposed settlement. But the take away is that the settlement simply moves most of the request into different rate mechanisms while allowing the shareholder a full opportunity to earn a fair return on their investment. The LPSC is expected to vote on the proposed settlement at its May 18 meeting.

In another step forward, at it's meeting last week, the LPSC (ph) unanimously approved Entergy Louisiana purchase of Perryville and the purchase by Entergy Gulf States of 75% of the capacity in associated energy from the Perryville facility. This action paves the way for midyear closing at which time Entergy Louisiana base rates will be increased by nearly $7 million, reflecting a return of and on the investment. Entergy Gulf States Louisiana share of the Perryville purchase will be reflected in May FRP filing when collections -- with collection when rates take effect in September. Finally, the LPSC has agreed to provide for rate recovery of the two remaining supply contracts to the capacity provision in the FRP once the contracts are approved.

Moving to Mississippi, in April, the review process at the Mississippi commission resulted in a joint stipulation with the commission staff, and there will be no change in rates based on our formula rate plan filing for the 2004 test year. Using a performance adjusted regulatory ROE of 10.5% and considering a 9.1% to 11.9% bandwidth range. Included in the performance adjusted ROE is a .37% for performance incentives out of a possible range of plus or minus 1%. The performance incentive reflected the top score in reliability and a score very near the top in customer satisfaction. The price score, however, was not positive, due to deferred fuel billings from 2003.

Those billings are now complete and will not affect the price score in 2005. Further efforts to improve the efficiency of our plate met with success through the signing of a purchase and sales agreement to acquire the 480 megawatt Attala Power Plant located in Mississippi. Total capital costs for this transaction are estimated to be $111 million or around $231 per KW. This low following, highly efficient plant was completed and commissioned by a unaffiliated IBP in 2004.

Entergy Mississippi will own the Attala plant and seek approval and rate release for this purchase from the Mississippi Public Service Commission as a condition of closing. This transaction is well aligned with our disciplined market point of view of commodity prices and for capital deployment. We expect to close on the Attala plant in late 2005 or early 2006.

Finally, in February, bills were introduced in the Texas legislature to create financial stability and certainty for Entergy Gulf States Texas. In its current state, the legislation, which is now on its way to the Senate specifies that Entergy Gulf States Texas is no longer subject to a rate freeze, that it can recover certain costs like reasonable and necessary transition costs and incremental capacity payments under additional rate rider mechanisms set in single proceedings outside a general rate case. But it may not alter base rates in a general rate proceeding prior to June 30, 2007 with new base rates to be effective no earlier than June 30, 2008.

At the same time, the legislation provides considerable direction and guidance to the commission as to the will and the intent of the legislature of moving to retail open access when or if Entergy Gulf States Texas becomes part of a certified power region. More importantly, the legislation allows Entergy Gulf States Texas to proceed with jurisdictional separation between Texas and Louisiana, thus creating one company solely under Texas jurisdiction and another company solely under Louisiana jurisdiction. Simplifying regulations in both states and preserving Entergy Gulf States Texas options.

While the legislation does not include everything we believe we are entitled to in terms of immediate rate relief, it does clarify that Entergy Gulf States Texas is entitled to cost of service regulation that as it removes the threat of what we termed as the regulatory ice age, frozen in time, and more importantly, it reopens a potential door to competition that had previously been shut and locked. Specifically, the proposed legislation directs the Company to take reasonable steps to facilitate a wholesale generation and market over some future time period.

The keyword there is "reasonable steps" and we can work with that. While we will make periodic filings, there is no deadline for getting there by a specific date and we explicitly have the alternative of rate relief in 2008 if the path to a certified power reason -- region is not readily achievable. While this does give us some headwind for another couple of years because we can't get base rate relief until 2008, we will take steps to mitigate the negative impact and manage the overall utility operations to achieve our financial goals in the same way we always do.

Like I said, the proposed legislation isn't everything we wanted, but in the end, the short-term trade-offs necessary to reopen the door to competition and eliminate any ongoing threat of a permanent rate freeze are an acceptable outcome. On the federal landscape, the FERC accepted our enhanced proposal to establish the independent coordinator of transmission. Our proposal was developed and refined in extensive informal collaboration process with the stakeholders, with the specific goal of addressing priorities and concerns of both our local regulators and the FERC. Under our proposal, the ICT will grant or deny transmission service and play a key role in the planning, the expansion of the transmission system and the allocation of associated costs.

Additionally, the pricing proposal will protect our customers against costs imposed by third parties. But operational control will remain with Entergy. We're pleased that the FERC arrived at this decision while specifically noting that the ICT proposal is a, quote, positive development toward a more independent transmission system. We intend to submit our next filing, that's a 205 filing for those of how keep track of that stuff, around the end of May, outlining the required actions to implement the ICT. Before I move on from the Utility, while overall many strides have been made, there is one substantial outstanding issue that has not advanced since our last discussion and that is, of course, the system agreement proceeding.

We anticipate that the FERC could take action on this proceeding at any time now. Regardless of the rate order, given the complex nature of this case, it will take time to determine the ramification of the order, and as you might expect, some, if not all parties involved, will likely appeal some, if not all, parts of any order. While this case may have already seemed to have moved at a glacial pace, assuming it moves to the courts next, we may be years away from a final resolution. Of course, we will keep you updated in a timely manner as system agreement events unfold.

Now turning to the Nuclear business. Progress was achieved in continuing to sell forward the Northeast portfolio through higher average pricing and additional volumes as noted in our release on page 4. During the quarter . New York power authority also selected Entergy through its long-term request for proposal process that requested contracts starting as early as 2008. Contract negotiations are still under way with NIFA with this transaction. Even more progress was developed in the up rate Program.

Specifically the Nuclear regulatory program approved two uprates. The first uprate totaling 47 megawatts was recently placed in service following successful spring refueling outage at Indian Point 3 moving the total northeast fleet capacity to just over 4100 megawatts. Second upgrade totaling 68 megawatts will be placed in service following the spring refueling outages currently under way for Waterproof 3.

In closing, while the first quarter was quite active and marked with a number of accomplishments that create long-term value for owners, our work for the year is far from over. We know we need to remove more short-term and long-term uncertainties, to provide a clear line of sight for use of capital in our growth aspirations and to move the needle higher in our 2005 earnings guidance range. And with that, let me turn the call over to Leo Denault.

Thank you, Wayne, and a good morning. I will cover three primary topics. First, a recap of results for first quarter; second, review of our opportunities for the remainder of the year; and third, progress to date on our share repurchase program. I will also offer a reminder of our longer-term aspirations. Slide 2 shows the first quarter '05 as recorded earnings were lower than results one year ago primarily due to the absence of any contribution from Entergy-Koch. In addition, both as reported and operational results reflect low earnings at utility, which were partially offset by increased contributions from our Nuclear and non-nuclear assets whole sale business.

In addition first-quarter results included accretion from our stock repurchase program. Slide 3 offers a closer look at first-quarter operational earnings and shows utility, parent and other results were down about 24% quarter over quarter. In the current period, total sales grew less than 1% on a weather-adjusted basis, due primarily to lower usage in the residential sector. This lower usage is the key driver in our quarter-to-quarter comparisons that show residential sales including on build sales declined this year compared to '04. Modestly higher demand in all other customer sectors partially offset that impact of decreased residential usage. The industrial sector, particularly with the chemical and pipeline segments, supported the overall increase in retail sales.

We expect growth in the industrial sector to taper somewhat in the remainder of '05 due to a combination of factors. First, we have evidence that suggests our largest customers are operating at or near full capacity, and second, a large industrial customer at Entergy Gulf States Texas has begun the process of moving to co-generation, a little ahead the schedule we expected. Also contributing to the decline in utility results was higher O & M coming from increased benefits cost, planned fossil generation outage expense and higher Nuclear operating expense.

We have discussed higher benefits cost on previous calls. While we continue to look for opportunities to manage this issue, it is a trend we will likely see throughout the year. However, we do not see the uptick in O & M from fossil outage expense or Nuclear expense as recurring in future periods. Most of the fossil outage work was -- this quarter, is typically done once every five years. These costs were budgeted so we expect to see O&M trend back in line with our full-year expectations. Entergy Nuclear earnings per share contribution reflected an increase of 24% compared to the prior quarter. In the first quarter we realized the benefits of higher contract pricing. Also ENI's results impact of an adjustment to the decommissioning liability which was consistent with the application of statement of financial accounting standards 143. You may recall that we had a similar item in third quarter last year.

In both cases, these adjustments results from updated decommissioning studies on certain plants that supported revised liability estimates. Also in Nuclear, we began a refueling outage at Indian Point 3 in March that was subsequent -- subsequently completed in 26 days. The 26-day outage was a significant accomplishment and had equaled the shortest refueling outage ever achieved at Indian Point 3 and it included upgrade work to add approximately 47 megawatts of capacity to the plant. Nuclear results for the quarter reflect the loss of that generation for about 20 days, the impact of which was offset by higher contract pricing realized by the fleet.

Finally, in the non-nuclear wholesale assets business, we achieved better performance due primarily to operational improvements and proceeds realized on the sale of SO2 allowances. We continue to expect improved results in this business compared to last year's performance, but do not expect it to be profitable for full-year '05. Slide 4 reflects the progress during the quarter in our share repurchase programs. During first quarter, we repurchased 5.6 million shares at an average price of approximately $68 per share. The majority of the repurchases were associated with our $1.5 billion program. The reminder of repurchasing activity was associated with our efforts to offset the dilutive effects of stock option exercises. We continue to estimate that average shares outstanding at the end of '05 will be approximately 215 million.

Slide 5 details our current '05 guidance of 460 to 485 in both as reported and operational earnings per share. We are funding this guidance today and remind that you our bias is towards the lower end of the range. Taking into consideration first quarter's results, we've made some minor adjustments to the mix of contributions of '05 guidance. The primary reason for these adjustments include at the utility we expect a modestly lower contribution compared to our earlier estimates.

This comes primarily from some refinement of our assumptions on sales growth, O & M and regulatory outcomes. In the Nuclear segment we believe an upward adjustment is appropriate to reflect the latest decommissioning liability estimates. While we anticipated this adjustment, the fact was the impact was a few pennies per share better than we originally estimated. Lastly, we believe we can sustain favorable first quarter results in the non-nuclear wholesale assets business. With that rundown as a backdrop, we continue to acknowledge that we have challenges ahead to achieve earnings in our stated guidance range. We recognize that some of you may be thinking, how do you get there?

However, we are about where we expected to be after one quarter because we knew that due to the nature of our activities in 2005 we would have both step change and back-end loaded growth this year. Our assignment is unchanged from the view I shared with you on the fourth-quarter call earlier this year. We have to proactively pursue opportunities that are both additive to earnings and create longer term value. Slide 6 quantifies the opportunities that we see for the remainder of '05 that build to our earnings guidance for the year. We begin with first quarter earnings this year and add actual operational results achieved for the second through fourth quarters last year. Our challenge is to build on last year's performance. Sales growth and rate action at the utility is the first additive piece.

Next, we build in pricing and volume uplifts at Entergy Nuclear, followed by overall O & M improvement through some turn around at the utility as well as productivity initiatives. We estimate that accretion from our share repurchase program will make a significant contribution with a relatively small layer of other items completing the build-up to full-year guidance. While we've adjusted some components, this is not a new list. We're not changing our tactics and we don't believe a change in our full-year guidance range is warranted at this point.

We fully understand the task at hand and are committed to pursuing positive outcomes over the remaining nine months of the year. Before closing let me note, that our focus on delivering in '05 is balanced on other actions. These other actions align with steps were taking to identify and deliver on opportunities that add value for our shareholders over the long term. On slide 7, you'll see that the left-hand panel reflects the financial aspirations we have discussed with you in a number forums. Note that the aspirations have not changed even though we realize our path to achieve them may change. We continue to aspire to 8% to 10% earnings per share growth in '06. We know, however, that legislation taking shape in Texas will not allow us to pursue an increase in base rates next year as we had originally planned. At the same time, we are aware that stronger Nuclear pricing may present an opportunity to offset this shortfall. Looking at the right panel, we highlight potential strategic opportunities that we believe can create value in the future.

This list, too, will certainly change over a period of time as some opportunities are pursued, others are set aside, and new opportunities are added to the list. Our task is to rigorously evaluate each opportunity and choose those that yield value consistent with our threshold expectations for long-term growth and solid financial footing. We can not give you deep precise mix that will result in the future. We can promise a disciplined approach, choosing that mix, and we can commit to exercising the principles of capital stewardship that ensure our risk and return criteria are met. And finally, as our past actions clearly indicate, should our opportunities become limited, we will return cash to owners through share repurchases or dividend increases. And now our senior team is available to respond to your questions.

Thank you, sir, our question-and-answer section today will be conducted electronically. [Operator Instructions] We will pause for just a moment to assemble a roster. And our first question today comes from Ashar Khan from SAC Capital. Please go ahead. Hello, Mr. Khan.

Hi, sorry about that. Wayne, can I just -- just conceptually, so in Texas, the remarks you made this morning. You know the rate increase is going to happen in '08, but right now as you look out long term, Texas is part of Entergy. There is no immediate plans knowing where you are right now in terms of going one way or the other in terms of keeping it or selling it.

That's right. I mean the legislation currently makes it clear through the business separation, through opening the door to competition that our options are -- are back on the table to maximize the value of the Texas business, and before we head down the path of spending too much money one way or the other, we're going to try to work through some kind of collaborative process or maybe through declaratory orders, or whatever, with the Texas commission to get clarified, what the rules are going to be going forward.

If we move toward competition and -- you know, overall, that would probably be where the greatest value would be created, but not if we had to spend 2 or $300 million to get there without any assurance we can recover it. So, we'll -- we'll work that process as hard as we can to try to come to some resolution on whether we're the natural owner of that business and under what set of market conditions makes the most sense for us, another owner, and for the -- for the Texas commission.

And what would be the time frame of that decision? A year from now?

I don't know if we'll be able to get -- you know the business separation will probably take about a year or so at least to get to that point. If that goes well, which we have every reason to believe it will go well, we will be in a much better position to -- to get the options on the table and figure out which one makes the most sense. But it, it's -- I think it is unlikely that within the next year we'll have an answer to that question that will be -- that will be definitive.

If I can just ask one more. Leo, you had shown us a chart which had shown that the power that you contracted in '04 was about $3 or so average higher for each of those 5, '06, '07, '08 years from the average price. Is that still true from from what you have been contracting in '05 that prices are on average for each of the -- for the next four years about three -- two and a half to three and a half dollars higher? And the curve was a little bit backward dated in '08. Is that still the relationship as you have contracted for these years?

Ashar the -- Ashar, that relationship still holds. The recent contracts that we've been signing have been in the 50 to higher than $50 range. But that relationship to the average, you know, the average that we signed in '04, for example, has been -- has been pretty much holding true and it's still a little backward dated as we go out as most curves would be.

Okay. But you are signing things in 50, I guess that's for, what, '07 time frame?

It's really as we go out into the future beyond where we are already contracted '05, even into 6, 7, 8 and that time frame, and it really, it, it's in that range and better.

Thank you, sir

The next question comes from Glenrock Associates, Paul Patterson, go ahead, sir.

Good morning, guys.

Hey, Paul.

Just to circle back with HB 1567, the Texas legislation. How much -- you know, you get some regulatory relief from some of your potential filings. Can you give us an idea about what those might be?

Yeah, I'll let Rick -- Rick Smith, you all know Rick, I'll let Rick address that issue. He's the President of all our Utility Operations.

Paul we'll be filing two riders this summer if the Bill fully gets through, latest will be in September, but we're looking at filing over $130 million on the TTC rider, and then the capacity costs I think are costs for '05 that'd be around 15, 16 million, I think, but then it gives us an opportunity to file twice a year with ex capacity cost and update those numbers. So --

Okay. So we could see some relief there in -- sometime in 2006. Would that be, what, the middle of 2006?

Yeah, I think that's what we are really looking at, some relief in the middle of 2006.

Okay. And then, on the decommissioning study. It seems like you've gone and done another one, and if you could just revisit, you know, what's actually leading to these decommissioning studies and what actually is leading to the estimation of less decommissioning expense? And am I correct in looking at the income statement, it looks like it's, it's about $2 million for the quarter? I mean, what -- what is exactly happening there?

Leo?

Yeah, on a -- on a regular basis, As it relates to decommissioning studies consistent with 143, we revisit the -- what it will cost and our assumptions around decommissioning. As you know it is an assumption based on what is going on, you know, 20, 30 years from now. So the, the -- what happens is you go through and you look at a number of items about what it would cost. And one of the particular items that is of interest is how -- when will you actually decommission the plant in terms of will you have license extension, et cetera.

And so the most recent study was done around potential to look at life extension or license extension at the plant, and so we look at a range of opportunities and probabilities around how long the life of the plant will be, and that's what the adjustments are made. There's are a lot of other things that go into it in terms of the cost and the assumptions around cost, but that's major driver is when is license extension. As to the amount, it was more like $.07 a share.

It was $.07 a share?

Yes.

Okay. And, does that continue into the rest of 2 -- I mean do we see this -- is this a one-time kind of thing that happens in the quarter or something is this something that we should see benefiting throughout the year?

Well, it - the ongoing effect is smaller. It will have an ongoing effect Of a couple of cents a year, but the initial The initial assumption, the $.07, that's, that's the bigger piece of it shows up at the beginning when you restate the liability.

I see. And then, a couple cents we should see, sort of coming in throughout the rest the year?

No, annually.

Annually.

Annually it'll be about, you know, two, three, $0.04 in that range going forward.

Okay, and what was the benefit -- can you remind us -- in the third quarter.

Third quarter last year was about a nickel.

Was about a nickel. Okay. And then finally, the SO2 benefit. What was that, and what's that going to look like going toward?

Going forward, that -- that'll be smaller as well. We have SO2 allowances that are - that are granted to some of the Fleet that we have in EAM, and just because of the pricing and timing of them, we -- we realized more profit on those during the quarter this year than we ordinarily would. So, there'll be something going forward on a annual bases. We've taken benefit of all of we could in '05 in the first quarter. That's why we said that it, you know, it's somewhat one time this year. It'll be a smaller amount going forward, only a couple million dollars at most.

How much was it in the quarter?

It was about a penny or so this quarter

Oh, okay. Just finally, Vermont Yankee, there is some legislation on dry cask storage issue there. Basically one -- you know, in terms of your ability to get the uprate. And then, B, there's also some discussion of a tax on dry cask storage, could you just give us an update on that?

This is Gary Taylor. How are you today?

All right.

As far as the legislation. That 's fairly active if you've been watching and right now it's in with, with the House. We would expect that they would come out here probably sometime this week and then go to the Senate over the next couple of weeks. We feel that's pretty much on track to -- to authorize moving with the public service board, that still has to approve that to allow us to have a dry cast storage. Most likely, they'll come out something in the order of near to -- at least to the end of the present life, when they have to do something beyond that. So I think that would address both the uprate as well as the continued life. Right now we run out of dry cast storage space in 2008. At that point in time, we would have to close the plant if we didn't get this. And I think they recognize that BY Is one-third of the state's energy supply which is, which is a big part and a valuable piece of that.

The part discussing the tax is something that they're still discussing based on what some other states have done. Obviously we don't believe that that's something that should go forward, and we are working with both the House and the Senate to look at what benefits the plan already brings and that we think that's already factored into the price and the PPAs that we've already given them and the original sale, to us, of the plant. Great, thanks a lot, guys

And our next question today will come from Greg Gordon with Smith Barney. Please go ahead, sir.

Thanks, good morning, gentlemen.

Good morning, Greg.

Hello, Greg.

The prices that you're getting for the energy that you're committing to sell in New England and New York, that, that -- it looks like it is about a 10% discount to where we see other nuclear capac -- other nuclear energy getting sold, non-unit contingent. You've mentioned in your strategic opportunities slide on page 7 that, you know, this transform asset portfolio bullet. Can you talk about sort of the cost benefit analysis of buying into generation capacity, higher up the supply stack in New England in order to capture some of the present value of being able to sign non-unit contingent deals. Is that spread just too tight? Is that why you haven't made that move?

And, can you also talk about how your hedging strategy has evolved? Because it doesn't look like you've actually hedged that much more for '06 since we last talked. And, are you taking a stance where, on the margin, you'd like to be more naked to the market?

Greg, as far as transforming the portfolio, there's a couple of aspects of it. One, obviously, operationally in terms of continuing to manage that as a Fleet up there, from an operation perspective, is important as it relates to cost and capacity factor and things like that. On the -- on the contracting side and the pricing side, we have looked at -- you know, we do look at generation at different points in the stack, but you're right, the spread has just not been there for us in terms of what we'd be willing to pay to be able to actually change the way we've contracted.

That said, we look at a variety of other opportunities, whether they be in our review of transmission and transmission constraints in that area as well as the relationship between the units to try and find other ways to contract in terms of not having to take that unit contingent discount. As we said before, it's different at different plants and at different times and under different situations, as to whether that discount is 10% or 4 to 6% on some of our units. So we've looked at what we could do buying generation at a different place in the stack, but that really haven't been worth the price of admission to date. It doesn't mean it won't, but it just hasn't been. As far as what we've contracted going out.

If you look, we really don't have much opportunity until '07 and beyond, and that's the focus of our efforts in terms of whether we leave some of it open or whether we change the way we sell it in terms of, you know, of firmness, whether we add different availability guarantees to take some of that discount away or whether we go to a firm product. So, it's really -- you wouldn't see a lot in '06.

You'd be seeing more of it show up in '07 and one way it might show up is actually that, you know, we may choose to leave some open. But that's going to be, you know, -- evolving as we go . If we find a good transaction we're going to take it even if we have the opportunity to leave some portion of the portfolio open per our risk standards.

Thank you.

And --

And we will now hear from Kit Konolige from Morgan Stanley. Please go ahead.

Hello? Can you guys hear me?

Yeah, Kit.

Oh, good. Okay. Just wanted to see if you could review in a little more detail the higher O & M expense at the utility parent -- the utility, parent and other, but I guess utility primarily, up 12.5. I am looking at page 3 of the -- of the big handout. Up 12.6%. Can you give us a sense of which part is which? How much is benefits? How much is -- you know, the -- the one-time stuff that you've been doing. How much is ongoing?

Okay. Well, the -- the benefits piece of that is probably about $11 million or so. And I think -- you know the $0.09 that we've got, about half of that is probably from benefits. And then we've got another portion of that that's due to the fossil outages, the fossil generation out ages that we had and the rest is nuclear reliability spending. The fossil and Nuclear spending we wouldn't anticipate happening going forward. The benefits, as we talked about previously, that's something we are continuing to see throughout the year.

So is that -- should, should we be thinking of that as a -- the benefit portion as around 4 to $.05 each quarter incrementally compared to what we were thinking before?

Well, it is probably about $.03 a quarter is what I would say for the benefits going forward.

So that's $.03 higher than last -- last year, not $.03 higher are than you were expecting?

Right, right, right.

But somewhat high are than you were expecting because that's why you're on the lower end of your range among other things.

Exactly. And that's what we mentioned on the -- on our first-quarter call.

Right, right. I mean what stands out here -- just health? Is that -- this is the medicine and things, main things?

It's a combination of health care, as well as one of the big changes was at the end of the year, the discount rate changes, the actuarial assumptions in terms of pension and [ Inaudible ] going forward and that was the big piece of the move, why it was a little bit different than what we expected. As we said in the -- on our fourth-quarter call, that rate went from 6 and a quarter down to 6. So that moved I think about 3 to $.04 of additional what we had anticipated was going to happen for the year.

And just to finis with that. My general sense is now you -- most of your jurisdictions, you're just wrapping up -- regulatory proceedings and so is, is it going to be a while before you are able to pass this through to customers?

Kit, this is Rick. I mean, most of that will work through these FRP mechanisms. I mean we got that in Mississippi, we got Louisiana Gulf States, New Orleans, and hopefully with this rate settlement, to be voted on in May, we'll have an FRP in place to work that through also. And so the real issue probably would be just Gulf States Texas.

So when -- so this shows up in expense, but when -- when and -- where do we -- are we seeing an offset somewhere else now or soon or ?

You'll see it go forward when we go forward when we file under the FRPs.

Yeah, which would be when?

We just -- just completed Mississippi. We have to file in New Orleans in May. We are filing in Gulf States Louisiana in May. And then -- and then there'd be a -- I think it's about a year away for Louisiana.

Right, and how long do those take -- I guess I am trying to figure out. Is there any forward look to that process? Or just a matter that you are in a permanent regulatory lag as long as your expense -- your pension and other personnel expenses are rising so rapidly?

I mean, there is -- there is some regulatory lag, but there is other Productivity improvements that are offsetting A large share of this. I mean, that's what has been going on for quite a few years is you look at the rest of the business. Our costs are going down. And we continue to see that on the utility side. So it will offset some of this cost.

Okay.

Kit, this is Leo. Just to clarify, those are in our current thinking for '05, the costs that we've got versus what we will cover, et cetera. That's all in, you know, this is nothing new, this is where we -- as I said when we came out on our fourth-quarter call, which is consistent with where we thought we'd be on benefits.

Okay. Okay. Thank you.

Kit, this is Wayne. Let me just kind of close on this point that Rick made and Leo made that -- that this is really not -- the change in the actuarial assumptions, I mean, they are what they are, I mean you know.

Sure.

And we kind of got caught at the end of year with those assumptions, and like Rick said, there's been a lot of cost reduction, work construction taking place that that constant movement in those actuarial assumptions has kind of offset to where you'll see what's taking place operationally. Now hopefully, and maybe as we go forward we will get some relief on the actuarial assumptions which is a big -- a big driver in a lot of the numbers you're seeing.

We have any number of initiatives going on as Rick indicated to mitigate overall costs and become more efficient and productive, predicting on these formula rate plans that provide a strong incentive for that. We're not just sitting here trying to find a way to pass it on to customers. We have a very aggressive supply plan initiative. Supply chain initiative. We brought up a fella from General Electric who was enormously successful there. When Mark Saveoff (sp) came from General Electric, Mark was one of their key people in six sigma. Mark brought a supply person with him. Mark, he was our EVP of Operations, and he's been driving the six sigma work destruction process for us.

We also have teams in place on our support services that are working toward, again, destroying word, best practices, I guess what we call next practices and also looking at or investigating external providers and opportunities that they may provide for these type of overhead type items. And on the health side, we're, we're -- we have kind of an ongoing program this year, a very intensive program to educate our employees and move them into a different type of plan than they are used to, giving them more responsibility to become better consumers and moving the program more toward wellness and catastrophic coverage, which will hopefully mitigate a lot of the costs that you're seeing on the health plan side while making our employees obviously more healthy at the same time.

So we're not just sitting here trying to pass them on and I won't leave that impression.

Okay. Sounds good to me. Thank you.

Our next question today will come from Paul Fremont with Jeffries.

Thank you. Can you give us a quick update on when is the Texas legislative session right now scheduled to end? What exactly do you have behind you in terms of the proposed Bill, and what still needs to be done in terms of getting passage.

Rick?

Paul, the legislative session ends the end of May. We are expecting to come up before the Senate committee within I'd say the next two weeks, and then in the read out to the full Senate. So we -- we think in the next couple of weeks we can get through the Senate side. And then if there's any differences between the Senate and House, they'd have to sit down on joint committee and reconcile those. But right now, we are not seeing any differences.

And you don't think there'll be any type of an attempt to end the legislative session earlier, sort of in the mid -- in the mid-May time frame?

No, there is a lot of other activity going on in Texas around education and those type of things. So we don't see it ending any earlier than that.

And then slightly unrelated -- or I guess completely unrelated, if you look at some of the Capacity proposals that are in the Northeast right now, I guess LICAP (ph) and the Reliability Pricing Model, MPJM (ph), the, sort of the proposed pricing in some of those other jurisdictions differ very considerably from what's currently in place and approved in New York. Is there any thought process in New York to maybe, either to revisit their pricing or to -- or to change that in any way?

This is Gary. If you were talking about the LICAP (ph) that they're talking about. It is really kind of fallen in the New England power pool similar to what you have already seen in New York where it is broken up basically in -- into four zones, Maine, Boston, Connecticut and then there's one other, which is the rest of the pool and Pilgrim would be in the rest of the pool. VY is not impacted by that pretty much because it has a lifetime PPA.

It kind of disadvantages, I think, Connecticut so you will probably see them opposed to it. But I don't think it will have a big impact on New York. I think it's going to be how does it play out really in the pool. And I think it actually it will play to a better pricing have structure and as you are seeing to some capacity market going forward.

And are you expecting FERC approval when it comes up sort of in the -- in the June-July timeframe? LICAP (ph)?

This is Curt Hebert. Nope. I mean, there's no reason for us to believe that we will have any problems with those approvals so we will be able to expedite those.

And then lastly. How come the pricing for capacity payments is so much higher in terms of what's being proposed seems to be so much higher than what is currently in place in New York?

I mean, at this point I guess I would hazard to guess. I think what you're starting to see and what we're seeing is that there was a belief in that it was going to be an overbuild market and so there really wasn't a capacity market there. And I think what we are seeing now, and I think you're seeing in the prices in those areas and the movement in the prices specifically for [ Inaudible ] pool, that there really are, apparently, going to be constraints and I think you're starting to see that reflected in what will be the capacity market that shows up more like what you're seeing in New York.

Thank you.

And for our next question, we'll move to Paul Ridzon with Keybanc McDonald. Go ahead, sir.

I have two questions. Firstly with a clarification on the decommissioning study. It was a $.07 benefit but the ongoing benefit for the year is only going to be a of cents. Did I hear that properly? And how does that flow to make that happen? And my second question is related to slide 7 of your deck. And one your issues under nuclear is to execute new operating agreements in U.S. and evaluate other markets. Are you talking about markets outside the U.S.? I am just confuse by that wording.

Okay, starting with the decommissioning, the ongoing impact is not this year it's in subsequent years. The ongoing impact is $.07 this quarter and every subsequent year it will be about 3 to $.04 between utilities and nuclear for all of the revisions that we've made.

How should we -- what will happen in the balance of '05?

Not really anything. It's, it's immaterial in '05. It's, you know, as we go through and reset those liabilities as the -- the way the accounting works, the accretion and the recognition of it going forward, it should be spread across the remaining life of the unit. So it, it's ongoing in terms of way the liability accretes over time. Because the liability's been reset it's smaller and that's the way it happened.

Thank you.

And back to your question on the Nuclear growth. I think break that down into the U.S., I think you -- we are seeing some interest in -- by some folks to explore operational-type agreements like we have at Cooper. But we also have had some contacts from international type folks to see if whether or not we will be interested in some roll there. So, there may be some opportunity but basically we're kind of evaluating it at this point in time.

Okay. Thank you.

And our next question today comes from Deutsche asset Management's Vic Khaitan. Please go ahead.

Yes, thank you. Thank you, Wayne and Leo. My question is really a follow-up question to the previous questions asked already. But, one of the things I noticed, the production cost for nuclear Is more or less flat or so, but you had a goal to -- to improve the production cost at nuclear. So what might be the new expectation? Right now you are showing what, 18.71 per megawatt quarter in the first quarter?

Yeah, we are on track for that to continue to decrease some this year. The goal of having $100 million by '06 is still on track. We've seen a little bit increase this first quarter but in general we expect that to turn around through, through the rest the year and put us back on track.

So what does that translate into cost per kilowatt hour, target?

It is about $18 -- around $18.00 and a nickel an hour for '06 roughly.

I see. And the other question I really -- was the follow-up about nuclear opportunity, and you just mentioned that you are exploring what operational capability here in the U.S., as well as internationally. Are these -- include ownership or just the operation and how do you benefit just purely from operation without ownership?

I think -- this is Gary again. I think there is a -- really I think you see two combinations. In the United States, there are some from operating agreements, and if you look like that they are very, very profitable. If you look at the agreement we have with Cooper. So it would be something like that inside the United States.

I think you're also seeing that there is a plan for sale within the United States, which is the DeWayne Arnold (sp) with Alliant (ph). Outside, I think we've looked at what makes sense and that would be anything from a range of consulting, probably not ownership but probably some sort of operating agreement if we were to do something like that.

But does that include not only management fee but also incentive for -- for the kilowatt hour production and benefit out those?

The ones we have looked at will be a management fee and some sort of incentive built in for improving performance, because that's really where the upside is.

I see, but you won't have the ownership of those kilowatt hours though in any --

I would -- yeah, I would highly see outside the United States that we will be in an ownership position.

Okay. All right, thank you.

We will now hear from Duquesne Capital Zack Schreiber. Please go ahead, sir.

Hi, Wayne. Hi, Leo. Hi, Rick. It's Zack Schreiber at Duquesne. Just a follow-up question on Texas. Just to make sure I understand it. You know, going back -- I think back to March of '04, we'd all been quite -- quite excited in the major community about the prospects of moving the competition in Texas , and that is kind of -- kind of not gotten done based on the RTO issues and the independence of the transmission system and so forth.

Are you saying that in this sort of legislative compromise that the quid pro quo is -- is a delay in the traditional cost of service rate increase in exchange for, I guess, kind of reopening the option on -- on competition and if that's the quid pro quo, how valuable is that option on competition? I mean, is the thing we ought to be thinking about really or is that -- or is that really just not anything that I should place high odds on? Hello?

I will let Rick kind of -- Rick went over there and testified and tried to do his best to -- to get everything we wanted, which was immediate rate relief, plus reopening the option. I wouldn't call it a quid pro quo so much as it was an evolution of a lot of parties at the table, all wanting different things. Obviously, the industrial customers have a point of view. They want to get to competition. They want to have choice. They're very powerful in Texas.

So in dealing particularly with the large industrial customers, you have to be realistic with regard to what your trade-offs are and what you can get in exchange for what they are likely to get. The one thing that is very clear I think in Texas that we felt was clear all along, was that Texas wanted the tenant of the Bill was to get everybody to competition and we tried very hard, as you know, for quite some time, and we did it -- made a number of concessions like the one part rate from balance charges to try to encourage competition.

But nonetheless, we ran right into a brick wall with specific requirements for what would constitute a certified power region that just simply we could not meet. We could not meet them in large part because Texas was integrated with Louisiana. And Louisiana was not about to move toward a RTO and give up operational control. So we were very constrained in terms of options that we might be able to implement to satisfy the requirements in Texas.

At the same time, I think the staff and others in Texas were -- were pretty restrictive with regard to how they defined independence, and -- and, again, this Bill, it uses -- I think it's pretty clear with the direction it wants the commission to head, it uses words like "reasonable steps" instead of this kind of day to market kind of perfect state that a few people have, and by separating the two jurisdictions, it clearly puts back on the table the option of doing something different with Texas.

It could move into SPP (ph). We can go back to Texas and argue that our ICT is independent enough. You know, in that filing, we had every state on board except Texas, who still kept saying it's not independent enough. Well, FERC just said it was independent, so you have FERC plus the other states. You don't have Texas there, but you have guidance from FERC saying it looks good to us, and you have guidance from the legislature saying you ought to move this direction. So maybe they'll be a little more persuaded next time around whether it's the ICT or whether it's another RTO or something else that this was a direction we should move.

So we're going -- like I said, we're certainly going to push that -- push that issue. Like you said it would be silly for us To open this option up and not -- and not push it as hard as we have in the past or harder. But we want you to -- you know, it's kind of the old fool me once, shame on you, fool me twice, shame on me. And I tell you, we have been down this road in Texas, and we got shut out at the last minute, and so we want to get some rules in place or some strong guidance from the commission if we go down this path that there's -- that there's a good possibility we'll end successfully.

But the option is there. And we intend to explore it as hard as we can . But, again, the option is not there to spend a ton of money and expect it is going to be recovered. We'll work that issue. We are very hesitant at this point to make a lot of promises with regard to how it will turn out because we were optimistic before, and we were disappointed and we probably let you all down too. So this time around, we're a little smarter. And we're going to try a little harder. And hopefully the outcome will be a little better.

And just making sure I understand that from a timing perspective, how quickly will you procedurally open up this option, and if I recall going back to the slides from the Morgan Stanley conference in March of '04, you had pluses or minuses based on moving to competition under a certain gas price environment, pluses or minuses under traditional cost of service rate base. I Imagine the whole value equation is even more in favor of compensation based on current gas prices. Any way you can sort of update us on what the financial implications of it could be for number one. Number two, the process. And I guess, thirdly and related to number two, just the sort of timing and things we ought to be monitoring or is this really sort of years away, is this kind of months away.

Well, obviously the goal -- Rick Smith is sitting right next to me and he knows the goal.

Sure.

The -- as far as an estimate. At this point, you know, I hate to do this to you but we -- until we get closer to something that is tangible, we are not going, not going to -- not going to discuss what the estimate -- what the upside may or may not be from a rate case versus competition.

But it's the same kind of structure as last time we should think?

Sure, sure. Nothing's changed with regard to that. But again, one of the reasons we don't want to discuss is because -- we'll never get into it is because we got to sit down with the commission and the staff and to try to work out some kind of -- of -- of agreement with regard with how this is going to work and there might be trade-offs or something in that process that could change something or costs that we might have to pick up or who knows.

And -- and we -- we -- we can sit here right now and we know that we fought the battle last time, and we were -- and staff opposed us, and -- and opposed us very strongly. And they were able to convince the commission to shut it down, and so we are going to have to Reopen that dialogue and until we -- it's been reopened, just to put us through the formula probably is not the right answer at this point.

Got it. And in thinking about it last time, when I think I bugged you on the first-quarter call last year. My understanding was -- was that staff was really focused on you joining SPP (ph) and thought that that would be sort of a compromise solution. It felt like last time from your standpoint, SPP (ph) wasn't a viable option given the interrelationships between Louisiana and Texas. Now given the ability to segregate. Given your own mention just now I thought you said SPP. Is SPP (ph) a viable option if a day to standard no longer applies?

Well I think -- my memory on this may not be too good but look agent C trans originally when we were talking -- talking to the Texas commission on this that did call and SPP at the point was not certified as a RTO even. They didn't have and independent board and a whole lot of other things. SPP doesn't have days to market either So, you know, SPP as as -- just -- just saying blanketly, well, that will work, may or may not work. I mean, again, we've got to get the Texas staff and the commission to decide that -- that the structure of SPP is good enough or the structure of of the ICT is good enough. You know, our argument is -- our own argument is the ICT has some advances over SPP as it's structured today. That may be an quite an extensive dialogue if SPP never gets the day to markets, where the commission staff is, is -- believes that's the only way to get there. But I think SPP was one the options thrown out, but at the time it wasn't just Louisiana. It was , in the fact it was not an RTO and didn't have day to markets.

Has SPP been satisfied since then?

Yes, with -- under certain conditions.

And then the final question is there a timing of this sort of dialogue and debate playing out at the Public Utility Commission?

Yeah, Rick. What do you've got going?

Well, Zack, we'll start some conversations with them through the summer. And then we have formal filings we have to make January of '06 on really what our progress is, and then we have to follow up every year thereafter on what will be the path that would get us to reach open access.

Got it.

So I think those filings will help us so much more than where we've been In the past because it will specifically be about the progress we made and the path to get there.

Got it. Thanks so much. I don't want to over stay my welcome. Thanks so much, guys.

Thank you.

And at this time, we have time for one final question and that will come from Steve Fleishman from Merrill Lynch. Please go ahead, sir.

Yeah, hi, everyone. Hey, Wayne, in the press release, you are quoted as kind of saying that the degree of success for the regulatory agenda, both state and federal level in coming months will be critical in achieving financial objectives. Just kind on the surface it seems that the only Earnings or financial-related case that's still spending of significance is the Entergy Louisiana settlement I guess getting approved?

That's the primary case right now, and it is getting the Louisiana settlement done, and, then we, as we talked about quite a bit, we will have to figure out Texas. The ICT, we still have -- we have FERC's is kind of conditional approach. We had our ask and they had their ask and had come back with our 205 and reconciled all of that. That's very important to us for a whole lot of reasons. It takes a lot of risk away from the Company. It's 20/20 hindsight on granting service or not. It takes a lot of other issues off the table that we've argued about for two or three years. I think getting that in place could be critical to a number of other things we want to accomplish. And then we have the system agreement issue that just continues to eat up a lot of time and money to prosecute that case. And hopefully the -- you know again, that order will be coming out soon, and it will be something that everyone can live with. But all these issues, you know, as you know, Steve, some of them have explicit dollar amounts attached to them and some of them just to deflect your attention away from other things that need to be getting done. But we can't -- we can't get drug down while we are trying to create value in nuclear and cut costs and do those kind of things by the regulatory morass that we've been in over the last couple of years.

Okay. Again, just trying to understand what the statement means. There are a lot of that stuff going on, but most of it -- I mean, most of it is important , I guess, strategically, relationships, et cetera, but it's not necessarily earnings related in the near -- near term. It is really the Entergy Louisiana case?

That's right. That's right. And -- and ultimately figuring out Texas.

Okay. And then just secondly, One specific question. On the -- on the sales for the quarter, the residential, I think in your release, even the weather adjusted residential sales were down in the quarter, which is Kind of rare . Was there just some weird timing maybe with your unbilled sales or other things like that that -- ?

Yeah. Steve, the residential sales weather adjusted were down. As you know in the -- in the month like -- in the month like the first quarter, when the weather calculations are kind of difficult to understand exactly because you're not necessarily looking at -- you know it's clear that you are in cooling degree days in the summer, but when you are in March, it's not really clear what -- you know, where you are, so some of those calculations I think don't capture anything because you've got so many days where neither air conditioning or heat running or maybe air conditioning shows up. So there is a little bit of difficulty in the shoulder months on the weather calculations, and the other side of that is on build, because you know on build doesn't have weather calculations in it. And so, when you look at where we were, cross over into the year and what was going on in December versus what was going on in March, we had a big swing in unbilled revenues that contributed to that too. So it's, it's not unusual to have some of these kind of observations in these kinds of months. So -- but it's -- that said, usage per customer is down, the growth per customer is up which is good, but something we are spending some time looking at because it does -- like you said it looks a little odd.

Okay. Thank you.

Thanks, Steve.

And at this time, I would like to turn the call back over to our hosts today for any additional or closing remarks.

Thank you, operator. And thanks to all for participating this morning. Before we close, we remind to you refer to our release and website for Safe Harbor and Regulation G compliance statements. Our call was recorded and can be accessed for the next seven days by dialing 719-457-0820. Replay code 865625. This concludes our call. Thank you.

Thank you, everyone for your participation. That does conclude today's conference.