安特吉 (ETR) 2003 Q4 法說會逐字稿

Welcome to the Entergy Corporation fourth-quarter 2003 earnings conference call. Today's call is being recorded. At this time, for introductions and opening comments, I'd like to turn the conference over to Nancy Morovich. Ms. Morovich, please go ahead.

Thank you, and good morning to everyone. We'll begin this morning with comments from our CEO, Wayne Leonard, and then, following Wayne's comments, John Wilder, our CFO, will review results for the quarter. Then we'll follow with a Q&A session, where our entire management team will be available to answer your questions. And at the end, I will close the call with a brief reminder about the applicable legal compliance statements. Wayne?

Thanks, Nancy. Good morning, everyone. We're pleased to report 2003 was a year of strong earnings growth and shareholder returns and solid credit and liquidity methods (ph). John Wilder will review our financial performance later in the call. First, I'd like to provide several highlights of the fourth quarter, and from what has already started out to be a busy 2004, and then I'll spend some time focusing on our goals for the future.

During the fourth quarter, we introduced and completed a voluntary severance program. A total of 1,100 employees chose the severance package, resulting in an after-tax charge of $123 million. While this is a significant amount, it compares very favorably with the estimated annual savings of about $70 million after tax, resulting in a three-year net present value of $90 million.

The second highlight of the quarter was approval by the Federal Energy Regulatory Commission of the protocols for retail open access in Texas. You probably recall these were approved by the Public Utility Commission of Texas earlier in the year. The FERC's action brings us one step closer to retail competition in the Entergy Gulf States territory, and sets the stage to move forward with the pilot program. It also keeps us on track to begin retail open access in 2005, which provides a significant opportunity to improve upon substandard financial results in our Texas service area, where base rates have been frozen since 1999, even though we have made substantial investments for customer growth and reliability needs. Some of you may be aware that the PUCT last week affirmed its decision to allow Entergy Gulf States to move toward competition. Even though the commission indicated its intent to proceed cautiously, we're still confident that retail open access will be a reality by mid-2005.

After the quarter closed, we completed a number of other noteworthy items. We filed for a $167 million rate increase at Entergy Louisiana, several months ahead of schedule. We executed a purchase-of-sale agreement with Cleco for the Perryville plant. We closed on the sale of our 50 percent interest in a 320-MW in plant for a modest gain, and Entergy-Koch (ph) reached a settlement with the CSEC to conclude all issues that were under investigation.

Now, let me shift the focus to the rest of 2004 and beyond, and talk about the initiatives and goals we are pursuing. These goals are not new to you; they will be very familiar to you. But I want to spell them out, and make clear our targets that you can track over the coming quarter. These goals support the financial aspirations that we've outlined for you in recent presentations for continued earnings growth and top-quartile shareholder returns. Our first initiative is to improve the utility return on equity to the top quartile. We've increased our operational return on equity from about 9 percent to over 11 percent, so we're still about median, when compared to our peers. We believe that through constructive regulatory mechanisms like incentive rates, we can further improve our ROE in a way that delivers real value to our customers. As you are aware, we have two key cases before the Louisiana Public Service Commission in 2004 -- the rate filing at Entergy Louisiana and the ninth earnings review at Entergy Gulf States. In both cases, we believe the effect of base rate increase requests can be substantially mitigated by fuel savings resulting from our supply plant, in much the same way as we did in Entergy New Orleans last year. As you probably recall, we obtained a $30 million base rate increase in the Entergy New Orleans case, but the customers' retail bill actually went down, as a result of the supply plant resources replacing more costly tower purchases and less efficient generation. In addition, we have the opportunity to earn above 13 percent at Entergy New Orleans through a generation performance-based incentive plan. Our expectation is that the Louisiana cases can be resolved in much the same way, where supply plant savings mitigate base rate increases and performance-based rate-making mechanisms aligned to economic interests of shareholders and customers, rewarding both groups of stakeholders for superior performance.

Turning to Arkansas, we will file in mid-2005 to recover our investment in the steam generator replacement scheduled for completion at Arkansas Nuclear 1, Unit 1 in the fourth quarter of 2005. We have received preapproval of the need for this investment from the Arkansas Public Service Commission. Given this action, as well as the Arkansas Public Service Commission's previous action to provide a recovery of the cost of a similar project completed in ANO Unit 2 in 2002, obtaining full recovery of the expenditure should not be a contentious issue.

Our second near-term initiative is to complete the requirements for retail open access in Texas. To meet the 2005 implementation date, we need a successful pilot, FERC approval of our interim transmission structure, and federal and state approval of the business separation case. Obviously, Louisiana customers and creditors and Entergy Gulf States' creditors will have a significant interest in this filing. We have already started adding customers in ERCOT, and ultimately our goal is to build a sustainable retail business which can generate $100 million or more per year in earnings.

The third initiative for 2004 is to receive approval for our interim solution stalled CTRANS efforts (ph). The interim structure provides for operator independence, with substantial duties assigned to an outside expert, and for more efficient pricing through a transition from simple cost allocation, or what we called rolled-in pricing, to cost causation principles, or what is known as participant funding. We still support a transmission structure that incorporates locational marginal pricing over the long term, but we need to convince a lot of our state regulators that the transaction costs do not outweigh the efficiency benefits to be gained.

In Nuclear, we plan to aggressively hedge our open positions in the Northeast and to build a meaningful services business. Our immediate goal is to close new multi-year unit-contingent agreements and sell out 2005 by mid-2004, and to sell 75 percent of 2006 by year end 2004. Currently, 2004 is sold out, 2005 is 54 percent sold and 2006 is 45 percent sold, and there is a high probability sold forward (ph) positions will increase to an average of 80 percent in these two years -- that's '05 and '06 -- by the end of the first quarter, as a result of contracts that we anticipate closing very soon. Another goal for Nuclear is to execute two to three new nuclear services operating contracts with plant owners by the end of 2006. Over the longer term, our objective is to build sustainable nuclear services business that has the scale and the scope to generate $100 million in net income per year, through contracts that emphasize financial incentives tied to performance.

The next initiative is to continue to improve results from Entergy-Koch through expanding the customer business at Entergy-Koch Trading and improving profitability into Gulf South Pipeline after a year of relatively weak performance. At EKT, our goals are to continue to grow our optimization business and to expand in Europe. We are already well on our way toward achieving the goal we set out for you in 2002 -- to double the assets under management by the end of 2005. Over the longer term, we expect to build similarly strong trading capabilities and customer relationships in Europe, attributes that will ultimately allow our European trading operations to rival our U.S. business. At Gulf South, we will focus on reducing costs by resolving legal issues and putting other one-time expenses behind us. In addition, we'll focus on extracting value from relatively higher firm storage and transportation rates, as well as from efforts to recapture lost throughput, as new LNG comes into the region.

A fixed, very important near-term initiative is to reduce total operation and maintenance expense by $145 million a year, and reduce maintenance capital outlays by $350 million a year by 2006. These productivity improvements, combined with plant upgrades, will move us closer to achieving consistent 10 percent returns on total invested capital. In addition, we can improve capital productivity by redeploying capital as a high-performance investment. We project more than $3 billion of free cash flow to be available through the end of 2006. Our acquisition priorities have not changed. They are gas pipelines and gas storage, nuclear generating plants and fossil plants which can be used to meet the needs of our utility customers. We will continue to evaluate other mechanisms to deploy free cash flow, like stock buybacks and, of course, dividend levels, in line with acquisition opportunities and any successes that we might have.

I will note we are well aware of the industry track record of falling victim to the winter's curse, and we will remain a disciplined buyer, consistent with our market point of view and the demonstrated ability to add value -- for example, through operational improvement.

A final, ongoing initiative is to convince the rating agencies the financial improvements we have made are worthy of upward revision to either our credit rating or our business position or both. We will report to you each quarter our progress toward the goals I've listed, so you will be able to track our performance.

Before I conclude my comments, I want to recognize Don Hintz, who will retire as a full-time employee in April. Don has been the driving force behind the turnaround in Entergy's nuclear plant performance of its legacy fleet, the adoption and successful execution of our nuclear growth strategy, and he has served with distinction as President of Entergy since 1999. Over the last few years, Don has made a number of personal sacrifices to hold off on retirement until he could assemble the right team to carry on his legacy of operational excellence and continued improvement, not only in Nuclear but in all of our operations. Going forward, Gary Taylor, CEO of Entergy Nuclear, will maintain responsibility for all aspects of Entergy's nuclear operations. Gary brings more than 20 years of nuclear operating expertise to his new role, and he and Don have assembled an incredibly talented team that is up to the challenge of delivering productivity improvements while continuing to grow our nuclear business profitably.

Also with us today is Mark Savoff. He was recently added to our senior team as Executive Vice President of Operations. Mark is a former Vice President and corporate officer at GE Power Systems. He will be responsible for the business operations of fossil generation and the transmission organization. At GE, Mark was involved in marketing to the power industry for many years. Now that he is heading up our system-wide procurement efforts, he can leverage his experience to turn the tables on our suppliers. We expect our procurement efforts to contribute significantly to the overall productivity improvements we are targeting, and Mark can really help us reach that goal.

It is important to note that Entergy is a nuclear company. It is not a sideline; it's part of our culture. It's not just what we do, but in many respects it's how we do things -- the attention to detail, the emphasis on safety, the constant awareness of management of risks and the intolerance for errors or even mediocrity. Mark comes to us -- to our fossil and transmission operations -- after a long career in nuclear at GE. He fits what we do and how we think, and is already adding value in his own area and in interfacing with other organizations, like Nuclear.

One last word on Don Hintz. While Don is retiring as a full-time employee, I doubt that you have seen the last of him. We are in the process of working out a longer-term agreement with Don that fits his life plans and helps assure Entergy continues to benefit from Don's experience, his expertise and his sound business judgment.

And with that, let me turn the call over to John Wilder.

Thank you, Wayne, and good morning. I'll begin with fourth-quarter highlights on slide two. We achieved a 12 percent increase in operational results compared to one year ago. The primary driver of the increase was a 27 percent increase in megawatt hours generated by Northeast's nuclear fleet. As Wayne detailed earlier, and as reflected on slide three, our voluntary severance plan resulted in a higher take rate than originally anticipated, which created a moderately higher special charge than we projected.

We move to slide four, which shows our comparative results for '02 and '03. Operational earnings were solid throughout '03, exceeding the prior year's quarterly results for three of the four periods, leading to a full-year increase of 12 percent compared to '02.

Slide five reflects the earnings growth we've achieved over the last five years. Recall that our commitment was to grow operational earnings per share by an average of 8 to 10 percent annually. Our results in '03 demonstrate that we've clearly exceeded this commitment, even if the benefits of disproportionate sharing are excluded. We've made significant progress over the past five years in achieving improvements across a range of key financial measures. Over this period, operational ROE has moved up 55 percent, cash flow interest coverage has improved 69 percent and operational net margin has more than doubled, from just over 5 percent to 10.7 percent.

Slide six shows that our financial progress in 2003 measured up to the improvement pace that we set with advances across several key financial metrics. Of particular note are our return statistics, both of which improved by more than 4 percent compared to the prior year. These results demonstrate our ongoing effort to improve capital productivity as well as our investment discipline.

On slide seven, we decompose the drivers of our full-year '03 operational earnings. Utility and trading operations provided a catalyst to more than offset relatively flat Nuclear results.

As detailed on slide eight, our guidance range for '04 is 4.10 to 4.30 per share, and operational and as-reported earnings. As part of our annual planning process, we reviewed '04 earnings drivers, and continue to see solid contributions across all of our businesses. In fact, '04 earnings drivers have far less uncertainty than was the case a year ago, because 100 percent of nuclear output is sold forward, our utility rates are set for the year, and a significant portion of our productivity improvements are locked in, as a result of the voluntary severance program we completed in December. As we've discussed previously, the Entergy-Koch income sharing arrangement will be revised for '04. Our earnings guidance reflects a 50 percent sharing arrangement. Earnings growth in '04 is anticipated to be 9 percent, if both years are viewed consistent with our 50/50 ownership share in EK. This supports our near-term aspiration of continuing to deliver 8 to 10 percent in annual operational earnings growth, an aspiration we believe we can deliver on not only in '04, but in '05 as well. Our '05 results, however, will depend on how successful we are at pursuing the objectives Wayne described earlier.

On slide nine, we provide additional details and milestones so that you can track our progress in much the same way we intend to track the progress internally. In examining this list, I hope you'll find and you will agree with me that each of our businesses have meaningful opportunities which are likely to create value in '05.

While we are not prepared to provide '05 guidance until the second half of '04, slide 10 captures a number of sensitivities that we hope are helpful to you in assessing our risks and opportunities. With only a quick look, you'll notice that the upside potential appears to easily outweigh the downside potential. While I won't describe each and every line item, I'd like to highlight a few scenarios.

On the plus side, you will note first that a 1 percent increase in utility sales volume is worth about 10 cents. We are seeing some promising trends in the industrial sector, with facility startups or expansions in specialty chemical, plastics and chloral (ph) alkaline. Secondly, you will note that Nuclear can add up to 20 cents by selling its remaining unhedged '05 capacity at a price of $2 dollars per megawatt hour higher than the current EPA, and the addition of two new service agreements. And third, retail access in Texas provides an excellent opportunity to contribute as much as 20 cents, assuming $5 in MMBtu gas price, even if our implementation date is delayed until 4-1-05.

While we are excited about these opportunities, it is important to acknowledge that downside scenarios do exist. While we want you to be aware of these, we also want to emphasize that we spend a significant portion of management time taking steps to ensure we are adequately protected against these risks. And this is a primary reason why you will note that we expect to have positive year-on-year growth in '05, even if every scenario moved against us.

That said, you'll note that our primary downside sensitivity is to natural gas prices. If, for example, '05 natural gas falls to 4.50 an MMBtu, our Nuclear, Retail and Energy Commodity Services business could impact earnings by about 25 cents per share. However, this assumes we achieve no success in anticipating and mitigating this impact through our trading and marketing activities.

Before leaving this slide, I would like to point out that if we achieve only half of the total upside percentage, operational earnings would be on track to exceed our 8 to 10 percent growth goal. We are highly encouraged by this opportunity, particularly because we believe we have much better than 50/50 odds of coming out on the high side of the midpoint of the overall range shown.

And now, our senior team is available to answer your questions.

(OPERATOR INSTRUCTIONS). Paul Patterson, Glenrock Associates.

I just wanted to sort of touch base with you on that last slide. I didn't see any -- and I know this is just some of the potential drivers. I didn't see any mention of the use of the free cash flow that you mentioned earlier that you guys might be -- that you guys are expecting to be getting over the next couple of years. Am I missing that? Is it somewhere hidden in here?

No, it's not, Paul. What we wanted to illustrate were the list of operational drivers that we have in our business today. It doesn't include any redeployment of cash. There's a slight bit in there, in the supply plan, but it is very, very small. It doesn't include dividend increases, share repurchases, acquiring assets in the targeted asset classes that Wayne described in his remarks. It's probably unlikely to see any contribution from that in '04, but in '05, you could clearly see some additional benefit from cash deployment.

And then the other question I had for you was, in terms of the nuclear contracting, you mentioned that you guys look like you are close to doing quite a bit by the end of the quarter. Could you give us any idea about what kind of pricing you are seeing right now, in terms of what you might be getting?

The market is around $2 to $3 higher than our embedded '04 pricing. That's what we are seeing in the market. That's what we are experiencing in some smaller-sized contracts. And we're highly confident that we'll be able to transact in that range.

Thanks a lot, guys. Good work.

Steve Fleishman, Merrill Lynch.

I'll also thank you for the detailed corporate goal layout here. One question on the cash redeployment. Why would kind of March 31, '05 be the time for when you might review buybacks or dividends and the like? What's magical, if at all, about that timeline? Why not late '04?

Steve, this probably does sound a little too precise. When we look at our forward plan, if we are able to achieve a little over half of what we described on our '05 earnings drivers, that's about the range of time that our financial flexibility is going to be -- our financial flexibility and liquidity is going to be so strong, that we think we need to do something. That is the most plain-spoken way to describe it. So, whether it's the end of this year or early next year, it will be in that range, if we can't find some investments that meet our return standards to redeploy some of the capital.

And two, I guess, big-picture questions. First, maybe if you could comment on how you are thinking about some of FERC's recent actions on market-power-related issues, and how it might affect both your case on your affiliate contracts as well as Perryville. And then, secondly, if you could also just outline what steps are left to finalize the Texas competition initiation?

Okay, Steve. We'll let Rick talk about the Texas. Let me kind of start with FERC's actions, and then Curt Hebert's here, also, and we'll let Curt kind of jump in. I assume you're referring, in part, to the Oklahoma Gas & Electric issue, and then the recent technical conference on the supply margin assessment. Is that right, Steve?

That's right.

The OGE thing, of course, is far from done. And the technical conference hopefully brought a lot of issues to light that possibly people had not considered before. Our views on this is very, very strong, as you would expect. And at the technical conference, as I'm sure you know, there was a very predominant belief, I think, from all the experts, that the supply margin assessment has to exclude capacity that is committed to serve retail customers that don't have a choice of suppliers. Virtually no utility in the country is going to pass that test, if you use the control area and they haven't gone to competition. I think some 70 companies have already gone through that filter, and none of them passed yet.

So, to say it bluntly, I don't think it makes any real sense to apply that test and not exclude capacity that can't be sold in the wholesale market. As far as the market power issues, again, when that capacity, like OGE, is rate-based and committed to the retail customers, like in our case in Perryville, it's a cost. So if there's any economic rent (ph) to be had there, it's going to be had by the customers, not by suppliers. So it's difficult to see how that would be bad, from an economic standpoint, for the customers, at least.

For the IPPs, that decision might seem to be -- or that, not decision, that issue might seem to be in their favor. But I think, if they think about it, they'll have second thoughts. The utility, if the utility is short, is a logical buyer for that capacity. They can afford to pay more; it's worth more to them than it is to somebody else. If you take the local utility out of the mix, then the price they're likely to get for that capacity is going to be less. It's a long-standing history in regulation. The generation should be local. Franchises were handed out on the basis because of the locational nature of generation, enhancing liabilities as close to the load, and the externalities that simply associated with generation, like pollution, groundwater issues and things of that nature.

So, if the utility cannot buy the capacity -- let's say the utility contracts for the capacity, then if it's long-term, then the utility is going to want collateral. And if they can't post the collateral, then somebody else is going to rise to the top of the bidding structure. If the utility decides to stay short-term, because the logical suppliers can't post the collateral to make them credit-worthy, then the IPP is not going to be able to borrow against that contract, because no contract exists; it's just day to day, month to month. If the utility decides it can't buy within its territory because of the supply margin assessment test, then the utility would go outside of its region, and most likely pick a supplier where transmission costs would be an issue, and reliability would also be an issue. So they would have to pay less for that capacity than if they bought locally.

So the utility may also find, when they work themselves through this, if they can't buy local, that self-supply or repowering an existing unit provides reliability issues, and is actually cheaper when you consider the credit issues and other things, than buying from one of the IPPs. So I think, if the IPPs would think about the issue, they would realize that the utility provides probably the best market for them. A sale of the asset eliminates the credit issues and other types of things. And from the utility customer's standpoint, I think reliability is enhanced if the generation can be purchased locally. And for the life of me, I don't believe it makes sound public policy to pursue, whether it's a market power issue or whatever, that would prohibit utilities from buying power locally at a point in time where reliability is such an issue. Now, obviously, from those comments you know we feel pretty strongly about this issue. Now, Curt, do you want to add something to that?

There are a couple of things I would add. Obviously, I agree with what Wayne has said; he and I have spent a lot of time talking about these issues. Anytime you try to guess where FERC is going, we can all get in trouble there. Even when I was there, I wouldn't ask people to do that. But I think, in the end, what you are looking for here is try to figure out where FERC is going. Where I believe they are going to some reasonable test of market power. I really believe that's where they are going. They didn't think the hub and spoke would work -- kind of a blanket for everyone. So they want to move in another direction.

Obviously, when it concerns us, we think that it begs the question to FERC, when you look at Entergy, are you a net buyer or are you a net seller? Well obviously, we've kind of gone through that time and time again. And we are a buyer at peak. So we think it puts us in a different category.

One of the things that I do want to reiterate that Wayne hit on is the position it puts the merchants in. I think merchants might agree with some of the OGE language, and might agree with where the SMA appeared to be headed, until they are trying to get acquired themselves. And their situation is much different when they are in that position. And I think the last thing that FERC or any jurisdiction wants to see is these merchants put in such a position that they have to end up going through the bankruptcy courts, and then the bankruptcy court, as a disposing entity, has the ability to say who goes where and when they go there. FERC can fight over that all they want to, but I think it does put them in a precarious situation. When it comes to cost recovery, you know they are going to recover less at that point instead of more.

And I think you have seen some comments in the last few days from Pat Wood (ph), Joe Kelleher (ph) and Sue Dean (ph) talking about Translink. In fact, Translink didn't move forward in trying to get the incentives right for transmission. I think you're going to see more of a focus there. You know that we are filing with our independents; we're planning to do that by the end of March at FERC. So we are moving forward with that. If they get the incentives right on transmission, which I think FERC is moving in that direction, you build out enough transmission, you don't have to worry about these other concerns. So I'm hoping that's the direction they will go in. But I think we're going to be fine, as we move forward, with what we're doing at this point.

Rick, do you want to talk about Texas?

Yes, Steve. Texas -- we had a hearing with the Texas Commission last Thursday on our independent filing. And that was really a filing where it was a decision for them to continue on track with Texas retail open access, and they decided to keep moving forward. So we look for an order to come out on that probably in the June timeframe. We have had discussions with staff of the Louisiana Commission on the completion of the business separation plan, procedural schedule will be set up on that within the next couple of weeks,, and that would get us to separating Gulf States between Texas and Louisiana, we think, by the end of the year. And then another event would be the conduct of a successful pilot in Texas. That could get started somewhere in the June to July timeframe, and what the Commission has looked at before is you need six months of pilot before you can really go to retail open access. And then, once you go through that process, you'd look at a market readiness test out of the Texas Commission.

So we are looking now, with all those events happening, getting through all the approval processes probably first quarter of '05. But everything seems to be on track.

Carrie Stevens, Morgan Stanley.

I have two questions. One, I wanted to focus on redeploying your capital in terms of strategic opportunities. I wondered if you would comment on the recent announcement by Duke to put up its southeast merchant gas-fired plants, if there are any plants or the portfolio that you would have interest in. And secondly, with this push into Texas retail, I was curious if you felt you had a sufficient amount of Texas generation -- would you be looking at some of the Texas assets that may be available on the market?

Rick Smith will cover that, Carrie.

Carrie, as it relates to the Duke assets in the south region, as you are probably aware of, we've been running RFPs for new generation. The last was our spring 2003. We're still in the process of -- we have short-listed a number of companies, and I know Duke was part of the original RFP. So if those are priced right, they'll be part of that short-listing.

As it relates to generation in Texas, it's similar to what we've been -- I mean, we are utilizing our generation today, and part of the business separation plan would be to split the generation between Texas and Louisiana based on load. And there is also plenty of other generation available in that region, of the merchant variety. So I think there will be plenty of generation for the retail business.

And then, lastly, with respect to use of your free cash flow, if I remember correctly that you guys considered changes in dividend policy generally in October. And I think the current thinking is you grow the dividend about 5 percent a year (ph) on a normal bases. However, your earnings growth looks like it's slightly higher than that. Is there any thought to kind of more accelerated dividend growth, especially in lieu of other opportunities to invest the capital?

Carrie, we don't have any thoughts for that right now. But that would be one among a number of the variables that we would look at, increasing the dividend at a more accelerated rate than what we believe a structural long-term growth rate should be for. We've re-based the dividend before, and we would be very comfortable in doing that again. Repurchasing shares, as you know, is something that we are comfortable in doing when we are long liquidity. And we haven't given up. In fact, we have redoubled our efforts to try to put capital to work in these businesses in which we believe we have a very strong advantage. So we'll keep working and thinking about all those fronts. And if history repeats itself, we'll probably do a little bit of all of them, in terms of how we choose to put the capital to work.

Ashar Khan, Foresight.

Can I check, John, with you? The 100 million net income target on the Texas retail side before clawback -- if I'm right, the Texas company is at two years before the clawback. So if we take that timeline, are you assuming that that you will reach this 100 million level by the end of '06?

Well, we should be able to reach that 100 million level, in total, when we go to competition in '05. It will take us -- for the retail business only, it will take us a couple of years to build that business up to a $100 million business, for the unregulated retail and generation only. But from day one, we will be able to reset our overall Texas business from about a $55 million a year net income business to about 115 million a year, which is what we believe to be a competitive return for the amount of investment capital we have in Texas.

And then just to confirm, then this 115 becomes what level by the time you go into clawback?

Well, the 115 would probably be about 130. It would be 100 from retail generation and about 30 from distribution.

Second, I guess we saw this article in the New York Times regarding the nuclear upgrade at Vermont, and problems that might be addressed with that application. Could you just talk about that?

Yes. Don Hintz will do that.

We fully expect to be able to complete those upgrades, both in 2004 and 2005. We've been working with the Public Service Commission, and we believe that all their concerns are going to be able to be addressed. And right now, we don't see any problem in completing those two upgrades, 50 megawatts in '04 and 45 megawatts in '05.

And if I can just end up on one of your other goals on the nuclear side, in terms of management contracts, reaching that net income level that you had identified -- could you provide a timeframe of that, as well (ph), the $100 million?

Well, we are looking at being able to do another couple of management contracts in the next couple of years. We're talking to a number of utilities, and as I said before, these companies are trying to figure out what to do with their nuclear plants, either completely divest them or come up with some sort of operating contract. So we feel pretty confident that over the next couple of years, we will be able to get additional maintenance contracts, or possibly they'll go ahead and have divestitures, and I believe we'll get our fair share of those.

Paul Ridzon, McDonald Investments.

I've got two questions. Firstly, your industrial customer count is rising, but the load is shrinking. I was wondering if you could address that dynamic. And secondly, a little higher-level question -- Wayne, you mentioned about the winter's curse in this industry. And traditionally, where you have been able to add value is by kind of pursuing arenas before they become the flavor of the week. I'm wondering if you agree with that assessment and, secondly, whether there is any outside-of-the-box opportunities you see right now, where going forward it's more focused on blocking and tackling.

Let me kind of hit that one, Paul, and Rick will talk about the industrial customer segment. Obviously, if there were some outside-the-box things we were looking at, now would not be a good time to disclose it. We'd probably wait until we closed one before we told you what they were. But we are looking at things that would be a little bit outside of the box, that's in our core skills. Sometimes we define our business as a nuclear business or a utility business or whatever, instead of looking at the processes or underlying skills that you're good at, and that gets you in trouble sometimes, and sometimes you miss opportunities. And that's what we are in the process of doing right now.

As you mentioned, there's been three nuclear transactions recently which we were not successful on, and probably didn't make the shortlist, for a variety of reasons. But each one of those did not fit our success model. The Guinea plant was simply priced at a point very different than our point of view, particularly relative to its size and its location. Kewanee -- there were issues in that contract, I think, that you have heard us talk about before, that have the attributes of a firm, liquidated damage type contract in a relatively constrained area, which we tend to stay away from. The Amergen transaction that was available provided an opportunity, but you are picking up operational risks without operational control, which is another thing that we've kind of told you that we won't do.

So we're going to continue to be disciplined. We don't have any real creative ideas for you today that we are comfortable with talking about, but hopefully in the next year or so, as John mentioned, some opportunities that we are exploring will become available and be able to talk about them. I'm sorry. John?

I'll give you a quick explanation of the industrial laws. We lost about 15 percent of our volumes from our largest customers, but if you exclude co-gen losses, it would only be a 6 percent loss. So the lion's share of that was anticipated co-gen losses. We knew they were coming, we had them built into our plan; of the overall gross margin, it made a very small impact.

Andrew Levine (ph), Bear Wagner.

Three quick questions. First, can you just give those hedged numbers again for '04, '05, '06?

The '04, we're sold out, Andy. '05 we're about 54 percent sold out, and in '06 we are 57 percent sold out on energy and 53 percent of our total revenue is sold forward.

And the goal is to 80 percent by the first part of '05 for '05/'06, and then you see you wanted to be 100 percent by year end on '05/'06? Is that correct?

By the end of this year, we'll be almost fully sold out in '05. In fact, by the first quarter of this year, we anticipate we'll be about 90 percent sold out.

And then the free cash flow number -- you gave us a $3 billion number over three years? Is that correct?

That's our total amount of capital capacity. It's not necessarily a free cash flow per year number.

Are you giving any guidance on free cash flow after CapEx, dividends and all that?

It will be well over $1 billion.

On an annual or three-year basis?

On an annual basis.

Andy, let me give you those sold-forward numbers again, because I was mixing energy and capacity and revenue. I'll just give you volumes, energy volumes. 100 percent in '04, 54 percent in '05, 45 percent in '06.

And just back on the cash flow issue, I know you've had a very clear stated strategy to try to add value through adding assets or whatever it may be. At what point during the year, if there aren't any assets, or something that could meaningfully add to earnings, when do you kind of decide to buy back stock, or do something on the dividend level on the special basis, if at all?

We review that in an ongoing way, but we think it will be the end of the year or early next year until we would give that a real serious, actionable review.

So in the meantime, you have this $1 billion of free cash that may add up this year. Just making the assumption that you don't buy anything -- again, we don't know that being the case or not, but just kind of going down that road, what do you do with your free cash? Do you just put it as interest income and you leave it in the bank, or what do you do with it until it has a place to go?

We keep our revolving credit facilities down to a minimum level, probably zero. We would invest in short-term investments. We don't feel badly at all to keep a lot of liquidity in what we consider to be a very interesting investment market, if we can make a few of these potential investment opportunities work.

There's no issue with the rating agencies, as far as buying back stock at this point, is there?

We haven't had specific discussions with them on that, but when we show them the various scenarios for our forward plan, we also have scenarios of redeploying the capital. And whether we redeploy the capital in our own stock or distribute more of our free cash flow to shareholders through dividends, those are included in those kinds of cases. And they've never made a real issue out of them, as long as we are prudent and we keep delivering on all of the credit standards and performance expectations that we have mutually established with them, and we've got a very good track record with them of hitting every commitment that we've ever made to them.

Okay. Well I'd be one to probably vote for a small stock buyback. But that's just one person talking.

Vic Taipan (ph), Deutsche Asset Management.

Sorry to persist on the same question again about reinvestment, but, either Wayne or John, you use the word disciplined buyers -- your media (ph) financial criteria. So could you refresh us as to what those are?

Vic, of course, for our regulated investments, we expect to achieve an appropriate regulated return for the jurisdiction we are in. We are in kind of the low teens for ROEs now, and we would expect to have a similar kind of return if we were to make our supply plan work. And we believe that we will. For nuclear investments, particularly nuclear investments that don't come with a very long-life contracting strategy, we expect a mid-teens total capital return. And for any pipeline or gas transportation investments, we would expect kind of the low teens total capital return before we would put money to work. So we've had those similar standards now for the last six years. They've worked for us. We've had some really stunningly good investments. We've tripped up a few times as well, but on balance, we think that approach and those standards have created a fairly high-performance portfolio, and we are making it more high-performance each year, as we are able to get in and apply our unique management style and unique capabilities to the assets to get more and more productivity out of the capital that we invest.

John, one more follow-up question on this ROIC calculation, which you said for the Company as a whole, you had a pretty significant improvement goal plan. So could you remind where you are now, versus what your goal is on ROIC basis?

Well, we made good improvement this year. We indicated our long-term goal is to be in double digits, which is difficult in our business, but that's still our goal. We have a lot of difficult goals. But we are still on path to that. To do it, we have to continue to achieve these productivity gains in all of our businesses, which we believe we can. We are really structurally advantaged in the Northeast in the power markets we are in. We feel real good about our forward view on natural gas prices. We think that's going to support a very robust power market in the Northeast region. And we still think that's an achievable goal; we are not going to get there next year or the year before, but within the next five years, we think we can get this overall invested capital we have up to double-digit returns.

One final question on 2004 -- you provided some guidance, but are there any upside to those guidance, in terms of a what could make it look like those can be exceeded?

There's always upside, of course. But there's not a lot. '04 is locked in pretty tight. We've got all our production sold forward. We've got our known rate cases in full -- a full year of income contribution. We've made most of the productivity gains that we expected for '04 -- have already been taken and factored in. We have backed off fairly considerably, if you notice, from the table in terms of trading contribution. We are off 38 cents for the 50/50 sharing arrangement, and 15 cents for what we're calling conservative trading assumption. So that's an area that has always had the potential for some upside. But on balance, we think the 4.10 to 4.30 is a pretty good estimate for now. Of course, as the year unfolds and we are able to achieve some of this, we'll make appropriate adjustments. And if we need to move it up a little bit, we'll move it up a bit as the year transpires.

Martin Malloy, Hibernia Southcoast.

Could you update us on your targets for the production costs on the Non-Utility Nuclear, when you look out into '05 and '06, on a dollar per megawatt hour basis?

Okay, Don?

Well, we have made significant improvement on the production costs since acquiring the plants. We started at about $29 per megawatt hour, and in '03 we were down to $20. And in the South, the plants that are regulated plants were down -- in 2003, we were down at $15 a megawatt hour. So our goal is to get very close to what we are able to operate the plants in the South. Now, we do know that there is a higher cost of living in that area. So it's going to be difficult to get it down to the same levels. On the other hand, we have some advantages in those plants in the Northeast, where -- for example, at Indian Point, we have two identical units on the same site, which we don't have in the South. So that gives you significant advantages. So over the next two or three years, we're going to try to get those production costs very similar to what we have in the South.

David Dickens (ph), Deephaven.

Good morning. You've given some very nice detail about the drivers of '05 earnings versus '04, and you've talked about some things that are not in there, specifically the redeployment of the cash. Are there other cost pressures or drags that you can identify that we should be looking at as potential offsets to those items you've listed there?

David, we do have all of those built into our plan. We are encountering what all industrial companies are encountering; we are encountering upward pressure on health care costs, we are encountering upward pressure on pension costs; we have those fully developed and integrated into our '04 and '05 outlooks. A number of the additional costs flow through our regulated utility. That's why we really put forward a fairly aggressive productivity program in that business at the end of last year that we'll see benefits of this year. Those productivity gains will, by and large, offset the increased costs we anticipate in that business, and it will keep that business at about flat, from an O&M standpoint. So we think we've got them all identified. Of course, we think we've had additional cost pressures at our nuclear plant and security which are built into these numbers. So I don't think there's going to be anything that surprises us over the next couple of years, but if we are confronted with that, we'll just redouble our efforts to continue to get more and more productivity. We think the kind of businesses that we operate, we've got to keep these costs lines flat to declining, and we are committed to do that.

Let me just add to John's comments -- I'll ask Don to speak about it, because you may have heard this from other suppliers. Obviously, a lot of the merchants are very concerned about gas prices rising. Our merchant plants, which we talk about hedging out as nuclear, so uranium becomes an issue for us, in terms of the fuel source. Don, why don't you just talk about where we stand, as far as hedging our fuel source for our merchant plants, the nuclear?

Well, on nuclear fuel, historically, we had fairly short contracts, and a certain percentage of it came from the stock market. We have anticipated an increase in the cost of fuel, and we have gone into longer-term contracts with the nuclear fuel. So, even though we do expect nuclear fuel to increase slightly, if you look at the impact on total production costs, it is very, very small. Right now, we're looking at fuel costs to be at about five mils (ph). And even a 20 percent increase in total fuel cost is only one mil. So it doesn't have a drastic impact on production costs. So we think, with the productivity gains that we are incorporating, that will more than make up for the increase in the price of fuel. And, compared to any other fuel, the nuclear fuel has really the least volatility and most predictability. So, even though we will see some upward pressure on the fuel, it's still going to be a very, very small percentage of our total production cost.

Jessica Rutledge, Lazard Asset Management.

A couple of quick questions for you. The first is, can you give us any more color on these contracts that you are clearly working on for the nuclear fleet that you think will be basically done by the end of the quarter?

We really can't, Jessica. We've got some big customers up there. We've served them well. We've been real pleased with serving them, and we think they've been real pleased with us. And we hope to continue that relationship. But other than a real general comment like that, we really can't say anything.

I certainly understand. And then, secondly, I'm wondering how your expectations for customer growth and for throughput at the pipeline reflect your gas expectations. In other words, do you expect to see the fuel switching back off again? Or are you really expecting the customers that have switched away from natural gas to stay switched for a while, so that your volumes are lower?

That's a great question, Jessica. Kyle (ph) is prepared to answer that.

Hello, Jessica. We think that the changes, or that the reductions that we've seen will be short-term. I think, once gas prices moderate over time, we do think that, first of all, those will return. We've actually even seen a little bit of a pickup here in the last quarter. So I don't know that I would tell you that there's some volumes that are tied to absolute price that we probably won't get back, but if prices dropped back below like the $4 range or whatever, then we would probably have a chance to pick those up. Those tend to be industrial volumes, which are very competitive. They tend to be fairly low-margin volumes, but they would be ones that we would be more competitive on. One good news I think we are seeing, Jessica, is that with the price of fuel going up and the fact that some of the -- let's just say we've lost some of the short-haul volume -- we're starting to see very strong demand for our long-haul capacity. In fact, we've recently renegotiated rates for '04 that are going to be significantly higher than what they were back in '03. So we're starting to see -- even though the volumes have somewhat come off, we're starting to see in '04, we will be seeing an increase in revenues for those long-haul type customers.

And how does this work for your utility customer base? It seems to me that we've clearly had some industrial customers switch away also on the fuel switching. Are they coming back on the utility side, as well?

Rick?

Yes. In fact, Jessica, we saw a pretty good comeback from our industrial load in that heavy industrial corridor that's subject to gas prices, the last two months of the year. So a combination of us buying more capacity out of the market versus running our own unit has lowered our fuel cost to them. And that's been a benefit to them, so we've seen a little rebound in the last two months of the year of our industrial load.

And then one last question, if I may. You said at the beginning that you had had more takers for your voluntary severance program that you previously expected. And I'm wondering whether there was any concentration of employees sort of jumping into that. Do you have any staffing issues as a result of too many people voluntarily retiring from any one segment?

Jessica, actually, we targeted it fairly precisely to where the productivity improvements had already been identified through, really, a year-long process of analyzing our practices against best practices around the country, and our own best practices that we were developing. And as it ended up, I think it was probably close to about 400 in the Northeast Nuclear, about 300 in the South Nuclear and about 400 from Corporate and Utility. And that was just kind of marginally more than what we expected in each one of the areas, which was -- again, if we would have opened it up to the whole Company, we might have seen some pretty big numbers with some gaps in skills sets. But it was fairly precisely rolled out in a way that assured that we wouldn't have backfill, or would need backfill, or we wouldn't have skill gaps that would reduce our performance.

Win-win Chen (ph), ABN Amro.

When you unbundle in Texas, are you planning on calling the Gulf States, Don, or how do you plan on handling the debt there? Would you call and then reissue at the new entities?

Over time, our plan has been that -- in fact, we had that approved by the Texas Commission, and it's been in the plans with conversations we've had with the Louisiana Commission that we have like a three-year that we would call those over. So we think that gives us enough flexibility that we are not in any situation there.

And it would take place over a few years?

We would just call those bonds as we hit the economic call point.

And then secondly, if you do get your business position improved this year, would you look to get a credit rating for the parent Company?

If our business position improved, then our numbers are very strong for a BBB as a 6. If we were at a 5, we would be well over any of the quantitative aspects of the rating. It's not going to come all at one time; we know that. We're patient. So if we can get a business position improvement, continue to perform on our plan, then we think we would be very well positioned for an upgrade, perhaps 12 to 24 months beyond receiving a business position improvement.

Vikas Dwivedi, Prudential.

Good morning. I had a question on Entergy Nuclear. The long-term forwards in the Northeast market still look very strong, and I'm assuming most of that is on the back of high gas prices. What is your view on the capacity markets and the ICAP versus bilateral contracting of capacity? Is that showing underlying strength for that marketplace?

It is. In fact, we'll probably experience an improvement, '04 to '05, in total capacity revenues. In fact, it's very likely we could experience up to a 50 percent increase in capacity revenues in '05. So they continue to be strong. Where our IP plant is located, the capacity market is trading somewhere around $15 to $20 a kilowatt a year.

And then also on Entergy Nuclear, concerning some of the backlog of maintenance at IP2, does that have any potential of cutting into productivity improvements?

Not at all. As a matter of fact, many of the improvements that we intended to make at IP have actually already been made. We had a number of improvements that we made very early in the process to give us a lot more regulatory margin. As you know, we had some findings from the NRC that had to be cleared up, and some improvements at the plant that had to be done. And when we did the due diligence on that plant, one of the things that we were pleased with was even though there was a number of processes that had to be improved, the overall material condition of the plant was actually quite good. And in fact, the big components like condensers and steam generators and things like that were actually in very good shape. So there's a lot of process improvements that we still have to do, but there's not a lot of capital expenditures associated with those.

Paul Ridzon, McDonald Investments.

My question was answered. Thank you.

Andrea Feinstein (ph), Millennium Partners.

Just a quick clarification with regard to Perryville. Does the fact that you are buying it out of bankruptcy eliminate in any way the need to get FERC approval to put that into re-base (ph)?

No.

So you'll still have to go through the same process that we are seeing OGE and others go through regarding that approval process?

This is Curt Hebert, Andrea. Let me speak to it quickly. To say the same process, yes, we're going to make a filing. Yes, we expect we expect to have the approval and support of the LPSC, and actually, that will come first, as you know. But as we move forward, OGE, I'm hoping, is a bit of anomaly. As you know, they went in there and they were looking for something expedited. They came in last-minute. It was a mitigation factor in the very beginning, so I hate to ever say one filing is just like another. And I think there were some differences here. And again, I would bring you back to the fact that at peak, we are a net buyer.

Okay, I appreciate that. And then just real quick, on the 25 cents impact to your earnings, if we see 4.50 gas again, is that already net of the potential benefits that you mentioned to Jessica regarding the pipeline actually seeing a pickup in customers again, if we see gas prices mitigate back down?

Yes, Andrea, it does.

And due to time constraints, this does conclude today's question-and-answer session. At this time, I'd like to turn the conference back to Nancy Morovich for closing remarks.

Thank you, operator, and thanks to everyone for participating this morning. Before we close, I'd just like to remind you to refer to our release, as well as our Website, for the applicable Safe Harbor and Reg G compliance statements. Also, our call was recorded this morning, and can be accessed for the next seven days by dialing 719-457-0820. The replay code is 553475. Of course, you can also get the replay on our Website. This concludes our call. Thank you.