安特吉 (ETR) 2002 Q1 法說會逐字稿

Good day, everyone, and welcome to the Entergy Corporation's first quarter 2002 earnings conference call. Today's call is being recorded. At this time, for opening comments and introductions, I would like to turn the call over to the Vice President of Investor Relations, Ms. Nancy Moravich [phonetic]. Please go ahead, ma'am.

Good morning, everyone. We appreciate you joining us this morning. Each of you should have received our earnings release earlier. If you have not, please call my assistant Maureen at 504-576-4846, and she will immediately fax or e-mail the release to you.

We'll begin this morning with the caution statement regarding forward-looking language. The following constitutes the Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. Investors are cautioned that forward-looking statements made during this teleconference with respect to the revenues, earnings performance, strategies, prospects, or other aspects of the business of Entergy may involve risks and uncertainties. A number of factors could cause actual results or outcomes to differ materially from those indicated by such forward-looking statements. Investors are referred to the full text of our earnings release, our 10-K, and 10-Q filings for additional information.

In a moment, I'll turn the call over to Wayne Leonard, Entergy's Chief Executive Officer, and then following Wayne's comments, John Wilder, our CFO, will review financial results for the quarter. And, of course, at the end of the call, we'll open up for questions where Don Hiss, Rick Smith, Jerry Jackson, Kurt Ebert, Jeff Roberts, and Kyle Bands will also be available. Wayne?

Thanks, Nancy. I'm pleased to report our financial results for the first quarter of 2002. But before I address the operational highlights of the first quarter, I want to address an issue that I know is on everyone's mind, and that is the specific stance that we have taken to ally Entergy wholesale operations, our power development group, with our views of the market reality. First of all, you've heard me say many times that regardless of our strategic intent, we will not, one, engage in bidding wards for megawatt bragging rights; two, investment projects that do not, on an ex-ante basis, have a positive NTV or exceed the threshold requirements for return on value at risk or earnings at risk, or three, throw good money after bad when actual results differ from our [inaudible] projections. That pretty much explains the actions we are taking or not taking in some cases in the wholesale business, which remains a key part of our strategy.

I assure you that regardless of the various [inaudible] that we have had on the wholesale electric prices for over a year, that right now the write-offs that we are taking in this business are not the outcomes that we were expecting. From a market point of view, our direction to EWO was that we will not warehouse any significant additional merchant risk in this market for the next five to seven years. Basically, that meant long-term towing deals or power sales contracts with the outright sale of turbines or turbines with permitted sites.

Over this time, we have had discussions with no less than 80 companies on the disposition of the turbines and serious negotiations with at least seven, yet we have not achieved the goals that we've set out. In spite of this, it is still very likely that we could have billed out our entire turbine program and sold 50 percent of the [inaudible] for five years, which was our original goal, and a positive NTV for the half-that half of the project. But the problem is our own fundamental market analysis strongly indicated that warehousing the remaining 50 percent of the risk of these projects was not a good business decision.

In other words, the below-market returns on the 50 percent unsold portions would eat up the positive NTV on the sold portions, and of course, that considers the cancellation fees and other costs on the turbines if you don't build at all. Accordingly, this threshold write-off that we are taking today is consistent with our own fundamental market point of view, which again, may not necessarily reflect the bid side of the market.

We will continue to negotiate with potential counter parties that have a more bullish view of the market than we do, and if we need turbines, we know where to find them, and we have a point of view on what he price will be.

Let me take a few moments to describe the components of the charge itself. We are taking an accounting write-down of approximately $261 million after tax or $1.15 per share in the first quarter. The biggest component of the write-down relates to the turbines which were originally contracted for 1999. We're taking a write-off of $141 million after tax on the 15 turbines that are not yet assigned to projects under construction, and I remind you that we have not started any new construction in over a year since we instituted the no merchant risk guidelines.

This write-off reflects our decision to cancel all of the turbines outright, a decision that we did not come to quickly. We devoted countless hours in negotiations to restructure the turbine contract, in particular, to provide more time to complete negotiations that we were having with other parties on buying the output of potential projects or essentially purchasing our place in line with GE. But the fact is in the end, we cannot find that elusive win-win solution that everybody talks about.

This Friday is a critical date in our contract with GE when all the cancellation fees move up in accordance with the delivery schedule, but in particular when the cancellation fees for two of the 2002 turbines jump from 40 percent to 100 percent. So tomorrow at 5:00 p.m., if we don't cancel, we essentially own those two turbines.

As hard as both GE and our people worked to find common ground before this deadline, we could not agree to restructuring terms that in our mind were consistent with our point of view and constituted a good risk reward tradeoff. To GE's credit, they've provided a lot of alternatives, alternatives that would have substantially reduced the special charge that we are taking this quarter, but again, in the end, the best deal for Entergy was triggering the cancellation provisions which otherwise would escalate substantially tomorrow under our existing contract.

We strongly believe that this is the right decision, one that will be apparent to you not by what you see, but what you won't see in our financial results over the next few years. For example, Entergy will avoid $1.25 billion in additional costs to complete development of all 15 turbines, and will avoid what could have well turned out to be an ongoing annual cash shortfall of $10 million or more per year per project. Assuming five projects over five years, the avoiding cash cost between construction and cash operating losses could be around $1.5 billion. In addition, by triggering the cancellation of the turbines today from a cash perspective, GE actually owes Entergy money as the progress payments on the turbines exceed the cancellation fees which are now due.

The second major component of the write-off we are taking is associated with Dam Head Creek. We are writing off the entire $55 million of equity we have invested in that plant. This equity represents only 10 percent of Dam Head's total capitalization as the remaining 90 percent is true non-recourse project debt. Although Dam Head Creek is an extremely efficient plan that has operated better than expected the sparks spread in the UK has been as low as one pound per megawatt-hour over the last three to six months, and we do not see a recovery in sight of the significance required to meet our investment criteria. To keep the project debt current, we would have to increase our equity position by 50 to $100 million or more. Quite simply, we were not willing to make such an incremental investment, given our point of view in the UK markets. As you all know, we paid up front to put in place non-recourse debt to protect against unexpected events such as this.

At this time, I cannot tell you what the banks will do, but needless to say, we have been in and continue to have discussions with them on restructuring alternatives. If the decision is to turn the project over to the banks, we will be removing $454 million of non-recourse project debt from our balance sheet. We're also taking write-downs on two economically impaired PE plans in the U. S., the Warren plant that was completed last summer in Mississippi and the Creek plant, which is nearing completion in Illinois.

Like Dam Head Creek, these are good operating plants, but consistent with our market point of view, their current value is well below what we have invested in them. Total write-down on these two plants is $63 million after tax or 28 cents per share to bring you the net investment in these two plants down to an average of $219 in KW. Again, it's important to point out that this write-down simply reflects Entergy's proprietary point of view of market prices applied to the assets on our books.

Obviously, not everyone shares our point of view. But while we are taking a write-down for impairment of these assets, others are announcing new green field plans at exactly the same technology and exactly the same markets. Because we have ceased new development of green field projects and canceled other projects that have been improved for development, we will also be writing off $22 million after tax of previously capitalized overhead and reducing our burn rate further to about $20 million a year. This represents an 80 percent cots reduction over the last year.

Going forward, this amount is really more of an investment devoted almost exclusively to protecting and monitizing the value of the existing portfolios of originated positions, sites, and projects. There will be an additional charge, 10 to 20 cents per share, primarily for severance costs, but under the accounting rules, this charge cannot be recorded nor properly documented, which will not be until the second quarter when it will be recorded as special item.

We combine with the amount we are recording this quarter. We will still be within the $1.35 per share maximum we told you about in our guidance pre-release. Of all the components I've described, the severance piece is the only one that results in incremental cash cost to Entergy. Let me take a moment to pull all these charges into the context of what they mean for our wholesale strategy. Our European strategy can best be described as optimally harvest, and our U. S. strategy as simply a workout plan. In Europe, we believe we have already created significant values in early development, permitting efforts in Bulgaria and Spain. For example, the government of Bulgaria recently approved a tariff on the Moritza plant, which significantly enhances the current value of that project. We wills eek to monitor the value of these investments either through site sales or by bringing these projects to completion, provided that they meet our risk adjusted return metrics.

In the U. S., we have both long and short positions that need to be managed. Options like permitted sites can still be exploited, institutional knowledge of the transmission of the power markets, and an exceptionally strong trading skills and systems. We believe the market is very much in disarray in the U. S. and ripe for consolidation in asset sales, a nightmare for the participants, but a banker and a lawyer's dream.

We continue to believe the opportunities in the U. S. will be substantial if we maintain the necessary capabilities to act, including a strong balance sheet and the discipline to execute consistent with a well-founded market point of view. When you add all of our decisions not to build out the turbines, not to invest more equity in Dam Head or absorb ongoing cash losses on new power projects in the U. S., and to cut the burn rate in power development from $100 million down to $20 million a year, the cash improvement is somewhere between one-and-a-half to $2 billion over the next five years.

Before I move to operational results, I want to repeat that the actions we are taking today in terms of the write-downs and the scale back of power development is not the outcome we expected. The market collapsed even more quickly than we forecast, and I'm not sure that anyone was more negative than we were. Again, as disappointing as the special charge is, the actions we were taking are completely consistent with our commitment to execute on our current point of view regardless of how painful that might be, and not throw good money after bad. With a healthy balance sheet and strong cash flows, it would be foolhardy to impair this enviable position by either pursuing the passive green field development in an already over-built market or by restructuring the GE contract in a way that defers the accounting pain, but magnifies the risk and commitments we are already struggling with. In other words, we cannot allow accounting issues like write-downs or write-offs or simply the lack of sleep over some cost or past decisions that we cannot change now to cloud our current business judgment.

With that, let me turn to a happier topic, the first quarter performance of each of our businesses. The energy commodity services segment delivered excellent results in trading and pipelines. And again, this year, Risk Magazine, recognized Entergy-Koch trading for leadership in its markets with six top three rankings in gas, power, and weather derivatives. These rankings were a strong statement of Entergy-Koch's leadership because they're determined by the votes of banks, brokers, end users, and traders worldwide, and more importantly, EK's superior financial results continue or reflect their unique point of view, capabilities, and successes in up, down, and flat markets.

Nuclear continued its excellent financial and operating performance as well, with the capacity fact of our non-reg fleet topping 100 percent. Also, we're on track for financial close of Vermont Yankee by this summer. We've secured FDC approval in late March following [inaudible] approval in January. For those of you that either live in New York or read The New York Times on a daily basis, you already know that there is an aggressive PR campaign underway to close Indian Point. It's important to point out, though, that as of now, it's just that, a PR campaign. At the same time, we are doing perhaps the most important thing we can do at Indian Point, get in the operational performance of the twin units to a level never before seen at that site. This we believe will go a long way to help convince the public that Indian Point is safe, reliable, and vital to the interests of the citizens of New York. That's the message of our PR strategy, and for what it's worth, it's absolutely true.

Turning to our regulated nuclear operations, we just completed a scheduled outage in Waterford 3 lasting 25 days following only four hours short of a world record for units designed by combustion engineering, with no lost time accidents, and the cost of the outage was the lowest the site has ever achieved. The outage gave us a great opportunity to respond to the NRC directive concerning potential corrosion and pressurized water reactors.

Under the watchful eye of the Entergy inspectors, we did a full bare metal inspection, and we did not find any corrosion or any other issues at Waterford, and I will remind you that we did that with the shortest outage ever and at the lowest cost ever. We also just completed a vessel head inspection at AN02, and no problems were observed there either. In fact, we don't expect any Davis [unintelligible] type problems in any of the Entergy plants.

Previously, we had some minor corrosion at ANO in one inspection, and it was completely repaired without any delay during the last refueling outage. Now, turning to the utility, we can report progress on two important regulatory fronts this quarter. First, the utility reached an agreement in Arkansas with the Arkansas Public Service Commission staff, the Arkansas Attorney General, that addresses payment for the costs of the December 2002 ice storms. The agreement applies monies set aside in a transition cost account, the TCA, to offset storm costs which approach $200 million, and more importantly, lists the ROE cap that has been in place since 1997. This agreement is being contested by the Arkansas Electric Energy Consumers. That's a group representing certain industrial users. It's important to note that they are not arguing that we shouldn't get our money back. Their position is that there should be a refund of the TCA and then a rate increase to pay for the storm damage.

Secondary progress related to our transmission proposal, the first issue is the 206 filing at [inaudible] I talked about in February related to our generation and balance agreement. This complaint by Exalon, Calpine, Reliant, Williams and others, argued that our existing rates, administration of the tariff, and our conduct was abusive. The FERK [phonetic] threw out all aspects of the complaint that I've previously characterized as being outrageous, given the real facts, setting only the basic hearing-basic tariff for hearing.

On our C-Trans proposal, we, along with our partners, made progress during the quarter by establishing a stakeholder advisory committee. We're also working toward a mid-June filing at the FERK where we'll ask for more guidance and feedback on the structure of our RTO. We are more optimistic today than we have ever been that the FERK will find that our RTO meets the requirements of Order 2000, and we have good reason to be. As you know, we've been strongly advocating locational, marginal pricing to manage congestion. This was becoming a major policy issue dividing us and FERK. But we are very encouraged by FERK Chairman Pat Woods' recent comments on that issue. As you may have seen, Electric Power Daily reported in March that Chairman Woods said that the upcoming standard market design rulemaking would likely favor L&P as the preferred congestion management system for RTO. The article said that he admitted being the late, late convert to the system that said, "Converts are sometimes the most zealous people, so let's just get there." That's the kind of attitude we need, and the direction to move to locational marginal pricing is right on target. And with that, let me turn it over to John Wilder for the financial review, and he can tell you how we are right on target for another record-breaking year in operational earnings. John.

Thank you, Wayne, and good morning. I will review first quarter results, which, absent the special charges we recorded, again reflect the fundamental strength of our businesses. I will also provide some additional details on the special charges of market-to-market positions and our forward power sales. Finally, I will close with a view of our earnings going forward. For this quarter, Entergy realized the loss of 35 cents compared with earnings of 69 cents in 2001. Special items totaled negative $1.15 per share as Wayne discussed. I'd like to take a moment to describe the accounting treatment of the charge and the impact it will have on our financial statements. In the current quarter, we've recorded a $401 million charge to other operations and maintenance expense that is partially offset by $140 million reduction in deferred income taxes spent. From a cash flow perspective there is no incremental impact in the current period. We will, however, make a $220 million cash payment in the second quarter to the turbine trust, which will appear as an outflow on our cash flow statement. We're required to make this cash payment under the turbine financing arrangement regardless of the decisions we announce today. Because of this pending payment, about half of the $400 million charge appears as a reduction to our March 31st balance sheet. The remaining half will be charged off the balance sheet in the second quarter. Turning to our operational results, consolidated earnings were 80 cents per share or 7 percent above first quarter 2001 despite somewhat less favorable weather this year. For the utility, operational earnings per share were 45 cents, representing a 13 percent reduction from the first quarter '01. We again saw lower customer usage quarter-to-quarter, but industrial sales appear to be bottoming out, suggesting a potential improvement later in the year. Earnings were also reduced by higher operations and maintenance expenses relating primarily to our generation fleet. This level of spending is consistent with our previously issued guidance for the utility, and we expect O&M for the remainder of the year to be flat compared to '01. Our non-utility nuclear business, E&I, contributed 18 cents, a 38 percent increase over last year's results. The increase reflects the positive contribution of Indian Point, too, which was added in September of last year. Entergy Commodity Services contributed 20 cents to operational earnings in the quarter. This quarter's results include three months of operations at Entergy-Koch, while first quarter 2001 included just two.

In addition, the venture achieved excellent results in gas trading and had a solid contribution from the gas transportation business. These favorable effects were partially offset by the impact of lower spark spreads, realized that Entergy wholesale operations, on the portion of output that was not sold forward. As I've previously noted, we operate Entergy Commodity Services as an integrated business, but we do recognize your interest in trying to distinguish the contributions between our marketing and trading activities and our generation activities.

One way to separate out the performance of our generating assets is to assume that 100 percent of its output was sold at spot prices during the period. This scenario would have generated a hypothetical after tax loss of approximately $18 million based on actual output of 1,300 gigawatt-hours at spot prices averaging $24 per megawatt-hour. The per-share equivalent is negative 8 cents, which serves as a proxy for the portion of ECS earnings for the quarter that are attributable to generation.

There has been recent attention on the subject of market-to-market accounting, and we want to give you some details about its application at Entergy. Let me first say that we apply it as prescribed by generally accepted accounting principles. As a result of this application, 17 percent of consolidated operational earnings or 14 cents per share in the first quarter are the results of market-to-market accounting. 99.7 percent of our market-to-market value is based on prices actively quoted and other sources such as publications or indices, and the duration of our current trading [inaudible] continues to be fairly short, with 26 percent converting to cash within a year or less and 90 percent converting to cash within two years.

Now, let me briefly review the market exposure of our non-utility generation portfolio, including both nuclear and EWO. Currently, 97 percent of our projected output is sold forward in 2002, and 91 percent is sold forward in 2003. Specifically, for Entergy nuclear generation, 100 percent of the output is contracted in 2002, and 97 percent in 2003. For Entergy Commodity Services, 89 percent of the projected output, its generation, is contracted in 2002. This figure reflects the capacity factors on these units that are substantially lower, given our current forecast of summer prices. 70 percent of the output from ECS generation is currently under contract for 2003. With respect to 2002 earnings guidance, we are very confident in our ability to achieve our stated guidance for operational earnings this year in the range of 340 to 360 per share. We acknowledge that year-to-date results include two favorable factors, weather and a disproportionate share of income from EK, which could cause us to increase guidance later in the year. Because of the inherent uncertainty surrounding these two factors, we can't make this adjustment until we see at least a portion of the summer months from which most of our earnings are derived.

If these factors remain positive, then it is reasonable to anticipate that we will adjust the guidance accordingly. For now, however, our official guidance remains 340 to 360 per share on the assumption of 50 percent sharing from Entergy-Koch for the full year. You may be wondering why our guidance range is not positively impacted by the EWO restructuring decision we announced today. In fact, these decisions were instead required to hold our guidance range at the current level. As we approach the end of the first quarter, we expected to lose an amount equivalent to about 30 cents per share in EWO for the year driven by a 15-cent loss at Dam Head Creek, a 5-cent loss associated with U. S. operating plants, an overhead of about 10 cents per share. Absent the actions Wayne described, this would have required us to lower our guidance for this year. Given the actions we've taken, however, we now believe EWO will lose no more than 10 cents per year. This is a worst-case outcome based on the elimination of Dam Head Creek, a no-revenue scenario for existing plants in which fixed costs of 7 cents are incurred and 3 cents per share of overhead.

In today's forward spark spreads, this estimated loss is reduced to negative 3 to 4 cents, and our goal, of course, is to achieve at least break-even results or better in this business. We plan to provide details and earnings guidance for 2003 at our analysts meeting to be held June 13 and 14 here in New Orleans. For now, let me simply say that we main committed to our targeted average annual growth rate of 8 to 10 percent, which we believe is very achievable, given our current portfolio of businesses.

To illustrate, let me provide an example. If our utility business grows at 5 percent, based upon achieving recovery of incremental capital investments of $1 billion with moderate low growth of about 1.5 percent and if Entergy Commodity Services grows at 10 percent, based on the attractive growth opportunities of our strongly-positioned trading business, and if Entergy Nuclear grows at 18 percent based on achieving that 3 percent improvement in nominal production cost and adding a full year of Vermont Yankee, then EPS would grow at about 8 percent in 2003. And, of course, this level of growth would be further enhanced by any incremental investments we would make and any improvement in operational performance. We believe that attractive investment opportunities will materialize over the coming quarters and assets like transportation storage and generating plants that we have a competitive advantage in operating. For example, if the companies that own these asset types were to sell assets instead of issuing equity to achieve a 50 percent debt to total capital ratio, over 30 to 35 billion in assets would have to be sold.

Although this might seem like an extreme case, we believe a meaningful portion of this amount will ultimately have to be sold. As we've discussed before, our return requirements are fairly stringent. While these requirements vary depending on the type of asset and commensurate with the risk, we would expect that in the aggregate, our investments would produce an MPV capital productivity of 20 to 30 percent and return on investment capital of at least 10 percent over a five-year period and 15 percent long term.

And now our senior team will answer your questions.

Steve Fleischman with Merrill Lynch.

Just a couple of questions. First, to clarify, by having pursued these actions, John, I think you said you basically saved 30 cents a share this year on an ongoing basis of losses?

Right. We reduced it, Steve, from about 30 cents a share run rate to about 10 if we get no revenue, and we, in using today's forwards, that would reduce it down to about three or four, and it is our expectation that that would be zero, so it is a 30 percent reduction run rate.

Okay.

30 cents, not 30 percent.

All right. I guess on the topic of your point of view, could you give some perspective whether your point of view is kind of worse than what the current forwards are, particularly, I guess, for spark spreads, or just that they don't get any better than what they are now?

Kyle, do you want to address that?

It's probably more of the latter, Steve. We're looking at, you know, reserve margins that we think are extremely high. They're going to be in the 30 percent level for probably at least the foreseeable future, and at that point in time, our feeling is that spark spreads are going to be very depressed, and not until you probably get reserve margins, you know, certainly below the 20 percent level and down into the teens are you really going to start seeing any kind of significant improvement, so that more or less is the summary for why our point of view is what it is.

Okay. Now, I know-that said, you guys have been very focused on transmission constraints in the markets, and part of the strategy was to make sure you got these units, plants, and/or the plants you've already built on the right side of constraint. How does that fit into this picture?

That still is one of the opportunities that we have. If you look around the country, you're consistent with what Kyle just said. From a big crayon standpoint, you know, everybody needs to keep in mind that the old days of utilities talking about 15 to 20 percent reserves, that may have been appropriate at that time, but at that time, what we had was 500 to 1,000-megawatt coal units on the margins with ramp times of 16 to 24 hours, with very little shaft diversity at all because your plans were tied up. All your megawatts were tied up in two or three plants.

And now where you've got small plants, you've got a lot of shaft diversity. You've got RTOs. You've got elimination of a lot of the transmission issues. You've got these new efficient gas speakers that can almost instantaneously come to market. Reserves are-it's a very high number. Until you get into the single digits from a big crayon standpoint, I mean, you're really still talking about a lot of capacity out there than can respond. The areas in particular where the transmission constraints that we're very familiar with, of course, is even though [inaudible] is going to be overbuilt, but Entergy is certainly the most over-will be the most overbuilt in the country, and we know the Entergy system well. There's still transmission constraints in our area. We've been in both Zurich and SPV over the last few years, so we know both of those regions.

We have certain areas targeted. In the New York power pool, of course, you have substantial transmission constraints along with just shortages in certain hours, also. You're very close. In the upper Midwest in the main area, that portion, there are some issues up there with shortages, but we're spending most of our time, as you've indicated, Steve, on trying to identify-and we have identified, but it's going through the real-time changes that occur on the congestion models that we have today.

You know, as I indicated, since we announced Crete, for example, and we're taking an impairment loss on that. We've had 3,000 megawatts in a very small area of peaking projects, but now since we announced ours, in the Warren area, Duke and Calpine alone have announced almost 9,000 or in our building, 9,000 megawatts in the same area that Warren is, and that's-we thought that was very close to being overbuilt when we built that plant.

So it's a market that's very fluid and changes relative to whether utilities are going to build and whether they're going to seek bids or just build on their own, and exactly what kind of congestion constraints are going to be alleviated by these RTOs or independent transmission companies. It's a long answer. There really is no short answer to that, and it changes almost every day, frankly.

Okay. Two other quick questions. First, given that you've reduced the substantial capital requirements and also that since your point of view appears to be so much more cautious than it seems like many others might be, are you still considering using some cash to buy back stock?

Yes.

Kind of what's the status of that?

Well, obviously, with the Seabrook auction behind us, that was one of the factors that I think John mentioned last quarter that we were taking into consideration. Seabrook has come and gone. The-although certainly we never, never had even anticipated allocating that kind of money to that plant, but nonetheless, that's behind us. We have other issues. Like I said, we're in the process of disposing of the turbines. We've had discussions with so many different companies. We have a lot of opportunity on the investment side with companies who have given what we would think of as distressed assets. We're having discussions with those companies, though, with regard to the price that we think makes sense to us. So we're pulling all those alternatives, and at the right price, investments, good investments still rises to the top of all the alternatives that we have.

But a buyback of our own stock is right there under a good investment. I think [inaudible] is probably number two on our list.

Okay. One last question. If you could, just remind me when the Entergy-Koch sharing arrangement goes-expires? Is that at the end of '03?

That's correct, Steve.

Actually, my question's been answered. Thank you.

Next, we'll hear from Sam Mandilla with Suisse Credit Lyonaise Securities.

Hey, guys. I have a couple of quick questions. I guess the first one was related to the new RTO structures and, you know, basically could the boundaries be changed, and be redrawn in certain cases? I was wondering if that also factored into your analysis regarding the generation facilities. That was one, and then for a second, you're one of the companies that has not doubted the structuring/origination part of the business as, you know, a huge [unintelligible], and, you know, I would like to hear about some of the risks in that business from you guys.

On the RTO question, you know, we've always assumed that ultimately, [unintelligible] would get it right regardless of how many RTOs that we ultimately had that we would have seen agreements between the RTOs, which we are in the process of actually getting, as you may have read, with TVA and the Midwest ISO, so you essentially have these interconnected as kind of one seamless region. So we've always considered that in our factoring of whether plants make sense or not. John, do you want to respond to the second one?

Sam, on the-well, I don't exactly know what the other companies are saying, but we do have an originating business, and we're building it. We don't think it's going to be a savior in this market. There are very few counter parties transacting with any kind of length on their contracts. We think there might be an opportunity in this distressed market to purchase some of these longer-term contracts that other people have entered into and are having trouble performing on them, but we do have an originating business. It does perform for us, but we don't see that as being a way to work out of this-this current market environment we have.

All right, that's great, and just one last question regarding the transmission in the connection policy. Now you know I understand that there are still some issues in Mississippi and some of your other areas as well as to who will pick up the cost of upgrading the whole system from connecting all these plants in your area. Obviously, not all the power will be used in your system.

That's right. Let me-Kurt Ebert, as all of you know, used to chair the FERK before he came over, and this was an issue that Kurt was certainly very involved with when he was in FERK, and he's been very involved with here, and at the state level in particular, so I'll let Kurt now respond to that issue.

Yeah, let me just hit it quickly for you. As you know, there's a nofer [phonetic] out there, and the nofer on these agreements and what they're going to do with generator interconnection agreements is a little better, I think, than 250 pages, so it is substantial. I haven't gotten through the entire thing yet, but I can tell you, we think we're going to be able to work most of these agreements out on our own, and certainly, we invite FERK to give us some type of standardization and rules and procedures as long as we've got an opportunity to be heard and do what's in the best interest in the end, of the rate payers and the shareholders.

The part you brought up with the states actually goes to a ratepayer issue and how that is going to be paid for. it is certainly an issue that is between the states and the federal government. As far as how that issue applies to us, if it is something that is going to be ordered by FERK, which looks like it may well be, we're going to be required to upgrade. Those are incurred regulatory costs, and we will recover those costs either through FERK or either through the state jurisdictions.

If they are not recognized by either one of those jurisdictions, we will litigate, and we are protected by the law, and we will win.

All right. That's great. Thank you.

Thank you.

And moving on, we'll hear from Jessica Rutledge with Lizzard [phonetic].

Hello. I was just wondering if you could give us a cap ex update or an update on your cap ex expectations for this year and for next year, given all of the changes in commitments that we've had with these write-offs.

Jessica, I'll give you a three-year view, because that's really the most reflective of how we think our investment patterns will play out, and I'll also give you cash flow as well, because that kind of helps put it into perspective. We have about 800 million of cash. We'll generate over the next three years five-and-a-half billion of OCF. We will have about 1.4 billion of debt capacity to keep us at a fifty-fifty debt to total capital level. That gives us about 7.7 billion of cash over three years. We'll invest 3.3 billion in maintenance capital, invest about-a return of about 900 million back to our shareholders and their dividend, and that leaves us with 3.5 billion to invest in growth and step-down investment opportunities while maintaining all of our financial flexibility codes.

And not willing to break that down to a more year-by-year look at when you need and when you have the cash?

You could almost divide it by three. It doesn't quite happy that way. I mean, on the investment side, the investment opportunity cap ex, specifically, the maintenance capital is about equal over the three-year period, and the cash flow is about equal over the three-year period, but we think the investment opportunities are going to come, as you were expecting, kind of in chunks.

You will have some distressed assets potentially emerging over the next couple of quarters. We might invest five, 600 million, and then have to wait two or three quarters until we get something that meets our needs, maybe four or five quarters, so the growth investment capital is the one that's least ratable. The others are pretty ratable.

And our next question will come from Kit [Inaudible] with Morgan Stanley.

Good morning. I wonder if you could give us a little more of a view on your outlook on assets, acquisitions, possibilities. In particular, I was struck by your mention of your write-down of the peakers to 219 kilowatt. Coming off of that, what would be-if you were writing down a new combined cycle today, what would you write it down to, roughly, are those-are these, this kind of peaker asset value, is that indicative of what you might be willing to pay for new plans?

I think that's pretty close. I think in most regions, the peaker's 200 is probably on the low end. You might go as high as 300. Most regions would support 200. On combined cycles, probably the low end in certain regions is 300. It could go as high as 400 in some regions. The one thing I will caution you on combined cycle units is some of those units may be worth nothing.

If they're in the wrong region, they will not get dispatched. I mean, they will not get dispatched enough to support buying them almost at any price. There's some areas because of transition constraints and you happen to be in a generation constraint or a generation area where you're constrained in and you can't get out, and everybody's going to be competing in that fuel cost, so you wouldn't want to buy that plant virtually for anything, because there's no real return, rarely enough to cover your fixed O&Ms and nothing on capital or of capital, so you have to be very cautious on combined cycles in particular.

Peakers, of course, are a little different instrument, but that-I would say, you know, consistent with what you said, $200 on a peaker is probably going to work in most areas, and 300 on a combined cycle would probably work.

Thanks. Can I follow up on two related questions? One is have you seen any movement? I think you were suggesting you might have on the part of potential sellers getting towards realistic prices like that, and then the second related area, is there, in your view, we should reasonably expect any nuclear opportunities that may be involved in, you know, the next couple of years?

Well, Kit, I'll speak to the non-nuclear, and then we'll let [Inaudible] speak to the nuclear. But we're dealing with a lot of potential counter parties on the investment side. We're getting real favorable response. We can't provide you with specific company names, but we find people willing to talk to us. We're approaching them with specific ideas that we think will-investments that we think will work for us and we think would help them solve some of the issues that they have, and we're finding these counter-parties to be approachable. One comment I'd like to give to the point Wayne was making on the TCGTs, we recently looked at one, and we priced it down to $55 a KW, and it still generated 10 million negative cash for five years and 6 cents negative earnings for five years. It was a unique situation for us, but the-I think it's likely these accent values would just be all over the map depending on where they are and depending on whether they have any dual fuel and weather optionality built into them, and we're just going to look at each one of them one-by-one, but here's Don, and he'll respond to the other opportunities.

The announced auctions, I mean, Seabrook was the last one, and I don't think you're going to see a large number of auctions until, you know, sometime down the road when deregulation may be more in vogue. On the other hand, you know, as we've said, we continue to talk to the owners of companies that have one or two nuclear plants, and they still intend to divest them, and we're working with them, trying to come up with some arrangement where, you know, through a lease or a management contract or something like that, that they could get some of the synergies and some of the benefits of a larger nuclear company without an outright sale.

And in one case, we're working with a company that, you know, seems pretty receptive to take it to their Public Service Commisison, and it would be a-you know, just taking the nuclear unit out to see if they could do something with that, even though deregulation isn't taking place in that state, so, you know, we're working with these companies to see if we can come up with some management arrangement or something that does make sense, but without deregulation, I don't think you can see a lot of these plants on the market.

Moving on, we'll hear from Rick Shobin [phonetic] with Zimmer Lucas Partners.

You had mentioned before that you see potential upside to your earnings guidance with two things, one of them being weather, and the second one being energy commodity services.

Right.

And I was wondering if you could speak just a little bit more specifically about where the upside would be coming form in the commodity services business, and then what your expectations are for the summer in terms of volatility and gas pricing, and what you guys are going to be seeing there.

Okay. There are a couple of things I'll mention on that, and I'd also like to mention one other potential upside that we have, but on the energy commodity services business, we have agreed to a sharing arrangement on our income that enables us under certain conditions to receive more than 50 percent of the income from the partnership, and we will guide you on a fifty-fifty sharing.

However, as I've mentioned, in the quarter we achieved greater than that, so that component alone could drive our performance above consensus and could drive performance above consensus up to, you know, a dime to two cents, something like that. Another opportunity that we have from an upside standpoint that I didn't mention is our capacity factors in nuclear.

We assume a low 90, high 80, depending on the unit capacity factor, and as Wayne mentioned in his remarks, we achieved over 100 percent for the first quarter. Weather always swings us around. It can swing us minus 10 to 15 deposits, 10 to 15, so we've always been cautious in raising guidance before we get to the summer.

And my last question is, do you guys assume any sort of rate increases at any of the utilities in your '02 guidance?

Rick will respond to that.

No, no. We are assuming that we won't have any rate changes for 2002. We have some, as Wayne mentioned, the Arkansas settlement that really delays any rate filings until January '03, so we think that's a positive result for us on the utility. We will be filing for probably above 25 million in New Orleans this year, but that won't be fully litigated until 2003. And in the other jurisdictions, we really don't see any rate changes this year, but there will be different filings in Louisiana.

Our next question comes from Zach Schreiber with Silacap [phonetic].

Hi, guys, it's Zach Schreiber from Silacap. Can you hear me?

Yeah, Zach.

Just a question on sort of transmission constraints and this whole sort of idea as to how, you know, changing regulations is going to impact the market. Is it really an issue that you guys expect that the way power physically flows is going to change as a result of, you know, changes in the RTO structure, or is the way the power flows really not going to change, and that's really sort of set by physics, not by regulation and the economic pricing regime?

Let me just hit that at kind of a high level. It's going to be a combination of all those things, you know. Today under the contract [inaudible], power flows, of course, under the laws of physics, and there's no compensation to anyone other than the person that has the contract, so, you know 95 percent of it may go through other people's system, but the guy with the contract gets all the money.

Got it.

Now, if you're an LSP model, what's going to happen is that the power compensation will go to the lines and to the-who actually carry the flow, and the generators will get dispatched based upon the most economic dispatch considering both transmission and generation, and what that will mean is in some cases, that the most economic generation, the lowest-priced generation, may not get dispatched at all.

Sure.

Because of the transmission issues associated with it. So what that will mean is, kind of to your point, is yes, it will change the physical flows in some cases, because different generators are going to be running.

Okay, that's helpful. Thank you. More specific questions on the whole stock buyback question. John, if it is sort of number two on your list, I was wondering if you can sort of bracket it for us from a timing perspective, especially in light of the fact that we did not win Seabrook. What are the other factors that sort of tie into this decision aside from evaluating distressed and attractive investment opportunities? Where are we with the rating indices?

The only relation we have is the-are the other opportunities, Zach, and that's what determines our consideration. I can't really bracket the timing because we think we're too early into this asset sale market, and we haven't been told no enough around the kind of investments that we think we can make, to say that we don't think the distressed sale market is going to take off. We've had very positive discussions with the agencies and continue to.

We have shared with them our restructuring plan and our wholesale business, we've publicly announced it. We've received positive responses from all the agencies on our plan and on those actions, and we are-we really think that there's going to be some good investment opportunities with these over-leveraged companies, and we want to try to play that out. We think that's the way to create the most value for our shareholders.

We've got strong financial flexibility now. It's a great time in the market to capitalize on that, and we think that's the best use of the funds right now, to try to wait this out.

Great. Embedded in the guidance to 340 to 360, what kind of rate of return do you guys have, assumed on that capital, and to the extent that there aren't investments that roll forward, you know, over the sort of near term, or do you think that we don't buy back stock, is there anything that we ought to be adjusting or is there-the rate of return on that capital embedding your guidance, so low already that we don't need to adjust it at all?

It's more the latter.

It's more the latter?

It's more the latter. I wouldn't adjust the ROICs on our embedded capital from what they are currently today, and they're a little over 7 percent.

Our next question will come from Jonathan Arnold with Merrill Lynch.

I was just looking at the guidance in the earnings release, comparing it to the end of the year stage, and you seem to have moved like roughly 10 cents for a commodities services into nuclear, but specifically, the item line capacity factor normalization [inaudible] in other. There seems to be the main benefit to the nuclear outlook.

I'm just wondering how much has changed in your assumptions of what it might be at that line to account for such a big different.

Jonathan, for every one percent change in capacity factor, we generate about 4 cents, and we assume at the end of the year, ranging from the units, that 87 and 90 percent, we've stepped that up a couple of percentage points across almost all of our units. We haven't made any adjustments to our outage duration assumption, which is about 30 days, and so we still think we're in a pretty conservative zone on those assumptions.

So that's mainly for the balance of the year or based on performance in Q1?

No. It's what we actually achieved in Q1, plus we've stepped them up a couple of percent across all units for the balance of the year.

Next we'll hear from Jeff Guildersleeve [phonetic] with Argus Research.

Actually, I was curious about the nuclear guidance difference, so that answered my question there. When you spoke about acquisition, you mentioned gas storage as a possibility, too. I mean, given that, it sounds like you've seen a lot of generation assets that just aren't worth what sellers are offering now. Is that a big possibility, and how would that fit into your business?

Kyle, do you want to talk about gas storage, the existing projects we have and your views on gas storage?

Okay. We recently have announced a storage project near New Orleans called Magnolia, which is a salt dump storage project, and it'll be coming on next year. From a trading perspective, particularly in the U. S. right now where you're looking at, I think, a growing need for gas over time, there's going to be a need for more gas storage, not only just physically, but also, we think, from a trading perspective, you're going to continue to see markets be very volatile in the gas side, not only in the winter where it's historically been volatile, but you'll probably start seeing it more in the summer over time as you see more gas peaks coming on in the summer.

So we believe that storage is a good investment. It also very much ties into our trading point of view, matching and mismatches in supply and demand in regional areas and all that, and from that standpoint, from an EK standpoint, we're-we believe storage is a good investment. Now, it has to be in the right area just like Wayne mentioned on power. All power [inaudible] aren't the same. You've got to be in an area that's got plenty of access to supplies, variable options also on delivery, and things of that nature, but from that standpoint, we think that gas storage is a really good asset to go along with the trading-oriented strategy.

Do you see prices for gas storage being more acceptable to you than where generation is pricing?

Is that to me or Wayne? To me, from an EK standpoint, yes. Yeah, we're-I think John mentioned something. Certainly on the gas side, you know, gas storage is a business we understand very well, and it's also one that has a-we think, a good return, certainly if it's in the right spot and you know how to manage it. The power side I think we've talked about is even though prior plant prices are getting cheaper, you still are looking at a pretty extended period probably of pretty low cash flows in the front end that doesn't really excite you too much. A gas storage facility really kind of generates immediate income and opportunity.

Moving on, we'll hear from Paul Ridgen with McDonald Investmetns.

Actually, once again, my question has been asked and answered.

We'll hear from Jim Von Reidman with JP Morgan.

A lot happened in Washington in the last 24 hours with respect to energy bill. Can you give us a rundown on that?

Sure, Jim. Kurt will do that.

Kurt's got about ten pages laying in front of him right here to talk about that.

Jim, this is Kurt Ebert. Good to talk to you. As you know, there has been a lot that has happened. They're moving forward with the legislation. One of the things that we really had that we were concerned about and I had spoken of this earlier, and that was the funding and what would be the funding mechanism when it comes to transmission.

Are they going to roll it in, or are they going to incrementally price it in? Either way, we feel like we're going to be able to recover, and we're not concerned about that, but we are concerned with the effect it has on our rate pairs.

The other things that bring up concerns coming through FERK and coming through the Hill, FERK merger authority, if you kind of look at some of the things that have come down specifically, probably the Thomas amendment, severely limit the abilities of utilities to conduct transactions quickly. I think that is something that most of the industry will be looking at and saying, "Is there any way to get around that?" The Land Group Participant Funding Amendment is something that was on the table, was withdrawn in exchange now for a Senate hearing, so I think you'll see that coming.

Other FERK merger authority amendments that came through, the Campwell Dayton was rejected, and that would have expanded FERK's market power authority, including divestiture authority, so there were a lot of people that were truly concerned with that.

[Inaudible] appeal has certainly been something that was a little big on the back burner, and then here just recently has come forward.

There was the Carper Amendment actually that's continuing the mandatory purchase. That is something that everyone talked about. It was also the Daschle, Bingham and substitute, which was a prospective repeal of the mandatory purchase requirements. Other than that, there's some real-time pricing and net metering things that were brought forth with Thomas. It was much talk about that, but it's essentially the status quo. Renewable portfolio standard, that got a lot of attention. As you know, it bounced around a little bit, ended up at about 2.5 percent in 2005. It ratchets up a half percent a year, ending up at 10 percent by the year 2020. Those are really the things that we've looked at that we think are important to the industry.

Everything else really seems to be status quo. There was a little more talk about the market-based rates in the Thomas Amendment, but again, all that's doing is codifying existing laws, so that's not something that concerns us.

And just as a follow-up, it sounds like everybody's more on the same page in Washington now. So is there a likelihood that an energy bill actually gets done with these electricity titles is better than fifty-fifty?

I'd hate for any salary I'd ever make to depend on my guess in Congress. I don't know. You know, I think September 11th certainly put a lot of fuel behind this, and I think there is a good chance of passage, primarily because they've put so much time and effort into it, and I don't think they'd want to repeat that again in the next couple of years, so I do think there's a good chance of something coming through this year, much better than I think anyone would have anticipated.

CALLER INSTRUCTIONS.] We'll take our next question from Andrea Frankenstein with Angelo Gordon.

Close, but not quite. It's Angela Feinstein from Angelo Gordon. A quick question: I don't know if I've missed this earlier on the call. With regard to the possibility of a stock buyback, you've spoken in the past about talking to rating agencies to get them comfortable with that thought, given the current environment.

Have you made any progress on that front? And you tell us where you are in discussions with rating agencies?

Andrea, we have ongoing discussions with the agencies, not only about repurchasing our shares, but just about the overall financial plans of the company and the financial flexibility that we have. The most recent discussions with them centered around the restructuring of our wholesale business. Those discussions went quite positive, and we feel good about the position we have with the agencies right now. We've laid out to them our forward capital plan that shows the 3.5 billion of investment capital that we have available to invest, and there's a wide variety of investment alternatives, and before we'd do anything on our share repurchase, we'd have specific discussions with them around that time, but we wouldn't anticipate that being an issue with the current financial strength that we have.

On a separate point altogether, with regard to the possibility of seeing some distressed asset opportunities, can you just point us to either a region or any other characteristic that will specifically drive what you're interested in in the distressed market if they come up?

It's price and it's price and price.

Okay.

Other than that, you know, and location.

So you're pretty much interested in anything across the country as long as it's priced correctly?

But we're very interested on the generation side, any assets that have good fuel switching optionality and have weather optionality. Those are two areas that we believe we excel, and so those would go. We'd be keenly interested in those kinds of assets.

Yeah, Andrea, let me just follow that. In terms of what we're interested in, like John said, for power plants in particular, we're interested in things that have embedded options, that EK can trade around. Storage is the same way. We're looking for the locations and that they find favorable, that they can enhance their trading operations, and then in nuclear and natural gas pipelines, we look in particular for areas that we can enhance our operations and cut costs and throughput on pipes at a reduced rate, or improve the outset of the nuclear plants, and both of those, we've had a terrific track record at doing.

So there's operational areas that would be interesting to us, and there's trading areas, but just buying a power plant to sell a commodity into an overbuilt market, it doesn't work.

I guess that would have been-the more specific question is, are there any regions that are so over-supplied that you don't see the likelihood that there's going to be attractively enough-priced assets that you would even consider them?

Yeah, well, everybody in the room is holding their heads because that region happens to be our own region.

Okay.

But having said that, you know, that is the opportunity here. The opportunity here is, you know, a lot of utilities are announcing moving their turbines into the utility they have purchased for non-regulated, trying to move them into a utility, and in our particular case, that was a possibility, because we had some very attractive repowering opportunities that were extremely efficient, but at the same time in an overbuilt market, nothing typically worked.

So what the utility will be doing, first of all, this year, is buying a lot-you know, we're 3,000 megawatts short. They'll be buying power on the marketplace, I think, very, very cheaply compared to what we have in the past, which is very good under-our customers were very happy with that outcome, and then we will be working towards other outcomes in the future, which could involve buying distressed assets for cents on the dollar, and then possibly rate-basing those assets and replacing the power purchase contracts. We'll be earning return on those assets, or moving to a performance-based rate plan where if we can buy power on the market, because it's so overbuilt, that we can share in the difference between substandard and what we can buy it for, so it will allow us and our customers to participate in the distressed marketplace that exits in our own territory.

And we'll take our final question today from Win-Win Chen from ABN Amrow.

I just had a question about the 3.5 billion that you have cash available. There's a note in your release that says one billion is for growth investments and turbine contract cancellation costs. Does that mean that you have further possible turbine contract cancellations aside from what you've just announced today?

No, Win-Win. That just-that footnote was intended to indicate that we have-of that 3.5 billion, a commitment to buy Vermont Yankee, and we've made a commitment, as I've described in my remarks, to buy out the turbine trust, and that's all I meant. There are no further commitments.

And then just one quick question. Can you give me the unrealized portion of your market-to-market earnings?

The unrealized portion?

Yea. I guess you have 14 cents in the market-to-market gains for this quarter.

Yeah. Nancy said she'll follow up with you. We have it on one of our tables.

That concludes today's question and answer session. Ms. Moravich, I'd like to turn the conference back over to you for any additional or closing remarks.

Thank you, Operator, and thanks to everyone for participating this morning. Before we close, I just want to mention that the call was taped this morning. It can be accessed for the next seven days. The dial-in number for that tape delay is 719-457-0820, and the replay confirmation code is 602701. This concludes our call. Thank you.