埃克西爾能源 (XEL) 2002 Q1 法說會逐字稿

This is an unedited realtime transcript. An edited version with proper case and full speaker names will be available shortly.

Ladies and gentlemen, welcome to the xcel energy and nrg energy first quarter earnings conference call. At this time, all participants are on a listen-only mode. Later we'll conduct a question and answer system. The conference is being recorded. Starting off today's conference, we have Mr. Dick cope end.

Thank you. I want to welcome to the first quarter 2002 conference call. With me today are jim mcintyre, cfo of kmel energy, dave peterson, of nrg energy, president of nrg north america, and len bluhm, and in addition we have several others from xcel and nrg with us in the room to ensure we're able to answer your questions today. Before we get started, I want to mention that some of the comments that will be made contain forward-looking statements. Significant factors that could cause results to differ from those anticipated are described in xcel energy and nrg energy's filings with the securities and exchange commission. With that, I will turn the call over to jim mcintyre.

Good afternoon. Thank you for joining us. Our owe on going earning for the first quarter of 2002 were 31 cents per share, which was then our guidance of 30 to 35 cents per share. Totalenings for the first quarter of 2002, were 29 cents per share, due to two cents of special charges for the write-off of southwestern public service regulatory asset, one cent, and re 59ment. Restaffing charge originally recorded in the fourth quarter of 2002 for approximately one cent. In regard to our utility results, ongoing earnings for utility operations, which includes our short-term wholesale and electric trading results, were 40 cents per share for the first quarter of 2002, compared with 56 cents per share for the first quarter of 2001. Total earnings, including the impact of special charges, for utility operations were 38 cents per share for the first quarter of 2002. Utility results excluding short-term wholesale and trading margins were 39 cents per share for the first quarter of 2002, compared with 32 cents per share for the first quarter 2001. In regard to trading on page 6, you can see the table of our xcel earnings release, which captures the trading information. First quarter of 2002 short-term wholesale and electric trading margins were 8 million, compared with 134 million for the first quarter of 2001. The earnings per share impact due to the decline in short-term wholesale and trading margins is approximately 22 cents per share. In the first quarter of 2001, market conditions were very favorable and we had very strong short-term wholesale, and electric trading margins. Approximately 55% of our 2001 short-term wholesale and electric trading margins were realized in the first quarter of 2001. As I said before, we did not expect to replicate our 2001 results in 2002. We have indicated the performance in the second half of 2001 is generally indicative of near-term trends. However, our short-term wholesale and trading margins were lower than we anticipated in the first quarter due to warm weather, lower pool prices, and reduced volatility. Our trading operation is a good business, and augments our other operations by one providing with us a very nice increment to our earnings, two, helping disguise when we're in the market making purchases for our native load, and three, it acts as a natural hedge against the volatility of purchase power and energy prices that we procure for our regulated customers. In regard to whether we did see the diversity of our service territory continue to pay dividends, in that while it was 6.7% warmer in minneapolis, where fortunate the weather in denver was about 6 1/2% colder than normal. And the panhandle was basically very close to normal for the quarter. Effectively, we ended up with 1 cent per share adverse earnings coming from weather, compared to normal. And 3 cents per share adverse compared to 2001. One of the further strengths of our regulated business is the diversification of our strong service area. Although our regional economy is not isolated from the national slowdown, we continue to main than I strength that a enviable. In march, the unemployment rate and the xcel region stood at 4.8%, compared to the national figure of 6.1%. In the first quarter, our on am expenses increased by approximately 11 million dollars or 3%, and the increase is largely related to plant outages scheduled in the first quarter, compared to less plant outages in the first quarter of 2001, an additional premiums regarding property insurance that we and others have seen throughout the industry. For the first quarter of 2002, nrg contributed a loss of 6 cents per xcel energy sell, compared to earnings of 8 cents per share for nrg's -- for xcel shares for the first quarter of 2001. For more detailed discussion of the nrg results, I'll turn it over to dave peterson, ceo of nrg. Dave.

Thanks, jim. By now, you all knee that nrg had a difficult and very disappointing first quarter. The loss recorded for the first quarter of 2002 is 26 million or 13 cents per nrg share. This compares with the profit of 35 million or 19 cents per nrg share for the first quarter of 2001. As we noted in the news release, nrg recorded its much smaller pass it 133 gain in the first quarter of 02 than 01. Such 600,000 dollars versus 12.8 million last year. Nrg's first quarter was also impacted by higher interest expenses as a result of bother owings to fund our acquisition and con introduction program since the first quarter of last year. From march 01 to march 02, nrg invested over $4 billion in generating facilities. Nrg's earnings are historically very seasonal. And this year is no different. For example, nrg's earnings for the first quarter of 01 excluding fas impacts, was 9% of the total 2001 earnings. The third quarter is always the strong quarter and brings in most of the earnings, followed by the second quarter, which is a major contributer, and then the fourth quarter, and lastly or the least is the first quarter. I'm sure that every generator experienced -- have experience with similar quarterly earnings patterns. Nrg's first quarter 02 results were significantly impacted by the fact that nrg's total megawatt generation was down 19% in north america from one year ago. And that's a -- that's with a 35% increase in capacity, quarter over quarter. Craig will elaborate in a moment on our contracted margins. But when demand is down, in a total requirements contract situation such as we have at connecticut light and power, louisiana generating, and e way, our sales are -- will be down as well. Total requirements contracts comprise over 25% of our capacity sales. In addition, prices in some regions such as new york were down over 75% from one year ago. We are pleased to see that recently that demand and pricing in the u.S. Market are returning to more expected levels. You will notice from the regional detail provided in our release that our international assets generate performed well during the quarter. Europe showed a significant increase as the assets and continental europe performed exceptionally. The united kingdom assets are plagued with low prices, resulting from significant oversupply. The generator outage at eloigne in the first quarter impacted results in the pacific region. The good news there is a spare generator was located, installed, and as of april 17th is fully operational at full load. As most of you are aware, we announced the capital structure enhancement plan that involves potential asset sales. Nrg is retained financial advisors to market our international assets. The assets are being marketed in four regional bundles, latin america, the united kingdom, continental europe, and asia-pacific. We expect to issue information memorandums in early may, decide during the summer based on indicative bids which assets we will pursue to sale. We would not expect any sales of any of the large portions, anyway, to be consummated and closed before the 4th quarter. We also continue to evaluate and pursue the potential sale of a partial or entire interest in selected north american regions. Further we elected to terminate the acquisition agreement for the purchase of plants from atlantic city electric company earlier this month. One acquisition that we are proceeding with is the -- first energy. The regulatory proceedings are proceeding and financing is also progressing towards a probable june close. We continue to evaluate our construction program, and as a result have further trimmed or 2002 and 2003 construction forecast. In total, we have shaved 1.5 billion from the 2002 construction forecast, and at this time we forecast spending up to 1.7 billion dollars this year, but as I said, we continually review this for further delays or potential cancelations. We continue to work with the rating agencies to bolster liquidity and overall leverage. At this time, the status with both agencies remains unchanged. It was recently reported that through an oversight, nrg had failed to obtain the ferc approvals for operating the big ones in louisiana. Personally, I'm extremely embarrassed by this situation. We are correcting the problem with proper filings, which have already been made, and through a revision of our internal processes. Let me wrap. On a more positive note. We remain focused on providing acceptable returns to the shareholders. We will continue to manage the business to do so. We have curtailed all business at develop meant expenditures so we can focus more on existing assets as well as those currently under construction. We have recently closed four international offices and in the process of trimming other operating expenses. Our 2002 net income guidance is in a range to 300 to $315 my. This guidance does not include any possible impacts of restructuring, asset sales, or xcel integration efforts. As I indicated, the revised guidance includes our current market views for north america, including higher prices in connecticut and the northeast region. We look forward to resolution later this year on the outstanding issues we have in california, including the payment of past-due receiveables. We look forward to delivering the results you expect. Now I'll turn the call over to craig, who will provide detail on nrg's north american unit, including demand pricing and amounts contracted. Craig.

Thank you, dave. There are two important questions I want to attempt to answer this afternoon. The first is which factors contributed to the loss in the first quarter, given we were highly contracted. And the second has to do with how the first quarter results affect our outlook for the rest of the year. I know I don't have to tell any of you that this was far from a normal first quarter. Both sales volumes and prices were well below last year and below our expectations for the quarter. In the retail business, a common metric that is used is growth in same store sales. If we use a similar metrics, based on same plants or the plants nrg had a operation in the first quarter of 2001, our sales in the first quarter of 2002 were 27% below last year's first-quarter sales. Even considering the new generation which we added, total sales were down 19% from 2001, and were 29% below expectation. This part of the sales decline is due to lower merchant sales, but also as dave alluded to, the fact a number of our contracted sales are based on the requirements of the host utility, and it's those requirements were below expectations, our megawatt hour sales were reduced as well. In addition, pool prices were well below expectations. This resulted in merchant gross margins per megawatt hour, which were 40% glo had below that which was achieved last year. I want to further clarify this situation by directing everyone's attention to the graph of our margin and fixed cost. This chart is showing our website and was included in the e-mailed and faxed releases that went out previously. I think you can see why we can record a loss in the first quarter. Our margins from contracted sales don't fully cover all of our costs in the first quarter. Merchant volume and prices were too weak to make up the difference. Approximately one-third of the weakness resulted from the reduction in the quantities sold, versus expectations, in the remaining two-thirds resulted from the lower price. We have said for some time that we're about 75% contracted. That is true. The 75% contracted we refer to is our annual expected gross margin. And the charts show what we would have expected to achieve under normal conditions. The contracted portion is the blue portion showing on the colored graph on the website and the lighter gray shaded portion which is included in the fax. Since our greatest profitability is in the third quarter, we have a greater emphasis on contracting for that time of the year than we do in other quarters. We also have a high percentage of new assets that are being added throughout the course of year that have contracts associated with them, pushing the contracted amount up later in the year as well. On an annual basis, our contracted murder joins more than cover all our fixed cost, which are shown on the solid line in the graphs, and beyond that the contracted margins will also provide positive margin. However, for some months, primarily those early in the year, the contract alone were not anticipated to be sufficient themselves to cover all of the fixed costs every month. In a normal year, our merchant sales volumes and price margin we receive from the merchant sales, which are shown in yellow or the darker gray area on the shaded graphs, cover the gap and make the positive contributions to earnings in those months. The next question I want to try address is what does this mean for nrg, north america's earnings for the remainder of the year? There are four factors I will talk about here. The first is our assumption regarding pricing for the remainder of the year. You have asked us to be more specific about our pricing assumptions and we will do that. However, we won't disclose our pricing assumes by region. While sparks people define it, the difference between the pool price and the cost of gas-fired generation, at a specified heat rate, may be a good indicator for profitability for some companies, it is somewhat less revel for nrg. While nrg does have gas in the generation portfolio, we also have a significant amount of low-cost coal generation. The margins we cap can capture from gas will follow the typical calculation. However, the margins we capture from the coal-fire generation in or portfolio are higher than what most people would realize in a gags-based market. About one-third of our sales in megawatt hours come from gas and oil-fired generation, with a production cost of about $40 a megawatt hour. While two-thirds of our megawatt sales come from coal-based generation, which has a production cost in the range of 15 to $20 per megawatt hour. The weighted average production cost from our fleet is in the mid-20s. On the order of 25 dollars per megawatt hour. Over the year, in the markets we serve and during periods that we expect our plants to actually be in operation, we expect to achieve an average pool price for our merchant component of our generation of about $35 per megawatt hour. I believe this is consistent with others forecast for merchant pricing in the country. The consequence of that is that we expect to realize an average merchant margin over the year of about 11 to $12 per megawatt hour. This is based on the composite of high margins for limited number of hours during the year and those are the peak hours, and very modest margins at other times during the off-peak periods. This does not include our contracted sales or forward sales, where the price is already specified and which are generally at higher margins. With the regional markets we serve with our constraints, this is a realistic price assumption for our portfolio, and our pricing assumption for merchant sales are consistent with the current yacht look that others have. Another question we have gotten in the past is our sensitivity to changes in margin. If we -- if our mar -- merchant margin were to change by 10% from our current average spark spread of 11 dollars for the entire year, we would -- this would result in a change net income of $20 million. I would note that the change in margin for the first quarter was much beyond 10%. The second factor in our earnings yacht look for the year is that we are assuming a return to normal weather and demand conditions. In the first quarter, for example, in the northeast, where we do generate a significant amount of our income, weather conditions, the cooling degree days, the heating degree days, were down 14% in 2002, versus 2001. The third factor that we will look at is the ability to add significant generation capacity. And this of course will add to the bottom line. During the first quarter, we added about 800 megawatts of generation. By the end of the first quarter, we had 15,900 megawatts in operation in north america. This is an increase of 4100 megawatts or 35% compared to the first quarter of 2001. During the second quarter, we expect to add another 3,000 megawatts of generation. I will note that the majority on the order of 80 to 90% of this is contracted for already. By year end, our north american plant ownership will be over 19,500 megawatts, nearly 30% above the figure for year-end 2001. A substantial portion of this as I said is under contract. The bottom line of this plant addition is that for the remainder of year, we expect megawatt hour sales to be twice the level than the last three-quarters of 2001. The fourth factors we're entering a portion of year where higher margin is contracted for. Keep in mind as we move throughout the course of the year, and into june, july and august specifically, we have a much higher level of our margins stream contracted, and as we work par marketing efforts we endeavor to contract more and more of that as pricing situations become attractive to us, which has happened over the past few weeks. I will continue to take advantage of those opportunities, and we feel that will give additional assurance of being able to achieve our numbers. With that, I will turn it back to jim mcintyre.

Thank you, craig. Before we wrap up and open it up for questions, I want to provide an update on a couple things that you're all interested income in regard to the status of the credit rating agency valuation, we continue to meet and work with the credit rating agencies, taking some additional steps to enhance our original plan. I think people are probably aware that we cancelled nrg's involvement with the connective acquisition, which reduced our capital requirements by $230 million. Besides asset sales, we continue to look at bringing in partners on some of our existing projects, and as dave mentioned, we'll continue to review the expenditure program for further de ferls or cancelations. We plan to continue to discuss our working with the rating agencies. There are no secret cows. We're very, very committed to investment quality for nrg. We continue to look for ways to deal nrg and we'll keep you posted on any new developments. Also, in regard to the status of the nrg tender offer, as we previously discussed, completion of our exchange offer for nrg is conditioned upon receipt of an order from the sec under the public utility holding company act, and when we did increase the exchange ratio to .50 shares, nrg stock and the sec issued a new notice. The new notice period will expire on may 6th. Consequently, we extended our exchange offer to may 8th. In regard to our guidance update in key assumptions, our annual 2002 earnings guidance remains at $2.30 to $2.40 per share. The critical assumption include normal weather for the balance of the year, more normal power pool prices and sparks spreads, the completion of the nrg tender offer in may, and nrg maintaining its investment grade credit quality, or the critical assumption. We've also assumed that nrg's forecast will be improved by about $20 million, and after tax as a function of cost reduction and enhanced margins due to consolidation integration of their trading generation and corporate support functions within xcel energy. Once we achieve closure on the nrg tender, and we have further progress on the implementation of the integration efforts, and have more information on the nrg asset sales, we'll provide quarterly -- further quarrel guidance. Kevin, at this time, I'd like you to open it up for questions.

Ladies and gentlemen, questions I've taken in order are cued. You may place yourself in cue by pressing one on your phone. Please ask that you limit your question to one question per cue. You may participate in the question and answer session. You may press one at this time. We have a question from terry shui-bian of j.P. Morgan.

Hi, jim and dave. If you can clarify again on your pricing assumptions, as well as the earning sensitivity. I think you said you were assuming normal weather for the summer. But we already see the forward prices for the summer, and we are really moving into the summer. Just based on today's prices, what can you be a little more precise as to what you're assuming in terms of price recovery? I think you've talked about improving trend, just tracking the prices. I don't quite see an improving trend. And maybe you can just repeat the -- is did each dollar per change in the sparks spread is equal to what in earnings? I'm sorry, I missed that.

Tier, we'll have craig follow up on that.

Yeah, the reference that i made with the dollar change in our margin --

Okay. Associated with the merchant sales -- Okay. And only the merchant sales component on the portfolio, and that would be across the entire year, would result in a change of $20 million in net income to nrg.

Okay.

And that is only that portion of the output, that is not under contract. That's the merchant portion of the nrg sales. You can be more specific on pricing assumptions? We have seen -- our pricing assumptions has taken the forward curve analysis that we have done in that has come to a round the clock, 24-hour per day average type price of $35 per megawatt hour.

For the summer?

No, that's for the entire year.

Okay. Summer pricing is actually higher than that. And I don't have the number off the top of my head. Exactly what the price as many but the margin between the expected margin between the summer and other periods of the year will range from twice as high to three or four times as high, depending on the specific market or asset region that you're in. For example, in city new york is higher than that $11 by a significant amount. We saw prices in city new york for example, a couple weeks ago, trading well above $100.

Okay. I ask that because the $35 round the clock number you say, we already have four months of the year in, and prices have been low. So I gather you're assuming a rebound, even from here. Correct? I think that the indications that we're getting relative to the price particular during the summer months, which is consistent with the forecast we have put out there in the pricing assumptions that I talked to earlier, we're getting back to where we expect it to be.

Okay. Thank you. I think terry, just to add some clarity, when craig talked about the pricing assumption, those are really for the balance of the year, from here to the year-end.

Okay.

We're not expecting to overcome the very low prices that we're experienced in the first quarter.

All right. The $35 have averaged in the low levels earlier in the year?

No, no, the $35 averages in the on-peak and off-peak price from march, for april 1st, basically, going forward.

Okay. Thank you.

Our next question from popper from -- please go ahead, sir.

Good afternoon. Two quick questions. What is the short-term dead balance of nrg and xcel at the end of the first quarter? And the second question, has there been any discussion to walk away from the acquisition of the power plants from first nrg? In regard to the short-term debt balances, those will be put out in the 10 cue out on may 15th. I don't believe those amounts have been disclosed at this point in time. In regard to the second question, dave, you want to handle that?

Yeah, we've -- we've had some internal discussions. We believe it's more prudent to go forward with the purchase. We are talking to people about doing a partnership arrangement. We are also proceeding with the financing, and believe at the time it gets closed in another eight weeks or so, that we'll probably have some sort of a partner in the transaction will close, and it will be the prudent thing to do.

Thank you.

Next question from a doula. Please go ahead.

Good afternoon.

Hello.

I'm doing fine, thank you. Couple of things. One, with the revision here on nrg's outlook here, at 300 to $315 million, and based on a may close right now, can you update the breakdown you provided, that goes back in february 15th, as to the -- how you achieve your 232, 40 earnings amongst utilities, nrg enterprises and the interest costs?

I believe the disclosures we have in the port filing associated with the exchange offer are still appropriate. They're still within the ranges that we outlined there both in terms of the earnings per share contribution from the various components to xcel, as well as the net income contributions shown on the subsequent page. These are shown on pages s-4 and s-5 out of the s-4 filing.

Okay. And I'm wondering also, can you -- you referenced the status of the credit rating agencies is unchanged. Can you give us any sense as to when you expect to hear anything additional, and can you also review for us at this point what would be the impact -- you know, your current estimate of the impact in the event it were to downgrade nrg to below investment grade status, what would be the effect?

Let's see, the first part was the status of the discussions.

Yes.

And as we indicated in our prepared remarks, we continue to work with agencies to share our plans and to further seek ways in which to modify or plans, so as to further -- leverage nrg and to get investment credit quality. We continue to work with them, given some of the complexities of the issues and some of the changes particularly at moody's, we're really working with them on their schedule, and not in a position to really indicate when that might be completed. Obviously, we've done a number of parts that were with our original plan. We've issued the equity. We've expanded the revolver that nrg had put in place. We've taken steps as dave talked about to reduce the number of projects still ongoing through cancellations and de terms. And as you mentioned, we continue to put in place the actions in order to go through and determine which of the assets that we have are the appropriate ones to be sold in order to bring back cash and further reduce the debt that otherwise would be on nrg's balance sheet some we continue to take those actions, as well as other actions, in order to address the credit quality issues. In terms of the potential impact and the event of a downgrade, I'll let len bluhm talk to that.

The amounts we previously disclosed that would be, the downgrade collateral required of roughly $1 billion is largely unchanged from what we've disclosed before.

Okay. And one last question I have. In the notes of the earnings release, you reference something about in april, that there was a additional $150 million convertible note issued to xcel energy. And I'm just wondering, can you explain how that fits into the equity support that's being considered here, or how we should be -- evaluate that?

The original plan was that xcel energy would provide $600 million of equity infusion into nrg. Because of the pendency of the exchange offer, we initially did $300 million of sub ordinated notes and now we provided another $150 very much consistent with the 600 million. So think of it in the same context as the original 300.

Okay. Thank you very much.

Next question from chan of jk utility advisory. Please go ahead. I was wondering if you could give us an update on the new york to pass city auctions. Not sure if they occurred april 1st. And then for the next six months. And jim, I thought I had seen something about a sale of planergy the other day? Can you update us on that, if anything happened.

I'll take the second part first, and then craig can respond to the markets. We have sold a portion of the contracts that we had in place through emi, which is now a subset of planergy, and these are performance contracts that had been put in place sometime ago. We sold them to chevron, i believe the amount is -- has been -- I guess there's no dollars disclosed budge suffice it to say, it's a further action between clarity and focus to the business. And while the amount will not bring a significant impact to our earnings, nonetheless it's the focus of where we want to go and a refinement not different than a year ago, when we opted to sell yorkshire in order to bring more and more focus to the business. So we said before that we'll continue to take steps like that. This is another step in that direction. And we'll continue to do that within xcel. Okay, yeah, the auction for -- in new york was held i think the 28th or 29th of march, is when that was completed. We sold virtually all our capacity within the city of new york and the price was very close to the cap, I think on the order of 920 the cap, the cap 942. So I think those are all public numbers, and out there. But that was the basic result.

mark from northern crust. Please go ahead.

Can you just give more detail in terms of potential partnership for the first nrg plants. Are you talking about minority partner or talking potentially a 50/50 joint venture?

The -- I don't know if you're address interesting to myself or dave. I think in general, we will seek partnerships in various assets, and first nrg is one of the projects or assets we have. Dave, you want to comment on that?

Well, at this point in time we sure don't want to disclose what we're doing or who we're talking to. And there are several parties and the arrangements are different in each one, and we basically haven't decided which way we're going yet. That will happen before closing.

Okay. Just a clarify any debt for the first nrg plants will be non-recourse project?

Yes, sir.

Okay.

Thank you.

Planned on being a leveraged lease.

Okay.

Our next question from matt norris of adventist. Pleads go ahead.

Yes, just a claire if days on the chart you released. Across the bottom it says january to december as many this meant to represent 2002?

That's correct.

So the part of the chart to march is actual and the rest is estimated?

No, this was our expectation going into the year. But does not include actual results.

Okay. That's all. Thanks.

Next question from michael savoy. Please go ahead.

Hi, guys. Nrg downgraded -- so if -- downgrade to the low investment grade and post one in cash collateral, do you think it will impact your ability to finance the acquisition of power plants from first energy?

This is len. No, the first nrg transaction is going to be a project specific gemco transaction, and any impacts that nrg corporate level should not impact the financing of first energy.

How much equity would you have to put into the structure?

We previously disclosed that it would be roughly $of00 million -- -- roughly $600 million of equity.

Can you give us an update on the uses of funds for this year for nrg, then, so we can reconcile these numbers? I think just generally what we can tell you is that we have often talked about cash flow available from the projects for free from the flow of $750 million for the year, with our drop in earnings guidance and the results for the first quarter that probably will drop to the 550 to 650 range.

Okay. Thanks a lot.

Our next question from meryl nerl.

Thank you. One of the ask a couple questions on the nrg slide. Just wanted to make sure i understood the 300 to $315 million of net income incorporates the blue plus the yellow, or only the blue, in terms of your earnings expectations? With american business.

Yeah, this is first -- that's a good point, elizabeth. This is only pertains to north america, and the 311 -- well, the 311 would include the forecast, which is not what this represents, but the forecast that includes both the blue and the yellow. So it includes the blue plus the current forecast of the yellow, which is not what we have provided in this chart.

So if we were looking at this chart just like from april on, it's blue plus the yellow?

Right.

Plus whatever you actually earned in the first quarter?

Right.

Plus the international business.

Right. Right, just from the north american standpoint. Now, you mentioned in the first quarter, one of the problems on the hedging piece was that your customers were unobligated to necessarily i guess take everything if they didn't have the demand level. And I'm wondering on the blue piece going forward, how much of a risk do you see that being? How much -- potential is that of the blue piece?

I don't have a good answer for that question. There is some risk in the blue. However, as I indicated, the northeast, for example, the 14% negative or adverse deviation on weather, which correlates with consumption at a significant effect in the first quarter, I wouldn't expect to see it that large going forward. And what we're getting as far as indications from pricing and what we're seeing happen through the end of march and into april would support that.

Just one follow-up for nrg in terms of their results. Have you taken any reversal of the california reserves in either the fourth quarter or the first quarter of this year?

Bill will answer that.

No, we have not. We took a very small reduction in the reserves in the fourth quarter, I believe it was around 4 or 5 million. But there's been nothing in the first quarter of 02.

If I could just ask another question of xcel. In terms of your 20 million increment to nrg's earnings forecast, just wanted to clarify that you would expect to recognize all of that in 02, and I remember a couple months ago you had talked about cutting business development expenses maybe 45 million pre-tax. Is that kind of encapsulated in the 20 million after tax, benefit? An all-in synergy or integration savings number?

The development costs are captured in energy's guidance because as dave mentioned they have and are shutting down the development efforts as well as the offices related to development effort. So to the extent the development costs will be reduced as captured in their guidance, in regard to the integration benefits, the 20 million, that is separate from the development costs. And a lot of what it includes is the recognition that for a number of years we have retained the optionaction lity of having nvrg being a free standing entity. Once we're successful with the exchange offer, we would intend to consolidate, bring the two companies together, and get rid of that optionality, and reduce the cost structure and really focus on cost management as well as asset management, in order that we can reduce the break-even point for nrg on a go-for-it basis. Additionally, there is some incremental margins in that we would expect to further coordinate and consolidate the trading and marketing, which should allow us to reduce some of the costs structure, thereby enhancing the margins, and there's also some expectation we will provide some of the sourcing of the gas for nrg's gas requirements and be able to reduce costs and trade around that load sink. 20 million dollars is the expectation of the benefit that we would see in 2002, and that is an after-tax number.

Okay. Thank you.

Your next question, craig alpert of osprey. Please go ahead.

Good afternoon, everyone. I just had a couple quick questions. The first quick one has to do with, does the 1.7 billion in cap x include the amounts for first energy is that separate?

That amount is separate.

Okay. The other thing that surprised me is you had a 19% decline in volume, when power demand in the northeast was basically flat rb in the quarter, according to edison electric institute's weekly data. How can that be? Is that just your plants getting knocked off the stack by lower heat rate units?

Yeah. I mean, it has to do some with. The fact that our assets particularly say in city new york are peaking assets and as peak demand didn't develop because you had 60 degree weather instead of 15 degree weather, in the city of new york, we saw the effect of that. We also saw the effect of the lower demand for the residential low, which is the connecticut load, and also the load in entergy, the south central region, residential demand, and that was lower than we anticipated and consistent with what we saw.

So when you were giving your hedge percentages, you're saying if people take the amount we expect them to take, where x percent hedged?

That's correct. There's some variability around that blue line or the lighter shaded region on the graph we prayeded. But yes, that's the percentage that would be hedged.

Okay. And my last question is, the regulatory one. Correct me if I'm wrong, but i believe under from your public filings, that you have limitations on kooka, on your debt to cap at 70%, and you're one one or two% of that. By I the same token you're also limited under a different ruling that you can't -- there's limitations on how much equity you can inject into nrg. And I'm wondering how do you reconcile those in the event that moody's downgrades you and there's an additional $1 billion of equity required?

You're referring to sec rule 24, and sec rule 53. And we've considered both of those as we put together the plan to bring nrg forward. We believe we have appropriate room under 53 in order to make the appropriate equity infusion, and otherwise support for nrg, and under rule 24 with the equity that we've issued, along with the stock for stock exchange that we'll complete the exchange offer, will believe we have adequate room there as well.

Got it. Thanks very much for your time.

Ladies and gentlemen, if you have a question to ask or comment to make, please press one on your touch tone phone at this time. You have a question from david frank of zimmer lucas partners. Please go ahead.

Yeah, good afternoon.

Hello, david.

Hi. Jim, I was wondering if maybe len could remind us of the book value related to those international assets nrg is thinking of selling, and the related debt.

David, this is len. I do not have the book values with me. And certainly, any debt associated with those projects would go with the projects. So --

Yeah. That's what I'm trying to figure out. Do you have a ballpark number you could give us?

I don't today.

Okay. Thank you.

Next question is from jim von reeseman j.P. Morgan.

Yes, jamie waters. Couple questions. With regard to just looking forward to 03 earnings for xcel, I notice that the nrg guidance for this year is before any lost earnings from asset sales. So -- and for this year, you should get the full benefit or most of the benefit from earnings from those on sets given the 4 q sales target. Looking to 43, is there anything we can hang our hats on in terms of the earnings that could be lost from the asset sales?

I think it is premature because one, we don't know exactly which assets may be sold. So what we've done for 02 is as you indicate we've assumed that the assets sales will be completed late in the 4th quarter, and as such we would retain the earnings coming out of the assets with the expectation that we'll close and then not have those earnings for 2003. In terms of what we've said previously and we've not given any guidance for the calendar year 2003, we believe that over time xcel energy should be automobile to support an overall growth rate between 7 and 9% on average over time. Clearly, we've got a lot of things in transition this year in regard to nrg, not only in regard to the exchange offer but also in regard to the potential asset sales that will restore the balance sheet. As there's more clarity in regard to the timing and the ultimate financial relationship to all those activities, we'll give further guidance not only to the year-end 2002 and quarters for 2002, but then consider guidance for 2003 as well.

Okay. Well, I guess then specifically on the guidance for nrg for this year, can you give us the kind of rough mix between earnings coming out of international versus domestic assets?

We're looking the number up.

Okay.

In the meantime, the -- coming on the second quarter, that's 80 to 90% contracted, following up on a prior question. I guess those are mostly the contracts with first energy assets for those total requirements contracts?

The contract with first energy is a little different includes a fixed capacity payment for the capacity they're buying, and then energy payments which are intend today basically mirror the cost of production out of the facility, so the variability you see with let's say demand in the northeast should not and will not be replicated with first energy. Other than that, we have some tolling agreements in some of the plants that we're constructing and those make up the majority of those contracted pieces.

Okay.

Have a question from paul --

Just a moment, please. I was going to answer your question on percentage of earnings, domestic versus international. The expectation for 02, 90% domestic, 10% international.

Your next question from paul debis of valueline. Please go ahead.

This is paul debis. Couple utility questions. Given the sales weakness, what sales do you look poor for the year? And do you know yet what ps of colorado will be filing for its 43 rate case?

Take it in reverse order. In regard to the colorado rate case, which was in agreement that came out of the merger agreement, we'll be making that filing late in may. So we'll continue to work on that. It was a required filing. When you think about it, having been since 1992, in the last electric rate case was filed in colorado, we're not expecting a rate reduction. Part of our goal and plan is to keep rates low, but at the same time bring value to shareholders. So we'll put that filing in place later in may. In regards to the first part of your question, paul, if it has to do with sales growth, we're still expecting sales growth overall among all the various jurisdictions we operate in, between 1 1/2 and 2%.

Is that actual growth or weather adjusted?

That would be weather adjusted growth.

All right. Thanks.

You have no further questions at this time. Please continue.

Well, I'll now wrap things up. When we started here, we expected our first quarter 2002 results would be lowed than in 2001 due to the anticipated lower trading margins. However, as we think about the first quarter, actual results, we're clearly disappointed. Our results have been more adversely affected than we expected by both weather for our trading and marketing within nrg and within xcel energy markets, as well as pool prices. However, we expect to respond to the challenge. Our regulated operations continue to have strong performance. We operate on a growing and diverse service territory. And we'll continue to focus on cost management and customer service to ensure we deliver the results our stakeholders expect. Nrg has a good set of corps assets in operations. And has a highly skilled workforce and with the successful completion the tender offer and integration of xcel, nrg will benefit from a lower cost structure. It will have more engine be manageable growth, reductions in dependence and cost management reduced fixed costs and increased profitability. Finally, we're focused on managing our business. It was announced we did sell part of our subsidiary business to chevron energy solutions, and while we don't expect to have a material financial impact, it's still another effort at focusing our business for today in the future. With that, we'll just say it's been a challenging quarter, but we have a plan. We have the talent and dedication to respond accordingly. I want to thank you for your participation in the conference call and thanks again for your support and continued interest.

Ladies and gentlemen, that does conclude your conference for this afternoon.