阿莫林 (AEE) 2003 Q1 法說會逐字稿

Good morning, and welcome ladies and gentlemen to the Ameren Corporation first quarter 2003 earnings release conference call. At this time, I would like to inform you that this conference is being recorded and that all participants are on a listen- listen-only mode. At the request of the company, we will open up the conference for questions and answers after the presentation. I will now turn the conference over to Bruce Steinke. Please go ahead, sir.

Thank you, Janine. Good morning. I am Bruce Steinke, Manager of Investor Relations at Ameren Corporation. Here with me today is our President and COO, Gary Rainwater; Our SVP and CFO, Warner Baxter, and our Vice President and Controller, Marty Lyons. Before we begin, let me cover a few housekeeping details. This hour-long call is available to anyone who wishes to hear it for one week by dialing a play playback number. The announcement you received carries instructions on replaying the call by telephone. In addition, we would like to welcome everyone listening the call on the Internet. The webcast will be available for one week on www.ameren.com our website. This call contains time-sensitive data that is accurate only as of the date of today's live broadcast. Redistribution of this broadcast is prohibited.

I also need to let you know that comments made on this conference call may contain statements that are commonly referred to as forward-looking statements, such statements include those about future expectations, beliefs, plans, strategies, objectives and financial performance. We caution you that there are various factors that could cause actual results to differ materially from those projected in the forward-looking statements. For additional information concerning these factors, we ask that you read the forward- forward-looking statement and the relief we issued today in our filings with the SEC. Again, let me thank you for joining us. We will be brief in our remarks today to give you an opportunity to ask questions.

Gary will begin with call with an overview of our first quarter results and some operating matter, and Warner will follow with a More detailed financial review. Here's Gary.

Thanks, Bruce. Good morning, and thank you for joining us. This morning, we reported earnings of 63 cents per share for the first quarter of 2003. Compared to 42 cents per share in the first quarter of 2002. Ongoing earnings were 52 cents per share in the first quarter of 2003, excluding an 11 cent per share gain resulting from the adoption of a new accounting standard relating to recognition of asset retirement obligations. A return to more normal weather, improved power prices in the energy markets and solid availability of our low-cost, electric generating plants, boosted our ongoing earnings this quarter.

Our plants were not only available to meet the increased demand from our native load customers due to the colder weather, but were available to take advantage of power prices in the interchange markets that were significantly higher than last year this quarter was a textbook example of how we optimize our assets at Ameren. As we saw short term prices rise rising in the energy markets, our power plant operations and power marketing personnel worked closely together to keep our plants on line and to shuffle maintenance and work schedules in order to have our low-cost generation available during this period. These actions resulted in a 16 cent per share increase in contribution to interchange margins for the quarter by AmerenEnergy, our short-term power marketing arm.

We also recognize the importance of having our plants available during the peak summer periods and we're on schedule to complete all of our planned outages on a timely basis. You may noticed our announcement regarding an outage in late March at our Calloway nuclear plant. This outage was minor and not in the period of peak margins. During the 11-day outage, we replaced a valve that had a leak leaking gasket. The plant is now up and running well. During the quarter, we also moved forward with the implementation of our voluntary retirement plan. Nearly all 550 employees who accepted our offer, left the company by the latter part of the quarter.

We're still on target to achieve savings of 10 cents per share in 2003, from the voluntary retirement plan. Most of these savings will be realized during the remainder of 2003. Warner will discuss earnings in more detail, so I'll turn now to some other items of note in the quarter. On January 31st, 2003, we completed our acquisition of sill Corp. Upon completion of the acquisition, we immediately began to l formally integrate our operation operations and today the combination of our two companies is well underway. To date, we have found the operating assets to be in good conditions and our plans for managing these assets and attaining the expected synergies are still on target. We've realigned our organization and we have strong leadership in place at Sill Corp. Financial and operating systems are expected to be converted later this summer and fall. The bottom line is that we remain confident that the acquisition will be accreted to earnings per share, up to 5 cents in year one.

On the regulatory front, we have several activities taking place. Our Illinois gas cases continue to proceed. As you know, we have requested annual revenue increases of approximately $34 million for our three Illinois gas utilities. Since we last spoke, Illinois commerce Commission Staff has recommended approximately $19 million in aggregate revenue increases for those cases. Hearings will be held this summer with decisions in each case expected from the Illinois commerce commission by October. We've previously indicated that we are actively considering the filing of an AmerenUE gas rate increase request in the state of Missouri.

Our analysis shows that a rate increase would be appropriate, and we expect to make that filing by the end of May. We're still in the process of finalizing the actual amount of this gas rate increase. Keep in mind that our Missouri gas operations are smaller than our combined Illinois gas operations, therefore, it would be appropriate to assume the amount of our Missouri rate increase request will be smaller than our combined Illinois request. On the electric side of our business, many of you were aware that in February 2003, we filed for approval from the FERC and the Illinois commerce commission to transfer at net book value $550 megawatts of unregulated generation to our regulated subsidiary AmerenUE in order to meet generation capacity needs, primarily in the state of Missouri.

Approval of the transfer by the Missouri public service commission is not required. Since our filing, certain parties have made filings with FERC and the ICC, claiming that the transfer may harm competition for the sale of wholesale power or that other lower cost options are available, including the purchase of other generation assets. And recently, the ICC staff filed testimony expressing concerns whether this transaction is the least cost resource and recommending that the ICC deny approval of the transfer. We've made filings addressing these claims with the FERC and are in the process of doing the same with the ICC. You should note that, in this request, the ICC has jurisdiction only over approximately 7% of these assets.

The fact is, there are really generation capacity needs in AmerenUE and in the state of Missouri. The option we have proposed in this case is the most effective option to serve those needs. When one considers the transmission constraints on the system and overall costs. And I want to be clear, we strongly believe there is no viable option to purchase any new generation to serve our near near-term needs due to transmission constraints. It should also be noted that our proposal to transfer these unregulated generation assets at net book value to AmerenUE is consistent with the Missouri electric rate indicates settlement we reached last year. In fact, a letter from the Missouri public service commission which supports this transaction has been filed with the FERC.

Later today, we may learn whether the FERC will set this proposal for hearings since the matter is on their agenda today. While we had hoped to have this transfer completed before summer, customers will not be affected should the regulatory proceedings slow the transfer. Any energy needs in Missouri will continue to be supplied from our generation portfolio under our existing joint dispatch agreement with no impact on consolidated earnings. And finally, with regard to grid America and the Midwest independent system operator or MISO, regulatory proceedings are still pending before FERC and the Missouri public service commission. At this time we're still planning to be a member of grid America and MISO by later this year.

To wrap up, we're encouraged by our solid first quarter earnings and the near-term improvement in power prices. Having completed the CIL corporation ahead of our original schedule and with integration well under way, we believe we are on target to meet our goals for 2003. With that, I would like to turn the discussion over to Warner.

Thanks, Gary. Now onto a more detailed discussion of earnings results and other financial matters. In the first quarter of 2003, we reported net income of $101 million, or 63 cents per share, compared to 2002 first quarter net earnings of $59 million or 42 cents per share. Excluding the gain from the adoption of statement of financial accounting standards number 143, which I will discuss in a moment, we reported net income of $83 million or 52 cents per share in the first quarter of 2003. There were no unusual gains or losses in the first quarter of 2002.

In the first quarter of 2003, we recorded an after-tax gain of $18 million or 11 cents per share related to FAS143. FAS143 modifies the accounting for assets retirement obligations. For our regulated operations, the adoption of this standard resulted in an increase in both assets and liabilities associated with legal obligations for the retirement of long-lived assets of $200 million. The principal retirement obligation relates to our Calloway nuclear plant decommissioning obligation. While unregulated operations, adoption of this standard primarily resulted in removal costs accrued overtime as a component of accumulated depreciation being eliminated and recognized as income to the extent no associated legal obligation was identified.

Excluding this one-time gain, ongoing net income increased $24 million or 10 cents per share in the first quarter of 2003, compared to the prior period. As Gary discussed earlier, this increase was due to strong interchange sales margins and solid winter demand due to a return to more normal weather conditions. Favorable weather conditions in our [PreCIL Corp]. Territory increased earnings by an estimated 10 cents per share over the prior period. 80-degree days in our service territory were only 15% better than 2002, but only a few points better than normal. As a result, in Ameren's PreCIL Corp. acquisition service territory, weather sensitive residential electric kilowatt hour sales increased by 14%.

Commercial electric kilowatt sales increased by 5%, and gas sales increased 6% in the first quarter of 2003, compared to the first quarter of 2002. Earnings from interchange sales by AmerenEnergy on behalf of AmerenUE an AmerenEnergy generating company increased net income in the first quarter of 2003 by approximately 16 cents per share. Last year in the first quarter, AmerenEnergy contributed 5 cents per share to earnings. The increase in earnings on interchange sales was principally due to significantly higher power prices and greater availability of the company's low cost generating plant. Our average realized interchange sales price increased approximately 90% in the quarter. This improvement in power prices in the energy markets was well above our expectations and was driven by the colder weather and a spike in natural gas prices. As many of you know, natural gas is a major fuel for peaking generation here in the Midwest and as a result, the marginal price of electricity will often be set by the incremental cost of such generation.

Simply put, we were able to take advantage of our excess low cost base load coal and nuclear generation capacity during the period to sell into a market it was being driven by higher gas prices. We were also fortunate that our operators were able to keep our plants available to take advantage of this opportunity. This availability not only helped interchange margins but increased electric margins from our native low customers by approximately 4 cents per share due to greater use of low cost generating units to serve expanded native customer demand. Partially offsetting the benefit of net income of higher electric and gas margins was increased dilution and financing costs outside of those incurred in connection with the CIL corporation acquisition which reduced earnings by about 5 cents per share.

Consistent with our expectations, higher employed benefit costs related to plan performance and increasing healthcare cost in our historical Ameren business reduced earnings by $11 million or 4 cents per share. We also had no sales of admission credits in the first quarter of 2003, versus sales of 6 cents per share in the first quarter of 2002. As we discussed during our year-end conference call, based on environmental compliance strategy, we historically have sold approximately $20 million of emission credits annually. The ultimate timing and amount of these sales will be dependent on market conditions.

Earnings in the quarter were also reduced by approximately 2 cents per share due to the Missouri electric rate case settlement. You will recall that reduced rates and costs associated with that settlement were not reflected in our results of operations until the second quarter of last year. And finally, due to the fact that we have completed our equity financing for the acquisition of CIL Corp. in its entirety prior to the close of the transaction at the end of January, coupled with the fact that we only had two months of CIL Corp operation in the first quarter, earnings were down about 2 cents per share in the quarter due to the acquisition. This was certainly expected and we continue to believe that CIL Corp will be accretive to earnings in year one -- as we realize the synergies associated with this acquisition and a full year of operations.

Before I move on to our earnings guidance for 2003, I would like to point out that consistent with the current periods presentation, the first quarter of 2002 does include a netting of revenues in purchase power of other costs of $241 million related to our adoption in the second half of 2002 of EITF0203 and the rescission of EITF9810. You will recall that the adoption of these accounting rules had no impact on earnings. This completes my discussion of the main factors impacting our first quarter 2003 earnings. Today, we also reaffirmed our 2003 guidance 2003 guidance for earnings per share before the cumulative effect in the change of account accounting principle of $2.08 to $3.05 per share.

This guidance excludes the gain of 11 cents related to the adoption of FAS143. As Gary stated earlier, given our solid start in 2003, we remain confident in achieving our 2003 goals. Consistent with our past practice, as the year goes on and we get further into the peak summer cooling season, we will refine as necessary our earnings guidance. In all cases our guidance is subject to among other things. Plan operations, timely integrations of AmerenCILCO, weather conditions and energy market and economical conditions and other risks and uncertainties outlined in our forward-looking states. This completes our prepared remarks. We will be happy to take your questions.

Thank you. The question and answer session will begin at this time.

If you are using a speaker phone, pick up the handset before pressing any numbers. Should you have a question, press star 1 on your push button telephone. If you wish to withdraw your question, please press star 12. Your questions must be taken in the order that they are received. Please stand by for your first question. Thank you. Our first question comes from Scott Pearl (ph) with CSFB. Please state your question.

Hi, good morning. I was wondering, could you tell us as far as the higher availability of plants in the quarter what the capacity factor was for your cold fleet during the quarter?

Our capacity factor this quarter was about 67-68%, compared to last quarter, was right around 59%. Another metric, which may be helpful is that our overall equivalent availability was around 87% this year compared to 77% last year.

And as far as the revenues that you are recognizing for AmerenEnergy, is that a situation where that's pretty much your excess coal generation that's being sold off into the wholesale market in the area or was there any profits generated on buying and reselling activity as well?

The vast majority, Scott, not the vast majority, virtually all of our profits were from our physical plant. It wasn't from buying and selling in the market. So it was optimizing our low- low-cost generating fleet and in particularly our coal.

And as far as the $42 a megawatt hour price relative to last year, that's a little bit higher an off-peak prices in that area. Is it a situation where at some points you are selling the coal fleet on peak?

I'm sorry, Gary, go ahead.

Scott, I think the $42, I think, was the average of all of the power they're we sold during the quarter, and actually on- on-peak prices were at times considerably higher. We saw priors prices up in the $60 and $70 up in the megawatt hour. What’s happening in the market today is the high gas prices are driving the electric price. So for companies like us with a strong base of nuclear or hydro-coalfire generation, we're able to take advantage of that. The gas peakers really are not -- they are not being dispatched at all in this kind of a market, but we're taking advantage of the base load generation. To the extent that we can keep that generation more available, which is a key point that I tried to make, is that we've worked really hard to move our outage schedules around to keep that generation available, to take advantage of this market. We'll continue to do that the rest of this year.

But when I look at, you know, an average off-peak price of around $25 for synergy for the quarter, obviously gas has increased year over year, to get to $42, you have to sell on-peak during some periods of war.

That's absolutely correct. We're clearly selling some of our energy during peak periods.

What do you see as far as the remainder of the year for off-peak and on-peak prices for this excess generation? Obviously you had a goal, I think, of around 25 cents or so for the full year for AmerenEnergy, and it looks like you've made about 21 cents or so in the first quarter.

That's correct. As you rightfully say, our range was 20 to 25 cents for AmerenEnergy. We've attained 21 cents so far. As we look forward to the year, we do see solid pricing. To give you some metrics, if you look at on-peak prices, the 5 by 16 in synergy, probably for the April through June time frame, we're seeing visible markets probably of $40-45. Prior to July through September, we're saying a range of $35-$55 and in the last quarter, around $35-40. We're still seeing solid prices. They are not as strong as they were in the first quarter where we probably saw prices going up into the 60s and 70s and often average priced somewhere between 45 to 60.

In general, for the volume for AmerenEnergy tends to come more in the first quarter and fourth quarter in the shoulders? Did you need that more the fleet for the [Inaudible] in summer.

I think that's a fair statement. Certainly we would expect during the peak summer cooling season that much of our low-cost generation will be served -- used to serve native load, but keep in mind that's during the peek period during the summer. We certainly have the opportunity during those off peak time period so still sell some of that energy.

Are you still seeing high off-peak periods in the region then more to the first quarter.

They've come off little bit as well. I don't have specific metrics, but we still see the off-peak still being solid throughout the remainder of the year, but just as we saw in the first quarter, we're not seeing quite the same level of strength for the remainder of the year.

Okay. Thank you very much, Warner.

You're you are welcome, Scott.

Thank you. Our next question comes from David Frank (ph) with Zimmer Lucas Partners. Please state your question.

Yeah, hi, good morning, guys.

Good morning, David.

I was wondering, Warner, you gave a comparison of the weather impact this quarter versus first quarter this year versus last year. Do you have the weather impact versus normal for the first quarter?

Sure.

As far as millions of dollars?

I guess with regards to millions of dollars, I would suggest that whether was basically normal. It was basically flat from our perspective in the first quarter. It was up 10 cents compared to the prior period, but we had a warm winter season last year, so I would characterize this first quarter as being virtually flat from a normal standpoint.

Okay. And you mentioned something about emissions credits. You gave a number. I missed that. Was that 6 cents year over year?

That's correct. It was 6 cents last year and we did not sell any emission credits this quarter.

Okay. And could you talk a little bit about this process of trying to rate base some of these Illinois peakers and Missouri, how big a problem is this recommendation for you in Illinois? Is there a way to get around it? What's the timing? Do you think you'll ultimately be successful, and if you're not, what's the contingency plan then?

David, that the point, we don't see it as a serious problem. Remember, the key points here are that it's primarily for Missouri, and Missouri wants hard assets. That's the reason we're doing the transfer. It's drawing attention at FERC, as you would expect it to because of other power suppliers out there who have excess capacity, but at worst, I guess I see it as a delay, and, again, there are other options, another option we could ultimately use is simply the transfer our Illinois service territory rather than transferring transfer the assets and that way we would be aligned more along state lines with UE being a fully regulated utility in Missouri and CIPS being un unregulated in Illinois, but the primary option, Missouri wants hard assets, we're transferring hard assets to meet that desire, and almost all of it would berate based in Missouri. I mentioned only 7% would be rate based in Illinois, a minor piece of it.

A couple other points. We're at the very front end of the regulatory process. This is the ICC staff recommendation. We will respond to their filing, and today, we will likely hear -- we will find out if the FERC will set this for hearings. That may or may not be the case. So we're still very early in the process. I mean, all things being equal, we would like to have it done by summer, if we have to go through hearings, that's fine. We strongly believe that the option that we have chosen, not only best meets the needs of the capacity needs and is really the best option given existing transmission constraints and the overall cost. And similarly, as Gary alluded to, this is a situation where Missouri really wants the hard assets and clearly this option that we've proposed is consistent with the Missouri rate case settlement that we reached last year both in terms of the transfer of the assets and the fact that we said we would attempt to do it at net book value. We're still early in the process, and you know, if we have to go through the normal regulatory process, so be it, but we believe we have a strong case to move forward on this.

Let's just assume the Illinois Commission came out and said no, you can't move them, they control 7% of your total generating assets in Illinois or 7% of the specific assets you're looking to move, how could you make your Illinois jurisdiction jurisdiction -- how could you transfer the whole jurisdiction to Missouri. Gary said something and I was confused by that.

Keep in mind, union electric has operations in Missouri and a small piece in Illinois, which is why this proceeding came before the ICC staff. We talk about 7%. It's an allocated percentage based upon our historical allocation factors. That's why the issue is in front of them. And so, certainly to the extent the ICC staff has raced raised concerns, we may we able to address those concerns in the form of discussions or the form of a settlement to make sure we get this done. But again, we're really at the very start of this process with them, and so how that plays out, and what we think the best course of action will be, will be determined by the various rate case proceedings that will go through the rest of this year, if necessary.

David, another point to keep in mind is that this makes no difference to the bottom line because rates are frozen in both Missouri and Illinois for the next three years.

That's a good statement, Gary. Essentially, what will happen to the extent this gets delayed as Gary alluded to, I believe in his talking points, would be that the assets and the needs would still be served by exist existing generation capacity by Ameren and we have in place an existing joint dispatch agreement really to address this issue. What we're simply trying to do is put the hard assets where they're going to ultimately be utilized in the state of Missouri which is consistent with the overall desires of the state of Missouri. They would ultimately be put into rate base when we have the regulatory proceeding at the end of the rate moratorium, sometime in 2006, as you well know.

That's kind of what I was looking at, too, is what would happen if you couldn't use those assets for satisfying the need that was specified in that settlement and had to -- was there a potential that you would have to go out and acquire other assets, but it sounds like you probably will work this thing out. I guess FERC ultimately has the final say in this matter?

I think with regard to the final say, they certainly have a say in this matter as well. And so they have jurisdiction over this transfer as well. So they -- I wouldn't characterize them as more or less. They both have a say.

Okay. Great. Thanks a lot, guys.

You're welcome, Dave.

Thank you. Our next question comes from Doug Fischer with AG Edwards. Please state your question.

Thank you. Just to follow-up a little bit on this issue, since I think some of the others have been covered, what is the standard that FERC is using for approve or disapprove this asset transfer?

And Doug, when you say "the standard" what is it specifically that you are --

I think in Illinois, the ICC staff is raising, is this the most economic way to meet the need, and I think there is serious questions with the staff staff's testimony, but you know, that seems to be where they are looking. Is the FERC looking at -- is this the most economic? Are they looking at market power? What's their standard? Is it the same as the ICCs?

I would suggest that -- I wouldn't say that they are dissimilar. I think FERC looks more at the competitive basis, and, of course, obviously, they have to look for rates as well, so my guess is that they blend both of those pieces into -- of course, we haven't seen specifically any filings or anything from the FERC staff, but in general, that's what they would be looking at.

Did you file all of the same testimony at the ICC that you filed at the FERC?

At this point, no. We've filed most of the testimony at FERC. We will be filing -- since many of the interventions, we filed testimony at FERC were based upon existing interventions to date and the issues that were raised. Some new issues now as a result of the ICC staff's filing has come out, so we will file additional testimony which will be, in many respects, very consistent with what we filed at FERC, as well as supplemented as well as necessary to the extent that the ICC staff raises additional issues. So we will still be filing more data, some of which we have already filed at FERC with the I ICC.

Doug, keep in mind that while FERC is going to look primarily at the competitive issues, they are also going to weigh the state's desires, and the state of Missouri wants hard assets. Once the assets are transferred, it's really a retail issue, not a wholesale competition issues. To some extent they have to weigh that and they should defer to the state's desire. That makes me optimistic that we will get the FERC approval and we'll be able to transfer the assets.

Okay, thank you, Gary.

Thank you. Our next question comes from Daniel Seitz (ph) with Salmon Smith Barney. Please state your question.

Hi good morning, I was wondering if you could give us an idea of how much was a contribution to earnings from -- AmerenEnergy, and also, could you compare that with what you were anticipating for the year? It seems that it's overwhelmingly larger, that I was wondering if actually there were some other negative factors that make your guidance haven't change.

Hi, Daniel. As far as AmerenEnergy They contributed 21 cents per share to the quarter. When you compare to the prior period, they contributed a nickel per share. They were up 16 cents per share for the quarter. Clearly as we said before, they've been off to a very strong start, and as we said earlier in the call, the expectations going into the year for AmerenEnergy's contribution ranged between 20 and 25 cents per share. Obviously given where we're at today, we feel very strongly that we'll exceed those expectations. We're not going to be providing any additional guidance today with regard to what our overall expectations are for AmerenEnergy forest of the year. We will see how the summer cooling season approaches. And we will update that guidance as well as our overall earnings guidance as appropriate later in the year and perhaps during the second quarter conference call. So basically, when you look at the in increase in electric margins , what I also then identified -- that, obviously, was very positive and that included AmerenEnergy, improved weather compared to the prior year, coupled with lower fuel and purchase power cost, those things were offset by the fact that we did not have emission credits this year which was 6 cents per share, where we did last year. The rate case, which I pointed out, lowered earnings 2 cents per share. Employee benefits, as we have discussed in the past, they were up a nickel but certainly in line with our expectations for employee benefits this year. Dilution and related financing costs and I'm talking about dilution related to CIL Corp. but keep in mind that last March we did the equity dilution to strengthen our balance sheet, that reduced earnings about a nickel per share, and a host of other things. All of that, when you add them all up, get you the incremental 10 cents per share.

Uh-huh. I was just wondering if actually, for example, purchase par costs might be more obviously more expensive, given the fact that prices are much higher, and I was wondering if any of those given, you know, factors have changed in your forecast.

I'll tell you, if you may recall, last year, during or year-end conference call, we talked about sales growth. One of the things that we talked about this year, which is going to contribute to overall sales margin growth, electric margin growth in particular was the fact that we were going to have more low-cost generation available throughout the year, especially given the fact that Calloway does not have a refueling outage. That's what we're seeing in this first quarter is, in fact, lower fuel and purchase power cost because we're using our own plants. We've had to -- our purchase of power is down over 50% this quarter versus last because we've had our plants not only available, but running at optimum capacity this quarter.

Uh-huh. And you anticipate this -- I was more looking into future quarters, and if you expect the same advantage to continue or if you are concerned about longer term purchase power costs?

Daniel, do you mean are we really concerned about negatives out there, we don't see any negatives. Things are shaping up to be a good year. We're simply recognizing that we're only into the first quarter of the year. We're facing the summer season ahead, lots of things can happen and so one year doesn’t make the quarter so that’s the reason for our conservative stands right now

Okay thank you. .

One quarter doesn't make the year is what I meant to say.

Thank you, our next question comes from Philson Yim with Morgan Stanley. Please state your question. .

Hi good morning. Just I was wondering if you could talk little bit more about the details on the O& M reductions, the voluntary retirement program package and the benefit you are expecting from there and the union contract renegotiations and so forth.

Sure, I'll touch on the voluntary retirement program then I'll ask Gary to comment on the status of our contract negotiations. With regard to the VRP, as we said, 550 employees accept the offer. Many of those employees didn't leave until the latter half of the first quarter, so, what you really see in the first quarter results are very minimal favorable impacts as a result of the VRP. With regard to the year, we still fully expect to achieve a 10 cents per share in earnings as a result of the VRP and next year, due to the fact that we'll have now that additional quarter of the employees being gone, we will have an increment of 2 cents, in total 12 cents per share saved with the VRP. Gary, do you want to address where things are with the contract negotiations?

We're just beginning contract negotiations. Our major contracts expire at the end of the June this year, and we actually have not notified the union of our formal positions yet, and I really don't want to get into a discussion of contract negotiations in the conference call, but we expect to be able to wrap up negotiations without labor issues this year, I guess is the only point I would want to make.

Okay. Great. Thanks. And also, could you guys talk about remind me of how -- what the weather impact was in the summer, the warmer than normal summer last year?

With regard to the specifics, I'll have to try and get that out as to what extent it was. I know last year for the entire year was -- compared to normal, about 24 cents per share, which in large part related to our electric business. I don't have that number specifically as to what the summer was, but the second and third quarter, we might be able to get that before the call is up, but I know last year it was in total 24 cents per share and the vast majority of that was due to summer weather conditions.

Okay, one last question. I was wondering if you could talk about forward contracting on regular generation into 04.

The weather in the second quarter was positive 12 cents.

Thank you Bruce.

I'm sorry, Philson, could you state your question again?

Sure, the progress on the contracting of the unregulated generation into '04.

I think that's still certainly a target of what we've been doing. We've been entering into some additional contracts on the long-term basis for, you know, our unregulated generation fleet. Where we stand today is in ‘03 we're over 90% hedge for our unregulated generation and next year is pretty much the same. And so, that combines both the fully contracted to third parties as well as the contract back for our CIPS native load customers and the like. Keep in mind, too, when you look at that CIL Corp., when we acquired them, they are 250 megawatts short. Some of that capacity will go to serve their needs as well.

Do you think you'll get a benefit from the higher power price, the recent higher power prices like when your contract runs out in '04, or were those done earlier.

We have contracts which were done earlier. I think what we're seeing in the forward prices beyond a year, we've seen them up tick a bit but certainly we're not seeing that level of volatility or the percentage increases that we are seeing in the shorter term market. The liquidity isn't still quite the same either, so it's a combination of both of those factors. We are seeing some improvement in price but certainly not to the extent that we've been discussing on the short-term basis.

Okay, thanks a lot.

You're welcome.

Thank you. Our next question comes from David Groomhoff (ph) with Copia Capital. Please state your question.

Hi guys how are you.

Hi David, how are you.

Back on the emissions credit, I know you've said Warner you realize $20 million a year in sales from emissions credits. My recollection was that number was higher in '02. The first question, is that correct, and do you still think you'll get to that $20 million in '03 or is it more of a wait and see.

Keep in mind that 2002, David had really two pieces to it. One was sort of the Ameren piece, which we typically sell right around $20 million. That's really about what we did. Last year, which was a little bit unusual, is that EEI, our 60% own the subsidiary. They sold emission credits, and they did that principally in the second quarter. That was about 10 cents per share. So all things being equal, that 10 cents per share for EEI to that extent will not be repeated. They will likely get some level sales off but not to that extent this year, so I think that's maybe what you're thinking about.

And so is $20 million a good number to think about for '03?

I think, of course, when we talk about emission credits, we think in terms of not just our environmental complaints, but market conditions, but historically, we've been right around that $20 million Mark for several years, and so that would not be an unfair assumption.

Okay. Can you just -- secondly, can you outline a little bit about capital expenditures going forward now that Sill Corp. is in the fold in this year and especially as it relates to environmental compliance?

Sure, happy to do so. With regard to this year, our overall CAPEX will approximate around $675 million, CIL Corp. will be $100 million of that. $50 million roughly relates to environmental compliance for Knox. So as an ongoing basis, we would expect maintenance CAPEX for the company as a whole to approximate $450-500 million with CLI Corp. in that $50 million range. If you look at the next lets say 5 years we estimate the CAPEX to be in the $3-3.3 billion range, which is basically on a -- well, you may see some lumpiness in CAPEX over the next five years, basically, we think they'll average right around the $675 million dollar metric.

Thanks. Congratulations on a good quarter.

Thanks David.

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