愛迪生國際 (EIX) 2005 Q2 法說會逐字稿

Welcome to Edison International's conference call. This call will be available for replay at the following numbers -- 877-693-4277, and for those calling Internationally 402-220-0042. You will need to use the pin code of 10401 to access the call. For your information this call is being recorded. Also, we want to advise you that Edison International is holding a simultaneous Webcast of the conference call. This will be on the Company's website in a listen-only mode for interested parties. When the conference begins you will be on listen-only and there will be a chance for questions-and-answers at the end of the conference. In addition, if at any time during the conference you are in need of assistance from a coordinator, please press star followed by zero on your phone. Thank you for your patience. The conference will be beginning shortly. And at this time I would like to introduce your host, John Bryson, Chairman and CEO of Edison International. Thank you, and go ahead, Mr. Bryson.

Thank you. And thanks to all of you on the phone for joining us today. We will start with the usual forward-looking advisory statement. Barbara Mathews will provide that.

During this call we will make forward-looking statements about the financial outlook for Edison International and its subsidiaries, and about other future events. Additional forward-looking information may be available on our website at www.edison investor.com. We believe these statements and this information to be reasonable and well-founded, however, actually results could differ materially from current expectations. We have set forth important factors that could cause different results in Edison International's 2004 Form 10-K report and subsequent 10-Q and 8-K reports, including its second quarter Form 10-Q report filed today. We encourage you to read those reports carefully.

All right. Many of you on the phone have already seen the materials we released earlier this morning. I will simply say that we are pleased with our progress through the first half of the year and that we expect further positive results during the balance of the year. With regard to the second quarter, Edison International reported earnings of $0.61 per share. That compares to a loss of $1.15 per share in the second quarter of last year. Both periods include non-core items, including a large lease termination charge taken last year at an Illinois power station. If we exclude those non-core earnings, core earnings for the second quarter were $0.55 per share. That is a $0.34 increase over the second quarter of last year. On a year-to-date basis, core earnings were $1.20 per share. That is $0.91 per share above the first half of last year.

Each business segment of the Company has achieved improved core earnings, not only for the second quarter, but also for the full first half of the year. I'm going to ask Tom McDaniel in a minute to review in detail those earnings with you. I wanted at the outset, however, particularly to highlight two key performance factors for this year. First, our 2005 results include lower net interest expense as compared to last year, and that reflects our continuing effort to reduce debt and strengthen our balance sheet, which as most of you know has been one of the critical elements of our strategic plan. Also contributing to the increased core earnings this year have been improved operating results at our independent power business where we have benefited from strengthened energy prices in the Midwest and the Eastern wholesale power markets.

Significantly, we are today looking ahead and increasing our prior guidance for earnings for the full year 2005. Based on results today in that outlook we expect core earnings for 2005 will be in the range of $2.53 to $2.63 per share. That is about 20% above our prior guidance. Let me say with respect to 2006 earnings guidance we do not anticipate providing that until after we receive Southern California Edison's 2006 General Rate Case decision from the California Public Utilities Commission; that decision is expected in January. We will, however, continue to provide at these quarterly reports our updated Mission Energy Holding Company hedge positions. I'll stop there and let Tom McDaniel take it up from here.

Thanks, John. Let me begin with a discussion of our quarterly and year-to-date performance compared to last year. I will then provide an update on hedging for the balance of 2005 and for 2006 at MEHC's Midwest Generation and Homer City plants, and additional detail on our earnings guidance for 2005.

As John mentioned, second quarter consolidated earnings were $0.61 per share, compared to a loss of $1.15 in the second quarter of 2004. I'll first separate the non-core items before I discuss the core items. Non-core items in the second quarter of 2004 were comprised of positive adjustments of $0.36 per share at SCE resulting from regulatory decisions, and $0.08 per share representing the operating results of our international projects that were sold last year. These gains were offset by a loss of $1.80 per share from the Collins lease termination. The net effect of the 2004 non-core items was a loss of $1.36 per share, compared to non-core items for the second quarter of 2005 of $0.06 per share, primarily from distributions received from the settlement of a termination claim against TXU Europe for the Lakeland Power project. Excluding these items, EIX's core earnings for the second quarter of 2005 were $0.55 per share, compared to $0.21 per share in the same period last year. Each of our reporting entities contributed this increase in core earnings, SCE was up $0.11 and MEHC up $0.16, Edison Capital up $0.04, and the Holding Company up $0.03.

Now, we'll go through this on a company-by-company basis. SCE's second quarter 2005 core earnings were $0.49 per share, $0.11 above the same period last year. Virtually all of this increase is due to higher authorized revenue in 2005 from implementation of the 2003 General Rate Case decision. SCE received the 2003 decision last July, therefore, the first and second quarter earnings of 2004 did not include any revenue impact from this decision. The full year revenue impact was picked up in the third and fourth quarter of 2004. Thus, when we compare the full year of 2005 to last year it is not expected to reflect a year-over-year core earnings difference as a result of the decision. SCE's second quarter earnings compared to last year also reflect higher CPUC authorized revenue related to the Rate Case decision. Tax benefits and lower net interest costs, which were offset by higher operating expenses.

MEHC's core earnings were breakeven during the second quarter of 2005, compared to a loss of $0.16 cents per share for the same period of 2004. The increase in core earnings is primarily due to lower net interest expense of $0.04, higher wholesale energy prices at Midwest Generation contributing $0.04, higher income at EMMT of $0.03 from sales into the New York market and positions which benefited from higher levels of transmission congestion and resolution of a prior-year tax issue of $0.04. It's important to remember that typically second quarter results from MEHC are the weakest of the year because it contains lower shoulder period prices and higher planned maintenance activities. During the second quarter of 2005, we had a higher level of planned maintenance than the prior year, which resulted in lower generation and higher maintenance costs. Our maintenance program varies year-to-year based on cycle times for major equipment and our assessment of plant performance. In addition to planned maintenance, unplanned outages were also slightly higher in the second quarter of 2005 compared to 2004. As a result, Midwest Generation generated 5.8 terawatt hours in the second quarter of 2005, compared to 6.1 TWh in the second quarter of 2004. Homer City generated 3.1 TWh during the second quarter of 2005, compared to 3.4 TWh during the second quarter of 2004. I'll discuss the expected full year 2005 generation for Midwest Generation and Homer City later in my comments.

Turning to Edison Capital, the second quarter earnings were $0.08 per share, up $0.04 per share over the same period in 2004. The increase is primarily due to Edison Capital's share of income from its investment in the Emerging Europe Infrastructure Fund. The fund has sold its interest in an Eastern European wireless company. Edison Capital's share of the gain related to the sale was $0.04 per share. And lastly, with regard to the Holding Company, it was up $0.03, primarily from lower net interest expense.

Now, I'll turn to year-to-date results. EIX reported consolidated earnings through June 30, 2005 of $1.23 per share, compared with a loss of $0.85 per share at the same period in 2004. I'll discuss it again, the non-core items before I discuss core earnings. Year-to-date 2004 non-core items were comprised of the SCE rate-related items of $0.36 per share, International project earnings of $0.22 per share, and $0.08 per share net gain from the sale of our Four Star and Brooklyn Navy Yard projects. And also, again, the Collins lease termination loss of $1.80 per share. These items combined produced a loss of $1.14 per share, compared to a year-to-date 2004 non-core items totaling $0.03 per share. And that's comprised of $0.08 per share from International asset sales, and the Lakeland distribution, and a loss of $0.05 per share from the early paydown of MEHC debt. Excluding these items, EIX core -- or year-to-date core earnings for 2005 were $1.20 per share compared to $0.29 per share in the same period of last year. Each of our reporting entities contributed to this increase in core earnings, SCE was up $0.20; MEHC, up $0.48; Edison Capital, up $0.17; and the Holding Company, up $0.06.

SCE's year-to-date core earnings for the period ending June 30, 2005, were $0.89 per share, $0.20 above the same period last year. Again, virtually all of this increase was due to higher authorized revenue in 2005 from the implementation of the 2003 General Rate decision. SCE's year-to-date earnings compared to 2004 also reflect higher CPUC authorized revenue and tax benefits offset by higher operating expenses. Turning to MEHC, core earnings were $0.13 per share in the first half of 2005, compared to a loss of $0.35 per share for the same period in 2004. The increase in core earnings is mostly due to higher energy prices at Midwest Generation, $0.19; and lower net interest expense benefiting earnings by $0.09; higher income of EMMT of $0.07; and the resolution of the prior-year tax issue, $0.04. A number of others, smaller items, including higher income from Homer City and the Big Four also contributed to the gain.

Edison Capital's earnings for the first half of 2005 were $0.24 per share, compared to $0.07 for the same period last year. Increase of $0.17 per share is due to income from its investment in the Emerging Europe Infrastructure Fund. Addition to earnings from the sale of the Eastern European wireless company, which impacted the second quarter, Edison Capital reported $0.13 per share in the first quarter from mark-to-market gains on several other telecommunication investments the Fund holds in Eastern Europe. These earnings may fluctuate from quarter-to-quarter based on changes in the fair value of these investments. Lastly with regard to the Holding Company, it was up $0.06, primarily from lower net interest expense, partially offset by higher taxes.

Turning to Midwest Generation and Homer City operations, our Midwest Generation's plants generated 14.2 TWh during the first half of 2005. We currently expect to generate around 16.6 TWh for the remainder of the year, resulting in total 2005 generation of 30.8 TWh. This is lower than the forecast of 34 TWh we provided last year. Expect a reduction in generation is largely in the lower margin off-peak periods, some nights and weekends, when power prices are relatively low. As I will explain more in a moment, the affects on our original earnings forecast of lower expected generations have been more than offset by higher power prices. We've been asked about the affects of the rail line disruptions on power deliveries of Powder River Basin coal to our Illinois plants. The railroads are in the process of making repairs to the rail lines and advised their customers, including us, that shipments will be curtailed 80 to 85% through November of this year. We're working with our transportation provider to insure that we receive contracted amounts to the maximum extent permitted. Based on the communication with our transportation provider, we believe that we will have -- we will receive sufficient coal supplies to meet our current generation outlook. The 14.2 TWh generated for the first half of 2005 resulted in an average realized price of $40.12 per megawatt hour. Of the 16.6 TWh expected to be generated from Midwest Generation for the remainder of 2005, we have hedged 9.4 TWh or 57% of that volume at an average price of $38.15 per MWh. The June 30 balance at the year-forward flat energy price at NIHub was $40.46.

Turning to Homer City we generated 6.6 TWh during the first half of 2005, and we currently expect to generate about 7 TWh through the remainder of the year resulting in total 2005 generation of approximately 13.6 TWh, which is slightly lower than the original forecast of 14 TWh. This slight reduction in generation is due to higher planned maintenance for the year. Of the expected generation for the remainder of 2005, we have hedged 4.6 TWh, or 66% of that volume at an average price of $44.94 per MWh. The June 30 balance of the year-forward price at PJM West was $50.25 of MWh. Now, I'll turn to the 2006 hedging program. During the second quarter we hedged 9.7 TWh of 2006 production at Midwest Generation at an average price of $41.84 of MWh. At Homer City, we hedged 5.3 TWh of 2006 production at an average price of $51.50 per MWh. On June 30th of 2006 calendar year flat price was $42.73 per MWh in NIHub and $53.66 per MWh for PJM West.

Now, I'll turn to 2005 earnings guidance. As John mentioned, due to changing market conditions, specific events, and the completion of half of the year, we are providing today an update of our 2005 guidance for core earnings at the range of $2.53 to $2.63 per share. And the guidance for reported earnings, which includes $0.34 per share of non-core items is updated to a range of $2.87 to $2.97 per share. First, let me discuss the $0.34 in non-core items. These items include two items identified last October, costs related to MEHC's early debt extinguishment of $0.05 per share -- and this was recorded in the first quarter of this year -- and a favorable tax settlement at SCE of $0.11 per share. In July we received this tax settlement and will record this benefit in the third quarter. In addition, we expect earnings from MEHC's discontinued operations to be $0.28 per share, primarily from the settlement of the Lakeland termination claim. We expect the Lakeland settlement will result in a net gain of about 88 million overall, of which 24 million or $0.07 per share was recorded in the second quarter. The timing of the remaining amount depends on obtaining a final determination of taxes from this distribution from the U.K. tax authorities. We expect this to occur late this year or it could move into 2006.

Now with respect to core earnings. As I mentioned earlier, we expect that range to be between $2.53 and $2.63 per share, compared to $2.14 per share provided last October. SCE's core earnings are expected to increase $0.05 per share over initial guidance from $1.75 to $1.80 per share. This increase is primarily due to better operating results, in particular, lower net interest expense from refinancing activity and lower taxes for the year. Next with regard to MEHC. In October, we provided earnings guidance of $0.34 per share. Not surprisingly, since October, there have been changes in market prices for power, coal, and emissions, and we have now completed one half of the year. And while we emphasize that the upcoming third quarter, the peak summer season is key to our full year earnings, we have provided today an updated estimate of MEHC's 2005 earnings in the range of $0.55 to $0.65 per share. This guidance reflects a new generation outlook that I mentioned earlier and updated market prices for power, coal, and emissions.

Next with regard to Edison Capital. Evaluation of its investments in the Emerging Europe Infrastructure Fund have increased significantly since last October and has reflected in year-to-date earnings. These changes in a change regarding the capitalization of Edison Capital expect a result in 2005 earnings of about $0.28 per share. However, there is potential for that to vary quarter-to-quarter as certain assets are valued and mark-to-market. Finally, the loss from the EIX parent company is expected to be $0.10 per share, or $0.07 higher than our initial guidance, driven primarily from the change regarding the capitalization of Edison Capital and higher taxes and other expenses. Of course, the updated guidance is subject to market and other risk factors set forth in our 2004 Form 10-K, and our first and second quarter 10-Qs. With that, rather exhausted review, I will open it up to questions.

All right, what questions do we have? We have a large group of people here [audio difficulty] willing to detail on any of the subjects Tom touched on.

Ladies and gentlemen, [OPERATOR INSTRUCTIONS]. Our first question is from Greg Gordon of Citigroup Investment Research. Go ahead, please.

Thank you. With regard to the output projections for the balance of the year for both Midwest Gen and also for Homer City, should we think about those production levels as being sort of the levels of capacity utilization availability that you expect going forward into '06? Or were there fitting -- were there extended outages or maintenance decisions that were made this year that caused production levels to be depressed?

Yes, Greg, we're not going to provide '06 guidance at this point in time. And as we update our full fall forecast we will cover '06 at that time.

Okay. Well, were there any outages at least year-to-date and for the balance of the year that are planned that were discretionary, that weren't done in the normal course?

Yes, there were. And really centered around some work that we were doing at Homer City and then some work at Midwest Gen. As you know we were bringing the two units on at Will County after they had been mothballed for some time, and there's always some issues in terms of bringing units like that back on-line and into service.

Now, on a General Rate case, are there any specific issues that you think we should be focused on that are critical to you being able to establish the '06 guidance? And is that why you're holding off until after the resolution of that case?

I think -- Greg, there are no issues we would single out. It's a very major case. We've underscored in the past and do again today how important that is to us. As you know the previous case, the so-called 2003 General Rate case, set important precedence in the mode of rate-making; that is, with this forward-looking test year rate-making in which rates were set for out years in advance, conditioned only on making the capital expenditures to which we had committed, and the Commission in that case had approved the principle of infrastructure replacement.

So we believe the system needs these capital investments, the level of capital investment is way above what we had done over the five years prior to 2004, and we're looking for affirmation again for that in this General Rate case. But we don't want to get ahead of the Commission in that respect, so we'll wait to see what they actually do. There's nothing there that we haven't pointed out in previous advisories to all of you.

Great. And lastly, when it comes to the Energy Bill, which has just been signed this week, there was some language in there with regard to PURPA contracts, which frankly, I don't fully understand the implications. Is there any implications for your California generation position and changes in -- that were enacted in the Energy Bill?

None that we see at this time.

Thank you very much.

Our next question is from Michael Goldenberg with Luminous Management. Go ahead, please.

Good morning, guys.

Morning.

I wanted to talk more about coal deliveries. I was wondering if you could elaborate some more on what's exactly happened up until now with the coal deliveries, and what you envision in the future?

Well, let me turn it over to Ted Craver to cover that.

Hi. Well, I think it's pretty much what Tom indicated in his opening remarks. We have received official communication from our rail provider that due to the track repairs that they expect coming out of the Southern Powder River Basin area, that coal shipments for all of their customers will be curtailed down to about 80 to 85% of contracted amounts through the end of this year. It's a little open as to whether any of this will continue into next year, but at this point, no communication on that. We feel we're in reasonably good shape from the standpoint of inventories based on the new forecast that Tom gave you for our production for the remainder of the year.

At any point in time up until now, did you ever choose not to run because you didn't have enough coal, even though running plants would be profitable? Or do you envision any such situation in the future?

Up to this point, we have not had to curtail any production due to coal supply problems. And in terms of going forward, as I said, I think we feel that we'll be able to meet the forecasted production that Tom gave you based on what we see and based on the levels of coal deliveries that the railroads have told us should be forthcoming.

But the production numbers, the projections, are they in anyway curtailed because of coal schedules that you've been given, or that's pretty much what it would have been had coal deliveries been more or less normal?

I think that's what we would expect. Really, the production levels to be with or without the coal interruptions.

Okay. And my other question is at Midwest Gen, how many megawatts of peaker's [gasonal] do you have if they're ready to go or on standby that could be unmothballed relatively quickly?

We have a very small number of peakers that are available. All the others have been decommissioned.

So bringing them back would be a lengthy process?

No, they cannot be brought back. They are decommissioned.

Okay. Do you have a number of megawatts that are still operational, or could the operation --? [multiple speakers].

Operational? They hardly run at all. [multiple speakers].

I think it's under 200.

Gotcha. Okay. Thank you very much.

You are welcome.

Our next question is from Paul Patterson with Glenrock Associates. Go ahead, please.

Hi, good morning, guys.

Good morning, Paul.

First on Edison Capital. I know it's hard to project, but any idea about how sustainable this increased profitability would be after 2005?

Well, it really is hard to project. We've had a very successful run with our Eastern European Fund. The current investment balance of Edison Capital with respect to the funds that it has investments in is $187 million. And I think that's really a starting point for being able to make some assessment as to the kind of returns we might generate off of that investment balance, and then the exit strategies that might be employed. And we are now into the point in time where the fund investment periods are closed, and we're now into that point in time where those investments will be harvested over time, and that would likely occur over the next two to three years.

Would you still stick to the 4 to 7% growth that you had when you gave guidance originally in '04 as long-term growth rate? Or has this harvesting I guess earlier in '05 changed that projection at all, or is it just too hard to say?

Well, I think it really is hard to say. It really depends on the values that can be derived out of the remaining investments and those can move, oh, positively or negatively. But what we would anticipate is that we would be able to translate some of these unrealized gains that we booked in the first quarter to realized gains as the investments are actually sold out of the fund, as what occurred in the second quarter.

Okay. With respect to the emission allowances, I was wondering, I didn't -- I missed it, and I apologize if I missed it. But was there any discussion about what your outlook for emission allowances are? Any sensitivity there with respect to earnings or --?

Well, that's why we have provided the updated guidance which reflects kind of our thinking as to the impact of kind of really the three key factors here, power prices, volumes, emission cost, and fuel cost.

Okay, and the emission cost, what was that again that you guys were projecting now?

Well, we didn't. That's why we provided you with a range of guidance to take really all of that into consideration. In fact, we have a half year of operation under our belt and then what our outlook is for the remainder of the year.

Okay. I'm sorry. Thank you very much.

And to tell you the truth, we felt this was better way to go at this point in time than providing the tool kit, because that only covers really one dimension of our performance.

Thanks a lot.

Our next question is from Ashar Kahn with SAC Capital. Go ahead, please.

Good morning. Going to the -- is there some way to gauge that how -- what would have to happen that you come at the upper end of the emission energy guidance, is it better prices, or better output? I just wanted to get a sense as to the sensitivity of $0.10, as to how we should look at it. That what makes you hit the upper end versus the middle or the lower?

Well, we still have an open position with regard to unhedged expected power sales, which would be impacted by market prices.

Okay.

And potential volume changes around what we've provided. Again, we need to get through this summer season, and I think that will dictate for us where we fit within that range.

It's probably a little more price sensitive than volume sensitive, because the increases in volume would really come in the off-peak periods. So it's probably a little more sensitive to the unit price.

Okay. And when you based this forecast was it based on a curve just recently or a couple of weeks ago, or three weeks ago? I just wanted to get a sense.

Well, everything that Tom gave you was as of the second quarter. And our outlook, of course, is based on what we see here today and on a go-forward basis. But all the other pieces -- most of the time -- he gave you the specific date that he was giving a forward number.

Okay. And, Tom, as you mentioned, so Edison Capital, you have this portfolio which you monetize over the next two or three years. Could you update us on the plan to invest into wind assets going forward, where you are in terms of that deployment?

Yes. The plan continues as we had outlined it. The expectation was that we would invest something in the order of $250 million a year going forward. Current -- the Energy Bill and the extension of the Production Tax Credit by two years was a positive event for us, and we continued with a very active program working with wind developers and existing sponsors to expand our portfolio. And so, the first step, which was important, was to get the Energy Bill through and get the PTCs extended. And so we would expect through the remainder of this year and into next year to begin to enter into firm contracts and to expand our portfolio as we had intended.

Okay. Thank you very much.

Our next question is from Brian Taddeo with The Bank of New York. Go ahead, please.

Good morning, everyone. Two quick things. First, I was wondering if you could give us an update with regards to your fuel hedges at MEHC, over the next couple of years what percent is hedged, and pricing, if available? And the second question is with regards to could you give us an update of your thoughts right now with regard to the large cash balance at MEHC, and if there's any new initiatives you can talk about with regard to what you're going to use the cash for?

I mean we had provided in the Q as of the end of the second quarter what the coal hedging position is -- and I'm just trying to get to that right now. Okay. And I've got it. For 2005, for the balance of the year, it's 110% for the Illinois plants, and 105% for Homer City, and that is higher than -- it's really higher than 100% because of our lower expected production. And then through 2006 at 98% for the Illinois plants and 53% for Homer City, and we've extended that on out through 2009, but I would just refer you to the Q.

Okay. And the second question with regards to cash?

On cash it's really the same answer. We've got three areas that we're focusing on, first, in terms of further debt reduction. Second, to make sure that we have adequate collateral to back stop, longer term our hedging program, and longer term contracting. And then third, to look to a higher yielding opportunities for investment in new plants for growth. And we continue to evaluate the relative benefits of deploying our cash in each of those -- into each of those areas. So really no change over what we've said earlier.

Do you see any reasons that look particularly attractive to you in terms of purchasing some new plants or bonusing new plants outside of California?

Well, we continue to look at a whole host of opportunities out there in terms of existing assets or the possibility for new assets, and then in addition to that, the California market. So we can't be specific, but we are in that business.

Okay. Thank you very much.

Our next question is from Paul Fremont with Jefferies. Go ahead, please.

Thank you very much. Just to sort of go back to the megawatt hour volume, can you just remind us again the numbers on Midwest Gen you were originally projecting for the full year 2005 34 million MWh, and the revised number for the full year is what?

30.8.

I'm sorry, what?

30.8.

30.8. And essentially if the lower level of production is not in any -- is basically not related to coal supply interruptions, would it be reasonable to assume that your original projections of capacity utilization sort of in that 70% range are aggressive based on the amount of demand, and based on the way that the -- those plants are dispatching, particularly in the overnight and in the off-peak periods?

Yes, it's -- Paul, it is Ted. It's really the off-peak periods where we're seeing less demand. I think you probably know some of this, but just to repeat it. Particularly in the Midwest area, because of the nuclear plants and all plants really being available for on-peak periods, they usually are not dispatched in the off-peak periods to turn them off. They keep them on so that they're available for the peak periods, and so that's really causing less production from our plants on or less dispatched from our plants in the off-peak periods. So all of the change is really occuring in the off-peak periods, not the on-peak periods.

So on a longer term basis conceptually the only way that that dispatch pattern is going to change is if there's basically a material alteration in the demand pattern in the region? In other words, demand in general goes up and, obviously, the need to sort of switch from nuclear to coal during those off-peak periods becomes a function of that increased off-peak demand?

I would say that's largely correct.

The second question that have is on Kern River, there was supposed to be a repricing of that contract, I think, on August 1, has that actually occurred? And can you make any comments as to whether the revised -- how the revised pricing compares to the original pricing?

We are in discussions, actually it's our partners in discussions. We are not aloud to be at the table for the power sold to Southern California Edison. We expect in the very near future to announce the results of those contract negotiations, but we are highly confident that it will be contracted going forward.

Okay, so that still -- that hasn't actually happened, that's still being discussed?

We are being paid for the power currently, and the final details will be worked out imminently.

And then just one other item as a housekeeping matter. The $0.04 gain that you recognized in Edison Capital, there's an offsetting charge at MEHC this quarter that's roughly $0.05, that could be also viewed as nonrecurring as a charge for early debt retirement?

Correct.

Okay. So it's sort of the nonrecurring-type things roughly offset each other?

Yes, Paul, to clarify that was in the first quarter on the debt retirement costs. So that was the takeout of the MIPs and then payoff -- the early payoff of the term loan.

At MEHC?

That was at MEHC.

Occurred in the first quarter?

It occurred in the first quarter that we had those charges.

Okay. Because in your 10-Q, I guess, on page 69, it says, "MEHC's second quarter results in 2005 include a 15 million or $0.05 per share charge related to the early retirement of debt."

I'll have to look there, but it did occur in the first quarter. There were some additional debt reduction in the second quarter related to Midwest Gen when we restructured the term loan and reduced it by 300 million.

We're looking now. That should have been in the year-to-date review. We'll double-check that.

Thank you.

Next question.

Our next question is from Greg Schultz with SAB Capital.

Hi. I wasn't really clear on the Holdco cost, want sort of caused that to go up, and how we should think about that going forward? I guess there's no debt at Holdco, and there's -- I guess there's just a little bit of operating expense. Why wouldn't that sort of trend down to the quota, sort of under $0.05 level at some point?

Yes, the Holdco, really the major reason for that increase, as we discussed, centered around higher taxes and compensation expense. A lot of that related to incentive programs that -- stock-based incentive programs. So you might look at it kind of in two ways. One, it would be nice to see that continue, but it really was tied to the affects of our stock price movement.

I got it. I understand. Okay. So those were inflated this year? I mean, unless your stock goes up 30% again?

Yes.

Okay. I understand Thank you. And on MEHC, just a couple of quick questions. Could you refresh my memory on how much coal you're going to use this year?

In the disclosures, it says between 18 and 20 are the range [multiple speakers] at Midwest Gen. And then there's five at Homer City, and that is what we've previously shown you. And it's in the disclosures too.

Gotcha. Okay. And I noticed reading the queue there was some CapEx disclosures. They look very low. Maybe I read it wrong. Are you still on track to do -- I think when you gave your big presentation on October you gave a little guidance on CapEx at Midwest Gen, and at Homer City. Are those still -- are those numbers still good, or have they come down a lot?

No, they're still good and it's really a timing difference, and then, of course, the big CapEx is around unit one and two scrubbers at Homer City, and that's been in our disclosures for some time

Okay, good. Thanks.

Our next question is from Kit Konolige with Morgan Stanley. Go ahead, please.

Thanks. Good morning.

In good morning, Kit.

It looks to me that there's more hedging of '06 at this stage roughly in the 30 to 40% range that you've sold forward already that would be higher, I think, than would have been the case a year ago at this time. Is that a correct perception?

Yes, Kit. That's true.

Okay. And is that cost -- I mean, what sort of effects -- I assume -- I'll make my own assumption that those are pretty good prices you're seeing obviously and you want to take advantage of those. What does that do to your collateral situation?

Let me have Jim kind of cover that.

Kit, how are you doing? Of course, as you do hedge, and you set in prices and prices move upwards, we are seeing some cash being used for margining purposes. And I think the number, as of June 30th was about $100 million that we have in deposit with our various brokers we use to clear our trades. So that's just a fact of prices moving higher and then the volumes of hedging activity that we've done.

So your -- so it's 100 million cash out as an effect of the margin, the change in the price is upward since you put the hedges into place?

That's correct.

Okay.

And obviously that cash would come back to us as you would conclude the trade. So it's going to go up and down depending upon what happens to the price and the duration of the trade.

Right. And then I guess in the past it seems to me that you guys have talked about significantly larger numbers than 100 million as being used for collateral as --?

Of course, we have lines of credit in place at both Midwest Gen and EME. We have got $500 million in blinds at Midwest Gen, and 98 at EME, plus our cash balances. And so it really depends on -- we're quoting things as of June 30th, and so it can affect by -- what we've done in the third quarter that we will not comment on until the third quarter.

Yes, Kit, this is Ted. I think where you're trying to go there, we have used numbers in the neighborhood of that 95 and 97% competence levels. We'll be up to perhaps as much as 400 million. That's based on having all of the next year hedges in place up to 50% of our expected production. So if we had all of 2006 hedged at the 50% level, and then we had a price movement on that full calendar strip 2006 hedge position in the 95 to 97% competence level, that's what gave rise to those numbers of around 400 million. So obviously we don't have 50% hedged at this point, and we haven't had that kind of a price movement since we put the hedges in.

Right. So you say 50%? It seems to me -- maybe I'm thinking of something different, that you used to talk about putting -- the hedging 65% of your expected production?

Well, that was based on the 50% hedged.

50% hedged. Okay, fair enough.

Ted, you may be thinking of the Homer City numbers. No, Ted does not think so.

And then just one final area. On SO2, on balance, is it fair to conclude that the higher SO2 prices go, that that's a negative for you overall, that Homer City uses more than are produced or available at Midwest Gen?

Yes, we typically really have not been very specific on that point, because that's a market that we actively participate in. It's really not wise for us to go into all of the details of our specific position. But directionally, you're correct.

And then just to follow-up on that, finally, it seems to me a number of other companies have accelerated their capital spending for scrubbers precisely because of their exposure to the SO2s, and have you looked at putting those scrubbers on sooner, or are they moving as quickly as they can at this point, or --?

We're still staying with the concept that we would put on scrubbers on unit one and two at Homer City. We are actively involved in the preparatory work around that. It really isn't anything different than what we always had planned, which was to move forward on that. I don't think it's really going to -- there's not a lot you can do to change the timing on it.

Right. And when would those operational?

Well, the work would start in -- principally in '07, and they would come online -- really, basically, in the 2008 period. There is a little -- they're not phased to come in exactly the same time for the two units. But basically around '08.

Okay. Thank you.

Our next question is from David Grumhaus with Copia Capital. Go ahead, please.

Good morning. Congrats on a nice quarter. Just wanted to check with you -- check in and see if I could get a little more guidance on the FAS 109 issue, and obviously the draft is out there. If that comes to fruition what is sort of the ongoing exposure -- of the ongoing earnings exposure might be?

Right now we're analyzing the draft. At this time we don't expect any significant increase in our contingent liability, so we expect no negative earnings impact. There is, however, the possibility that certain reserve amounts currently carried on our books may be reversed and certain tax contingent income items could be recognized, resulting actually in a net earnings benefit. But overall, we don't see any significant increase in contingent liabilities, or any -- or no negative earnings impact from it.

Okay. Great. Thanks for the time.

Our next question is from Jonathan Arnold with Merrill Lynch. Go ahead, please.

Yes. Good morning. Could you just maybe specify a little more on the reduced production, particularly at Midwest Gen? How much of that is due to the higher maintenance you had in the second quarter? And how much of the annual reduction is due to a reduced outlook for the full year -- for the second half?

As we said in the opening comments, it's really a bit of a contribution from both sides. We haven't really tried to break out specifically how much is due to higher forced outages than expected, or how much is due to just the way that the plants are being dispatched. But both of those are contributing factors.

But in terms of the timing, how much below your production estimate for the second quarter did you come in?

We -- I think this is maybe one that would be probably better to take this up afterwards. [multiple speakers]. I don't know that we've given it by the quarters as opposed to just giving an update for the year.

Okay. Thanks.

Our next question is from Devin Geoghegan with Zimmer Lucas Partners. Go ahead, please.

Hi, thanks for the time today. You guys gave the disclosure on that percentage of coal hedged in the 10-Qs. I was wondering if you have the associated total dollars by year? Just so I can try and back into some close dollar per ton number.

No, we don't. And we would update that in connection with putting out our updated long-term forecast.

Also, similarly, with the transportation you guys have also given similar numbers, but the difference is you haven't given the percentage of transportation tons that are hedged. Is it -- have you hedged identically with the coal hedges, or is it something less?

We have given that in the past. In the case of our Illinois plants, which use the Powder River Basin coal, we have long-term coal rail contracts which extend out to 2011. So as you look at that 10-Q, updated 10-Q disclosure, that would make it pretty clear that we have the transportation which represents about 60% of the total cost at the burner tip already under contract on fixed prices, yet the amount of coal that we've actually purchased varies by each of those years. So transportation is fully covered. The coal pieces varies by the different years.

The reason I asked is because it looked like when the 10-Q says, "year-to-date we have increased the dollars associated with those transportation hedges by a significant amount in some of those years," that made me think that you were putting those hedges on recently.

I don't know what that is that you're referring to, but they're nailed down.

Okay. And the last question is in terms of the dispatch of the plants, are you guys -- seems like you guys are obviously, running mostly on-peak, are you shutting the plants down off-peak so that if we're like putting in around the clock price into the model, it seems like that's too low of a price to use if you're really dispatching mostly on-peak?

Yes, these plants really vary plant-by-plant, but a general rule in terms of how they're being dispatched is they're running pretty much full out on peak, and then they're turned down to what we refer to as "minimum load" on off-peak. Again, this varies a lot, but they're not being turned on and off. You can't turn them off. It's too hard to get them started pack up again.

But the contract; I see what you're saying.

So it goes from min-load to max-load depending on whether it's off-peak or on-peak.

Do you have any rule of thumb for what kind of capacity factor that would be in a min-load? Could you rev it down to like 50% of total output or --?

It, again, it really depends on the unit. They're all different. So I really wouldn't be able to give you a basic answer on that.

Okay. And the contracts you signed, but those are around the clock contracts, not on peak, right?

It depends.

Okay. All right. Thank you very much.

All right, maybe we're at the point where we ought to take one more question.

Our final question is from Brooke Glenn-Mullin with JPMorgan. Go ahead, please.

Yes, good morning. I have two questions on the revised outlook for the utility. First, what is your assumed tax rate, and, also, based on the $1.80 level, what hourly rate would you expect to earn in 2005?

I don't have the effective tax rate that we're assuming in our forecast. I imagine it's in the 40% range. We can look at that and provide that afterwards, I assume. The rate of return, overall, the utility will probably be earning just about in the 11 to 11.5% range based on the new forecast of $1.80.

Okay. Could you give us a sense what the tax balance -- the amount of the tax benefit in the quarter was?

In the specific quarter, let me just take a look at that. The quarter was $0.04 and primarily that relates to two issues, it relates to resolution of issues in ongoing tax audits we have, and also related to tax benefits that we receive on our construction program related to cost of removal and repair allowance.

Okay. And just lastly, have you guys taken any cash reserves against the outstanding LILO and SILO tax issues?

We really don't comment on our reserve positions, against any specific contingencies. But I think in our -- in the comment that Tom Noonan talked about is how we would view the impact of FAS 109 if it were to be implemented, I think that gives you some indication of what our feeling is there.

I guess I just wasn't clear between whether you've taken book reserves or cash reserves?

We never specifically take cash reserves. We only take book reserves. In other words, our cash is either invested or used for operations, so I don't know of many companies or any companies that really actually take -- put away cash as a reserve for these items.

Okay. Great. Thank you very much.

All right. Well we thank you all for participating in the call. You have the queue and we would be pleased to have your questions that come into our departments for this purpose. Please direct them through our Investor Relations Department. All right. That concludes the call.

Thank you