第一能源 (FE) 2008 Q2 法說會逐字稿

Good afternoon. I will be your conference operator today. At this time, I would like to welcome everyone to the FirstEnergy Corp. second quarter 2008 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (OPERATOR INSTRUCTIONS) Thank you. It is now my pleasure to turn the floor over to your host, Irene Prezelj, Manager of Investor Relations. Ma'am, you may begin.

Thanks. During this conference call, we'll make various forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of FirstEnergy Corp. are based on current expectations that are subject to risks and uncertainties. A number of factors could cause actual results or outcomes to differ materially from those indicated by such forward-looking statements.

Please read the Safe Harbor statement contained in the consolidated report to the financial community, which was released earlier today and is also available on our website under the earnings release link. Reconciliations to GAAP for the non-GAAP earnings measures we will be referring to today are also contained in that report as well as on the investor information section on our website at www.firstenergycorp.com\IR.

Participating in today's call are Tony Alexander, President and Chief Executive Officer; Rich Marsh, Senior Vice President and Chief Financial Officer; Harvey Wagner, Vice President and Controller; Jim Pearson, Vice President and Treasurer; and Ron Seeholzer, Vice President of Investor Relations. I'll now turn the call over to Rich.

Thank you, Irene. Good afternoon, everyone. Thanks for being with us. I have a full agenda for you. I will start by providing an overview of our second quarter financial results then Tony Alexander will discuss the filing we made yesterday with the Public Utilities Commission of Ohio regarding both an electric security plan and a market rate offer. As I review our second quarter results, you may want to refer to the consolidated report to the investment community that we issued this morning. Okay. Let's go ahead and get started with our results.

Earnings on a GAAP basis in the second quarter were $0.86 per share compared to $1.11 per share in the same period last year. The quarterly earnings guidance we provided for 2008 anticipated that results for the second quarter would be below those of the prior year since a greater proportion of our annual earnings is expected to be generated in the second half of the year, compared to 2007. Excluding special items, normalized non-GAAP earnings were $0.87 per share, compared to $1.13 per share in the second quarter of 2007. This year's normalized non-GAAP earnings exclude the effect of a $0.03 per share gain from a claims settlement related to a previously sold International asset as well as a $0.04 per share loss related to the impairment of securities held in our nuclear decommissioning trust.

Positive drivers of this quarters comparative results included an $0.08 per share increase in generation revenues primarily driven by higher wholesale and retail unit prices, more than offsetting a 6% decrease in total electric generation sales. A $0.04 per share decrease in financing costs, reflecting lower interest rates on both short-term and long-term variable rate borrowings. A $0.02 per share increase due to lower nuclear operating expenses and a $0.01 per share reduction in pension expense.

Our results were adversely impacted by unusually mild weather through much of the quarter. Heating degree days were almost 7% below the level of the prior year while cooling degree days were down almost 11%. Overall, the weather contributed to a $0.05 per share decrease in distribution delivery revenues as kilowatt hour deliveries declined by 2% compared to the same period last year. Residential deliveries accounted for the majority of that change. Deliveries to the industrial class were down less than 0.5% from the second quarter of the prior year. Usage by our steel and refining customers grew while deliveries to our automotive manufacturers declined.

In addition to the weather, increases in fuel and purchase power expenses reduced earnings by a combined $0.23 per share versus the prior year. Fuel costs reduced earnings by $0.03 per share and were largely driven by transportation surcharges resulting from the sharp increase in diesel fuel prices. The total volume of our power purchases in the second quarter across our service territory with little changed from the prior year has increased purchases in PJM, offset lower purchases in MISO. Our purchases in PJM included replacement power for the scheduled Beaver Valley 2 refueling out and for increased customer loads due to a brief but intense hot spell in early June.

We had a heavy maintenance schedule at our fossil units during the period that included a 57-day outage at our 830 megawatt Mansfield unit 1 for generator rewind and boiler work. Although our overall loads during the quarter were reduced due to mild weather, when combined with these planned maintenance outages, our total purchase power needs were about the same as in the prior year. The average unit price of the power we purchased during the quarter increased 25%, however. And adversely impacted earnings by $0.20 per share. Contributing factor was spot purchases to meet customer loads, particularly in PJM during the warm spell at the beginning of June when power prices exceeded $100 per megawatt hour. A number of generation units through MISO and PJM were down for maintenance activities during this period including some of our own.

Other factors that reduced earnings on a comparative basis included a $0.06 per share increase in fossil generation O&M expense due to the increased number of planned outages. A $0.02 per share increase in depreciation expense due to incremental property additions and a $0.04 per share decrease in investment income from our corporate-owned life insurance portfolio compared to the prior year. This was driven by capital market conditions during the period. The equity markets, as measured by the S&P 500, experienced a strong second quarter in 2007 posting a gain of almost 6%. This year's second quarter was a different story, however. And the index recorded a loss of over 3% in that period.

Due to the conditions I discussed, our results in the second quarter fell below the quarterly guidance we provided at the beginning of the year. For the first six months of 2008, however, our normalized non-GAAP earnings were $1.75 falling squarely in our previously-announced guidance range for that period. Having achieved that performance, despite the weather and other challenges, we believe that results during the remainder of the year replaces in the top half of our original annual earnings guidance range and so today, we're revising our non-GAAP earnings guidance for the year from $4.15 to $4.35 to $4.25 to $4.35. We anticipate that about 56% of the earnings in the second half of the year will fall in the third quarter with 44% in the final quarter. We remain on track to make 2008 another solid year for FirstEnergy.

I would like to take a few minutes to comment on our portfolio and the Bull Mountain mine transaction that we recently announced. Like all fossil generators, we've tracked the increase in coal prices over the past year or so. We've also seen transportation surcharges rise rapidly along with the price of diesel fuel. Which has gone from about $2.90 per gallon last summer to about $4.70 currently. Our practice of securing long-term contracts for coal is intended to provide a high degree of supply assurance and our contract pricing typically results in costs that lag the market in a rising cost environment. Our supply positions are hedged through 2011 and we have coal transportation contracts in place to cover more than 90% of the tons we expect to burn over the next five years. We believe these strategies position us well relative to other generators. Even so, we expect an increase of about $200 million in total fuel costs in 2008 versus 2007 roughly 55% of which will be collected due to the Ohio fuel rider this year. Most of this increase was driven by the terms of new three-year western coal transportation contracts that took effect in 2008 and the impact of rising coal transportation surcharges.

We expect to see a similar overall increase in total fuel costs in 2009 due primarily to the terms of several eastern coal contracts as well as increases in other fossil, noncoal fuel costs and nuclear fuel expense. These continued changes in the coal markets provide additional incentives for us to look at new and more creative ways to manage our fuel portfolio. And that was one factor that led to our recent investment, the Bull Mountain coal mine in Montana.

In mid July, we entered into a joint venture to acquire an 80% interest in this facility. Our total equity investment will be $125 million and we'll own a 45% interest in the joint venture that was formed with an affiliate of the [Boyche] Companies. Both parties to the joint venture will have a 50% voting interest. At the same time, we entered into a 15-year agreement to purchase 10 million tons of coal annually from the mine with delivery beginning as early as the end of 2009. While the delivered coal is expected to be similar to PRB, I'm sorry, while the delivered cost of this coal is expected to be similar to PRB, the 10,300 BTU of energy content of the Bull Mountain coal will allow us to avoid D rates totaling more than 170 megawatts at our coal generating units. The additional generation, we expect to gain through the use of the Bull Mountain coal makes this the most significant of our asset mining initiatives. Because it will generate the additional megawatts without additional SO2 admissions, it is environmentally advantageous as well.

The arrangement also gives us the opportunity to sell any coal that we don't burn at our own facilities. The Bull Mountain transaction is a valuable and strategic addition to our fuel portfolio. It provides a long-term supply of higher BTU coal for more than one-third of our projected annual coal needs at very favorable prices. And we're glad that we're able to take advantage of this opportunity.

Before we move on to Tony, let me briefly mention that EPAs clean air interstate rule and the ruling by the D.C. circuit court of appeals on July 11, that vacated that regulation. We continue to evaluate the court's decision and currently believe we have no material impairment issues regarding our SO2 or annual NOX emission allowances. Although no one can be sure exactly what path this issue will follow in the coming months, we'll continue to monitor the situation and any impact it might have on our Company. I'll now turn the call over to Tony for his comments regarding our ESP and MRO filings.

Thanks, Rich. And good afternoon, everyone. As you know, yesterday we filed both our electric security plan and a market rate offer with the PUCO. These proposals outline our approach for meeting the requirements of amended substitute Senate Bill 221 for our three Ohio delivery companies and offer a constructive path toward a competitive generation market. We look forward to completing the regulatory process in a manner that will positively position FirstEnergy for the future. Additional details about the filings are contained in our letter to the investment community that was released yesterday afternoon. Links to the letter and a copy of the complete filing can be found on our website.

We believe that the ESP which we designed as required by Senate Bill 221 to be more favorable in aggregate for customers in the MRO, provides a comprehensive solution for the needs of our Ohio customers. To manage the overall rate increases for our customers, the ESP provides an annual phase-in credit of 10% or more on generation service and also results in a stage recovery of the deferrals created by the plan. We also offer securitization as an option for collection of the deferrals. Under the ESP, our unregulated subsidiary, FirstEnergy Solutions, would provide generation service to our Ohio delivery companies for the duration of the plan which is three years with the commission option to end the plan after two years. The delivery companies would have the ability to recover certain cost increases such as fuel transportation surcharges as well as other costs including renewable energy requirements in excess of those in the existing legislation, new environmental requirements or taxes in excess of $50 million. The plan would also permit the delivery companies to recover 2011 incremental fuel costs above the 2010 level.

In addition to the generation provisions, the plan also addresses the distribution rate case filed last year and the deferred fuel cost recovery issues pending before the PUCO. Base distribution rates across the three Ohio delivery companies would increase $150 million as a result and we would also implement a delivery service improvement charge to support our efforts to further improve customer service and reliability. To achieve more uniform customer pricing across our three Ohio delivery companies, we proposed as part of the ESP to waive collection of the regulatory transition charge or RTC starting in 2009 that would otherwise be collected from the Cleveland electric illuminating customers through the end of 2010. If the plan is approved, CEI would write off the unrecovered costs being collected through the RTC. This write-off would total approximately $485 million and is expected to reduce 2008 earnings by about $1 per share. We would consider this a special item that would be normalized for earnings guidance purposes. Finally, the ESP continues our strong commitment to energy efficiency, economic development, and delivery infrastructure capital investments over the next several years.

Now if the ESP is not approved, we're prepared to immediately implement the market rate offer or MRO. Under the market rate offer, our delivery companies would procure generation supply through a competitive bidding process, an independent third party would conduct the bidding process with oversight by the commission. Any interested wholesale supplier including FirstEnergy Solutions could bid on slices of the three company system load under a descending plot format. The initial competitive bidding process will set rates beginning in 2009 and use a staggered bid where one-third of the total load of all three companies will be bid for supply through May 31, of 2010, one-third of the total load will be bid for supply through May 31, 2011. And one-third of the total supply of the total load, excuse me, will be bid for supply through may 31, 2012. After the conclusion of the initial solicitation, each of the delivery periods will align with the MISO planning year.

Beginning in 2009 and during each calendar year thereafter, the delivery companies will conduct two competitive solicitations which combined will apply one-third of the total load of all three companies for a three-year period. The MRO incorporates a reconciliation mechanism to ensure that the delivery companies don't over or undercollect for generation service thereby ensuring a mutual financial outcome for the companies. Senate Bill 221 requires the PUCO to issue a decision on the MRO by the end of October. The MRO option is approved and implemented. We expect that the initial solicitation would take place following final PUCO approval so the new rates could be effective on January 1, 2009.

This time line is important as the FERC approved contract between the delivery companies and FirstEnergy solutions expires on December 31, 2008. The ESP also includes a contingency plan called the severable short-term ESP. The timing of either the ESP or MRO approval does not allow for implementation of new rates by January 1. We are looking for PUCO approval of the short term ESP on or before November 14, 2008, after which time the option would be withdrawn if not approved. If approved, a temporary generation rate of $0.0775 per kilowatt hour would be put in place and would provide the PUCO with additional time until March 5, 2009, to act on the full ESP. If no action is taken by that date, however, or if the commission rejects the longer term ESP, the delivery companies will proceed with the competitive bid under the MRO with a procurement auction sometime in early April. This will allow generation supply into the MRO to begin on May 1, of next year.

We believe that either the ESP or MRO will position FirstEnergy for success and I'm hopeful we'll be able to work through the commission approval process well in advance of January 1, although there is a lot of work to be done. Finally, it is important to note that we believe yesterday's filing meets not only the letter but also the full spirit of the new law. ESP is a good plan for our Company and a good plan for our customers. We're prepared to pursue the MRO path if necessary. We look forward to a positive PUCO outcome during the fourth quarter.

Let me conclude by affirming our commitment to exceeding the expectations we've established for ourselves. We've tightened our earnings guidance range for 2008. We continue to manage the transition to competitive generation markets in Ohio in 2009 and Pennsylvania in 2011. We're well-positioned for continued earnings growth and as always, remain committed to superior execution in our daily operations. Thanks for your interest in FirstEnergy. Now, I'll turn it over to the operator for your questions.

Thank you. (OPERATOR INSTRUCTIONS) Your first comes from Greg Gordon of Citi.

Thanks. First on the earnings for the second quarter and balance of the year, if we adjust for weather, and if your plants had not been down for maintenance, how far above the high end of the guidance range would we be for the year on a normalized for those two events? Clearly, you're still hitting the high end of the range even with those setbacks.

Greg, it has always been our policy not to attempt to normalize for weather impacts. Since we don't do that, I don't know what the numbers are. But you're correct. Those were factors that really did shape events during the second quarter. I know some other companies do normalize weather and other events but that's just been our practice.

I'm not presuming to say that you actually did earn more money. All I'm trying to say is if we hadn't had the weather events on a normalized weather basis, you would have been well ahead of your guidance for the year, is that fair?

I think that's a fair statement overall, yes.

And then when I look at the filing you made in the letter that you made available to -- the documents you made available via e-mail, you show a base generation rate for 2008 of $0.068 going to $0.075 in '09 and going up to $0.08 to $0.085. Can you tell me what's in that base of $0.068?

The basic G price, Greg, includes energy and capacity except for some certain planning reserve requirements includes line losses and it includes renewable requirements under Senate Bill 221. What it excludes would be transmission, that planning reserve capacity charge I mentioned and certain increased fuel costs.

So it does exclude transmission?

It excludes transmission, yes.

Okay, thank you.

Thanks, Greg.

Your next question comes from Jonathan Arnold of Merrill Lynch.

Good afternoon.

Hi, Jonathan, how are you?

Good, thanks. Just, a quick one on the -- on the next steps with the review and the PUCO. How much visibility do you have on the proceeding? And what we'll be looking out for as the next sort of road map, way marker?

Well, at this point, we don't have a procedural schedule that I know of. So, we will be waiting on the commission to take action, begin to set a procedural schedule and go from that point.

But it would be the normal of hearings, you've submitted them and staff will comment on hearings, et cetera, as far as you know?

We would anticipate hearings. I don't know whether or not there will be a staff report in the kind of traditional sense of a full-scale rate case or not. I just -- I'm just not familiar enough with the process that the staff and the commission intends to go through but I do anticipate that there will be hearings.

If I could ask a second one just on the -- you have the third year of the plan being at the PUC's option, what happens if they choose not to execute that option? And then sort of beyond that, are there any provisions within the plan as to how things work after the plan finishes?

Yes, there is very detailed provisions inside the plan with respect to what continues, what drops off and how do you proceed under a number of different scenarios including that one.

We should be able to find that within the documents somewhere.

Yes.

Any high level summary you can give us on that, Tony?

You don't want to go through the full thousand pages, Jonathan?

Well, it may take us some of the afternoon.

My sense is you really need to take a look at it because depending on what question you have, the team spent a lot of time identifying how this thing will proceed. If it goes through the full term because remember, the distribution rate freeze runs through 2013, I believe. So, there are terms that continue beyond the three year of the generation part piece of the plan. And there's been a lot of time and thought given to each one of the potential scenarios, what comes on and what comes off and what's affected by commission's decisions.

Is there one piece of testimony in particular you would recommend we look at on that subject? Or is it sort of dotted around the filing?

I think it spread across several layers of testimony, Jonathan.

The simplest way, Jonathan, is Ron Seeholzer. There is an application both for ESP and MRO, 40 some pages in the front end. If you're trying to get through both of those initially, you'll get an awful lot of the background.

Thank you.

Thank you. Your next question comes from Greg Oro of Lehman Brothers.

Thanks a lot.

Hi, Greg.

Hi. Question on the securitization proposal. I assume that, a key issue is whether -- in getting it approved is whether it's cheaper cost versus the deferring recover scenario. And that gets back to making it a lower cost of borrowing for someone through legislative backing or the agencies. What's the latest thinking on that?

First, let me just comment, Greg. I mean in the proposal we made yesterday, we're not asking authority to securitize what we're doing is laying out a framework for the commission's proposal in terms of securitization to consider. So, if we go that route, we would have separate applications to actually gain the authority to securitize. We laid out a mechanism but as I would say, probably conventional or traditional with what you've seen in other states as far as how the securitization mechanism would work. There is an attachment A in the filings that runs you through the various steps of that, I won't go through that now. I would call it a relatively conventional securitization transaction.

You're right though. We have two options to recover the costs. One would be securitization with bonds, with a final maturity not to exceed ten years. Second option is a recovery mechanism also not to exceed ten years where we would earn a carrying charge on those deferrals with an annual rate of approximately 8.5% during the period those expenses are being deferred then we would, once the recovery started, we would earn the long-term debt to the individual companies. That's kind of weighing out the two options. We wanted to put that out for the commission's considerations. Then we'll go from there after they've had a chance to look at that.

Okay. Thanks.

Thank you.

Thank you. Your next question comes from Dan Eggers of Credit Suisse.

Just looking at the targeted rate increases at about 5% a year, how much -- do the add or rescind some of the deferral accounting does that show up in that 5% rate increase or would that number look a little higher once everything gets layered in?

Those increases do not include the impact of the riders, Dan. It is not possible to know if those will be triggered and if so, how much the increase would be. So, they are not included.

Okay. And then writing off the RTC would be a taxable event, I assume so there would be a tax benefit back to FirstEnergy in 2008 based on that?

There would be no cash tax benefit. What would happen is that we would not receive the revenue and be taxed on the revenue.

So, there's not a cash tax benefit.

That's correct. The writeoff, Dan, as you know, is about $485 million. So, that would be an impact to earnings of about $1.01 in 2008.

Okay. Then lastly, the $1 billion of commitment on the transmission and distribution spending, that looks pretty consistent with existing CapEx plans, is that correct? Or is there something incremental that you guys are going to spend on the utilities part of the plan?

I think your presumption is correct. The exact number is about -- for our three Ohio distribution companies, it is about $265 million, to that order. I think you're right, Dan.

Thank you.

Thank you.

Thank you. Your next question comes from Ashar Khan of SAC Capital.

Hi, good afternoon and congrats. If I understand, Rich, by taking this write-off of this plans as assumed in 2008, we will have no longer any amortizations relating to CEI going forward hence the drop-off of like 225 or so, I forget the precise number that was to happen in '11. It will all happen now in '09 along with the drop-off in amortization for the remaining two Ohio companies?

Correct.

Is that my understanding? Correct. So, we could have nearly $1 in earnings just from the drop-off and the amortizations from all the three companies which will now happen simultaneously, on January 1, 2009?

Your theory is correct, without opining on your number, but yes, it is correct, Ashar.

Okay. Second, I wanted to go over was you mentioned that the 68 includes, I guess, the embedded cost of generation plus the costs related to some of the green initiatives in the filing, is that correct?

You're talking about the net customer generation charge?

Yes, for 2008.

Yes, it includes -- oh for '08. It has the RTC in it.

It's got the RTC in it.

Right.

The way I was trying to understand is as we look at -- the earnings potential, should we be subtracting 75 minus 68 and taking the volume on the revenue line? Is that enhanced revenue coming to the Company from an earnings perspective? I know there is a deferral attached to it. But is that the right way to do our modeling?

I would say it is the right way, yes.

Third, Rich, if I can end up it with I got confused with your -- you mentioned that fuel costs are going to be higher again in '09 versus '08. I know that in this plan, you've asked for recovery of certain transportation costs related to the fuel if they exceed a certain amount.

Right.

Could you tell us out of that increase, if you could repeat how much increase you're expecting from '09 to '08 and how much of that will be absorbed by this transportation rider that you have? Would have in this filing?

What I said in my comments, Ashar, that we would expect the increase in total fuel costs next year to be about the same as the increase we're seeing in 2008 versus 2007. I mentioned that was about $200 million increase. A lot of that increase in 2009 versus 2008 is being driven by changes in several of our eastern coal contracts. And changes we're seeing in some of the other fossil, noncoal items and nuclear fuel ex-pence. I think in Tony's comments, he had mentioned about some of the coal transportation surcharges over a certain amount that we would be eligible to recover getting into the years of the plan. The amount is -- the threshold is the highest in 2009. We don't know whether that would be triggered or not in 2009.

You don't know whether that's triggered or not under this filing.

It depends on basically what our fuel transportation costs do over that time frame.

If I can end up, the distribution rider if I do my math correctly which is 0.002 is an additional $100 million in revenue, is that correct?

You're talking about the delivery service improvement rider?

That's correct.

That's how much it is, yes. Plus or minus 15% based on our achievement of delivery service reliability goals.

But you said that, the CapEx and the O&M and everything, the CapEx isn't going to change because of this. So, just means I guess how you come up under certain statistics which you will reach an agreement with the commission and they will monitor it and you get -- I'm trying to see how does it get in? Is it just automatic?

No, it's not automatic. We'll have various measures of our performance, our duration, frequency and outage frequency and duration and so the commission will track our performance relative to those goals and adjust them up or down.

The two mills is included in rates and then is adjustable upward or downward depending on the performance of our system basically from a reliability standpoint.

Okay. So, we get this $100 million additional and then there will be a plus or minus attached to it based on how we perform. Is that correct?

Yes.

Okay. And then, sorry, I made a lot of -- then for 2010, is there another foul jump in 2010 or are we pretty flat -- you know, because you said you had a lot of contracts set and everything. Is the '09 to '10 movement, is that more levelized on the fuel basis?

We haven't talked about 2010 yet, Ashar.

Okay. Okay. Thank you very, very much. Congrats.

Ashar?

Yes.

Ron Seeholzer, I just wanted to -- the $68 that you were trying to do the comparison with, I wanted to take just a second. It is not an average annual rate that's indicated there. Those are the average rates that are likely to be in place at the end of the year, 2008. They're slightly higher for two reasons. Number one, we've adjusted a tariff rider during the year and we have a higher effective fuel recovery rider in the second half of the year than we would have had in the first part of the year. It has been adjusted during the year. It may look slightly higher than we talked about but it is not an annual average number that we were addressing to $68.

So, the average number would probably be lower.

Correct. Because that's a comparison of end of year rates 2008 to our projected 2009 to make that percentage jump. Does that make sense?

It makes sense. Thank you, sir.

your next question comes from Paul Fremont of Jefferies & Co.

Thank you. I guess I noticed as part of your second quarter press release that you guys have repurchased about 259 megawatts of your nuclear leases. Are you able to indicate at what price you made those purchases?

No. But I think they were attractive. Not in terms of specific prices.

Will that end up being -- at some point will that be disclosed to any type of a public filing or is that not going to be covered at some point in the future under a filing?

I don't believe the specific pricing will be, Paul. This initiative that we undertook to buy these leases back is consistent with our long-term view of just trying to get rid of some of these future risks. In this case, being end of lease for market value risk. So, we were able to take advantage of some opportunities to do that. Get this in. It was done in a manner that was reasonable and we're glad to get that behind us. It is just another thing that takes a risk down the road off the table for us and just makes the path that much clearer as we move down the road.

Paul, this is Harvey Wagner. One of the disclosures we have in our financial statement is a consolidating balance sheet for FirstEnergy Solutions that includes their two generating companies and I think you could review the changes in those balance sheets and develop some kind of estimates of that.

And the Ohio Edison purchases, those, I assume, were voluntary since it was only Toledo Edison where you had sort of the ability to trigger a mandatory purchase, is that correct?

That's correct, Paul.

And lastly, any -- should we make any assumptions on repurchases on the Mansfield lease or is it more likely we would assume that those simply remain in place?

More likely those will remain in place.

Thank you.

Thank you.

thank you. Your next question comes from John Kiani of Deutsche Bank.

Good afternoon.

Hi, John.

All seven of my questions have been answered.

That makes it easy.

Actually, I have one follow-up question. I know you've touched on the coal -- new coal supply agreement and you've discussed some of the transportation changes and some of the cost changes as well. Can you give a little bit of color around maybe '09 and '10 or just generally speaking perhaps in the future how we should think about, of the roughly 24 million tons of coal that you burn on an annual basis, I guess how much is subject to price reopeners, callers, escalators or what not, generally speaking, how should we think about that? I'm really more concerned with the roughly 60% or 14 million or 15 million tons that's the eastern poll as opposed to the PRB.

Not a simple question to answer. We have a number of contracts that have reopeners and other factors at different periods of time.

Sure.

I don't know how I could simply quantify that for you John, other than to say the coal, the nuclear, and everything else, 2009, about the same increase as we saw this year versus last year.

And then in the future, it is normal to assume that there are obviously openers or escalators but it is just tough to say exactly, what volume that applies to at this point.

It is because we don't know what all the conditions are that would impact the pricing in the future years. In general, the way our portfolio works is that when prices are going up, we'll tend to lag that somewhat and prices are going down, we'll tend to lag that as well. But it depends on a number of factors that we can't readily predict at this point.

Okay. Thanks, guys.

Thanks, John.

Thank you. Your next question comes from Paul Ridzon of KeyBanc.

Good afternoon.

Hi, Paul.

Hello, Paul.

You may have touched on this but ancillary services, are those embedded in the 75G rate or is that going to be at the disc op?

That would be part of the transmission charge not included in the G rate.

And then just back to the $68 number that was thrown out?

Which $68 number is this? Just so we're talking about the right one.

The average rate at the end of '08.

Okay. Got it.

That's not the average rate but the end of year rate. What do you think the average is? $1 or $2 below that?

That's probably a fair guess. I don't know off the top of my head. That's reasonable though, Paul.

Thank you very much.

Thank you. Your next question comes from Paul Patterson of Glenrock.

Good afternoon, guys.

Hi, Paul.

Okay. The $200 million of expense in 2009 of fuel costs, can you give us a flavor as to how much of that is being driven by transportation costs?

Actually, our transportation costs will likely be flat to slightly down in '09 versus '08, so that's being driven primarily by some eastern coal contracts that we have.

Okay.

Or expectations.

And then the Montana coal plant, you guys are purchasing it for $125 million and there is a $450 million cost associated with developments, is the $125 part of the $450?

Yes.

Okay. And then what is that -- you mentioned there will be -- you mentioned the additional megawatts. Is there an additional cost associated with that or is that sort of 175 megawatts of just extra great capacity?

The way we expect it to work, Paul is that coal will be about the same cost as Powder River Basin, but will produce about 170 to 180 megawatts of more generation. For the same cost, you get more output.

Okay.

That's the beauty of this transaction. And also environmental advantages as well. So, you're thinking about it the right way.

Then that begins at the end of '09, is that correct?

We'll get the first call either late '09 or early '10. Somewhere in that timeframe.

Okay, great. Thanks a lot.

Why don't we do one more call and then if there's any follow-ups, we'll be glad to take those questions off-line.

Your final question comes from Neil Stein of Levin Capital.

Hi, Neil.

Could you talk about the legal standard for gain that is ESP approved by the PUCO and why you think the plan meets that legal standard?

The legal standard -- the legal standard, if I understand -- again, I'm not giving you a lawyer's perspective on this but if my understanding is that ESP test is whether or not it produces a result in the aggregate, that is better than the anticipated result under the MRO. That's -- if I remember right, that's the statutory criteria. And that's what I would anticipate being applied here.

And then with respect to the various prices you've included, what is your basis for including those prices with respect to meeting that test?

You're going to compare the ESP prices compared to what the MRO prices would be. The statute has multiple provisions in it. I believe that we have fit each one of their requests that are made as part of the ESP within a appropriate statutory context.

Okay.

All right.

That's pretty much it. Thanks very much.

Thank you, Neil. Well, thanks again for joining us today, everybody. We appreciate your interest in FirstEnergy and as I said, if you have any further questions regarding anything we discussed today, please feel free to contact our Investor Relation team. Thanks again and have a good day.