Welcome everyone to the FirstEnergy Corp second quarter 2008 earnings conference call. (Operator Instructions) It is now my pleasure to turn the floor over to your host, [Irene Prezo], Manager of Investor Relations. [Irene Prezo]: During this conference call we will 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. Reconciliation 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.

Good afternoon everyone and thanks for being with us. We have a full agenda for you today. I’ll start by providing an overview of our second quarter financial results and 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. 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 the 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 claim settlement related to a previously-sold international asset as well as a $0.04 per share loss related to the impairment of securities held on our nuclear decommissioning trust. Positive drivers of this quarter’s comparative results include 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…

Good afternoon everyone. As you know, yesterday we filed both our Electric Security Plan and our 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 and 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 staged 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 a 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…

(Operator Instructions) Our first question comes from Greg Gordon - Citigroup.

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 on the year on sort of a normalized from those events because clearly you’re still hitting the high end of the range even with those setbacks?

Greg it’s always been our policy not to attempt to normalize for weather impacts or some of these other items that you mentioned, so since we don’t do that I don’t know what those numbers are. But you’re correct. Those were factors that really did shape events during the second quarter. And 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 that 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?

Yes, I think that’s a fair statement overall.

When I look at the filing you made in the letter that you made available and the documents you made available via email, you show a base generation rate for 2008 of $0.68 cents going to $0.075 cents in 09 and going up to $0.08 or $0.085 cents. Can you tell me what’s in that base 6.8 cents?

The basic G price Greg includes energy and capacity except for some certain planning reserve requirements. It 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 all transmission?

It excludes transmission, yes.

Our next question comes from Jonathan Arnold - Merrill Lynch.

A quick one on the next steps with the review in the PUCO. How much visibility do you have on the proceedings and what we’ll be looking out for as the next road map way marker?

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 hearings. You’ve submitted them and staff will comment on hearings, etc. as far as you know?

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

You have the third year of the plan being at the PUCO 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 are very detailed provisions inside the plan with respect to what continues, what drops off, and how to 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 1,000 pages Jonathan?

Well, we’ll get there but 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 this full term, because remember the distribution rate freeze runs through 2013 I believe, so there are terms that continue beyond the three years 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 the Commission’s decisions.

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

I think it’s spread across several layers of testimony Jonathan.

The simplest way Jonathan is Ron Seeholzer.

There’s an application both for ESP and MRO, 40 some pages in the front end, and I think if you try to get through both of those initially, you’ll get an awful lot of the background.

Our next question comes from Gregg Orrill - Lehman Brothers.

A question on the securitization proposal. I assume that a key issue in getting it approved is whether it’s a cheaper cost versus a sort of defer and 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 of all Gregg, let me comment. 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 that is 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’s Attachment A in the filings that kind of runs you through the various steps of that. I won’t go through that now but I would call it a relatively conventional sort of securitization transaction. You’re right that we have two options to recover the costs. One would be securitization with bonds with final maturity not to exceed 10 years. The second option is a recovery mechanism also not to exceed 10 years where we would earn a carrying charge on those deferrals at the annual rate of approximately 8.5% during the period those expenses are being deferred. And then once the recovery started, we would earn at the long-term debt rate for each of the individual companies. So that’s kind of weighing out the two options. We wanted to put those out for the Commission’s considerations and then we’ll go from there after they’ve had a chance to look at that.

Our next question comes from Daniel Eggers - Credit Suisse.

Just looking at the targeted rate increase of about 5% a year, how much do the adders and 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. I mean it’s not possible to know if those will be triggered and if so how much the increase would be. So they are not included.

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 it’s null and void.

The write-off Dan as you know is about $485 million so that would be an impact to earnings of about $1.01 in 2008.

The billion dollars of commitment on the transmission and distribution spending, that looks pretty consistent with existing cap ex plans. Is that correct or is there something incremental that you guys are going to spend on the utilities part of the plan?

No, I think your presumption is correct. In 2008 I’m trying to think of the exact number. For our three Ohio distribution companies it’s about $265 million to that order. Yes, I think you’re right Dan.

Our next question comes from Ashar Khan - SAC Capital.

If I understand Rich by taking this write-off if this plan is assumed in 2008, we will have no longer any amortizations relating to CEI going forward. Hence, the drop off of like $225 million or so I forget the precise number that was to happen in 11, will all happen now in 09 along with the drop off of an amortization for the remaining two Ohio companies. Is my understanding correct?

Correct.

So we can have nearly $1.00 in earnings just from the drop off in the amortizations from all the three companies which will now happen simultaneously on January 1, 2009?

You’re theory is correct without opining on your number, but yes you’re theory is correct for sure.

Second, you mentioned that the $68 includes I guess the embedded costs right now of generation plus some costs related to some of the green initiatives in the filing, is that correct?

You’re talking about the net customer generation charges?

Yes, for 2008.

It’s got the RTC in it.

It’s got the RTC in it. 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’s 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 I got confused. You mentioned that fuel costs are going to be higher again in 09 versus 08 and I know that in this plan you’ve asked for recovery of certain transportation costs related to the fuel if they exceed certain amounts. Could you tell us out of that increase you’re expecting from 09 to 08 and how much of that will be absorbed by the transportation rider that you would have in this filing?

What I said in my comments is 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 and 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 mine coal items and nuclear fuel expense. 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 in each of the years of the plan. That amount threshold is the highest in 2009 so we don’t know whether that would be triggered or not in 2009. It depends on basically what our fuel transportation costs do over that timeframe.

The distribution rider, if I’m doing my math correctly, which is 0.002 is an additional $100 million in revenue. Is that correct?

Are you talking about the delivery service improvement rider?

That’s correct.

Yes, that’s how much it is. +/- 15% based on our achievement of delivery service reliability goals.

But you said that the cap ex and the O&M and everything, the cap ex isn’t going to change because of this. So it just means 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 that amount up or down within that band.

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

So we get this $100 million additional and then there will be a +/- attached to it based on how we perform. Is that correct?

Yes.

For 2010 is there another fuel jump in 2010 or are we pretty flat, because you said you had a lot of contracts and everything. Is that 09 to 10 movement more levelized on the fuel basis?

We haven’t talked about 2010 yet.

The $68 that you were trying to do the comparison with, I just want to take just a second. It’s not an average annual rate that was indicated there. That’s 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 the 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’s been adjusted during the year. It may have looked slightly higher than we talked about but it’s not an annual average number that we were addressing with the $68.

So the average number would probably be lower?

Correct, because that’s a comparison of end-of-year rates 2008 to a projected 2009 to make that percentage jump. Does that make sense?

That makes sense. Thank you, sir.

Our next question comes from Paul Fremont - Jefferies & Co. Paul Fremont - Jefferies & Co.: 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 but not in terms of specific price. Paul Fremont - Jefferies & Co.: At some point will that be disclosed through 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 term fair 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’s 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.

One of the disclosures that 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 estimate of that. Paul Fremont - Jefferies & Co.: 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 is correct. Paul Fremont - Jefferies & Co.: 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 that those will remain in place.

Our next question comes from John Kiani - Deutsche Bank North America.

All seven of my questions have been answered. Actually I have one follow up question. I know you’ve touched on the 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, how much is subject to price re-openers, collars, escalators and what not? Generally speaking how should we think about that and I’m really more concerned with the roughly 60% or 14 million or 15 million tons that’s the eastern coal as opposed to the PRB?

Not a simple question to answer. We have contracts that have re-openers and other factors at different periods of time but I don’t know how I could simply quantify that for you John other than to say in total if you look at the coal, the nuclear and everything else 2009 versus 2008 as I said before about the same increases we saw this year versus last year.

In the future it’s normal to assume that there are obviously openers or escalators but it’s 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 that pricing in those future years. In general the way our portfolio works is that when prices are going up we’ll tend to lag that somewhat and when 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.

Our next question comes from Paul T. Ridzon - Key Bank Capital Markets/McDonald. Paul T. Ridzon - Key Bank Capital Markets/McDonald: You may have touched on this but ancillary services, are those imbedded in the 75 G rate or is that going to be at the [DISCO]?

It would be part of the transmission charge that is not included in the G rate. Paul T. Ridzon - Key Bank Capital Markets/McDonald: Back to the $68 number that was thrown out.

Now which $68 number is this, just so we’re talking about the right one? Paul T. Ridzon - Key Bank Capital Markets/McDonald: The average rate at the end of 08.

Okay, got it. Paul T. Ridzon - Key Bank Capital Markets/McDonald: That’s not the average rate but the end of year rate. What do you think the average is, $1.00 or $2.00 below that?

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

Our next question comes from Paul Patterson - Glen Rock.

The $200 million of expense in 2009 of fuel costs, can you give us a flavor as to how much of that’s 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. That’s our expectation.

The Montana coal plant, you guys are purchasing it for $125 million and then there’s a $450 million cost associated with development. Is the $125 million part of the $450 million?

Yes.

You mentioned that there’s going to be I think additional megawatts. Is there an additional cost associated with that or is that just 175 megawatts of extra capacity?

The way we expect it to work Paul is that coal will be about the same cost as Powder Riverbase but will produce about 170 megawatts to 180 megawatts more generation. So for the same cost you get more output. That’s the beauty of this transaction. And also environmental advantages as well. So you’re thinking about it the right way.

And then that begins at the end of 09, is that correct?

We’ll get the first coal either late 09 or early 10, somewhere in that timeframe. Why don’t we do one more call and then if there are any follow ups we’ll be glad to take those questions offline.

Our final question comes from Neal Stein - Levin Capital.

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

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

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

Well you’ve got to compare the ESP prices against what the MRO prices would be. The statute has multiple provisions in it and I believe that we have fit each one of the requests that are made as part of the ESP within an appropriate statutory context.

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 Relations team. Thanks again. Have a good day.