Good afternoon. My name is Cheryl and I will be your conference operator today. At this time, I would like to welcome everyone to the FirstEnergy Corp. second quarter earnings conference call. (Operator Instructions) Thank you. It is now my pleasure to turn the floor over to your host, Mr. Kurt Turosky, Director of Investor Relations. Sir, you may begin your conference.

Thank you, Cheryl. 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. 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 of 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 will now turn the call over to Tony Alexander.

Thanks, Kurt. Good afternoon, everyone. I’ll begin by highlighting our operational performance during the quarter and then ask Rich to review our financial results and provide an update on regulatory matters. I am pleased that we continued our progress in the second quarter in achieving our key goals for the year, including realizing the full potential of our generation assets, further enhancing our distribution reliability, pursuing continuous improvement in all aspects of our business, and delivering consistent and predictable financial results. During the second quarter, we recorded earnings on a GAAP basis of $1.11 per share, and our normalized non-GAAP earnings of $1.13 per share were 19% higher than the same period last year. Our generation fleet continued its outstanding performance with a second quarter output record of 20.4 million megawatt hours of electricity, a slight increase over the record established in the same quarter last year. The increased output resulted from the generation up rates we’ve implemented over the last year as well as the strong operating performance of our fleet. Since the second quarter last year, we’ve added 93 megawatts of nuclear capacity through up rates at our Beaver Valley and Davis Bessie plants, and 50 megawatts of baseload fossil capacity from the up rate of unit two at the Bruce Mansfield plant. The favorable fossil performance during the quarter was led by our Mansfield plant, which is our largest generating facility at 2,460 megawatts. That plant produced more than 5 million megawatt hours of electricity in the second quarter and posted a capacity factor of 94% during the period. With our strong performance during the quarter, we continued to pursue our goal of exceeding last year’s record generation output of 82 million megawatt hours. As part of our environmental compliance strategy, we recently announced plans to install…

Thank you, Tony and good afternoon, everyone. As I review our results, it might be helpful for you to refer to our consolidated report to the financial community that we issued earlier this morning. Okay, let’s get started; earnings on a GAAP basis in the second quarter were $1.11 per share, compared to GAAP earnings of $0.92 per share in the same period last year. Excluding special items, normalized non-GAAP earnings were $1.13 per share, compared to $0.95 per share in the second quarter of last year. This year’s normalized non-GAAP earnings exclude the impairment of nuclear decommissioning trust securities that reduced earnings by $0.02 per share. The 19% improvement in this quarter’s non-GAAP earnings resulted largely from favorable operating performance, strong sales, and lower pension and post retirement benefit costs. Specific positive earnings drivers included: a $0.25 per share improvement related to higher generation revenues from a 3% increase in generation sales, as well as higher retail and wholesale prices; a $0.04 per share contribution from distribution delivery revenues, reflecting a 16% increase in heating degree days and a 39% increase in cooling degree days compared to the same period last year, as well as our normal sales growth; a $0.06 per share reduction in other post retirement benefit costs, due to retiree healthcare design changes and lower pension expense following the $300 million contribution to the pension plan in January; a $0.05 per share increase investment income from our nuclear decommissioning trust and corporate owned life insurance; and a $0.07 per share benefit related to the reduction in common shares from the accelerated share repurchases of 10.6 million shares in August of this year -- I’m sorry, in August of 2006 and 14.4 million shares for this year. Factors that partially offset these favorable impacts included: a $0.09…

(Operator Instructions) Your first question is coming from Danielle Sykes of Darman Rose.

Thank you. I was wondering if you are, if you intend to do some additional share repurchase over the next year or so, or your program is pretty much done now?

We haven’t given any guidance or any thoughts, Danielle, beyond the existing program that we completed earlier this year, so we haven’t really said whether we were or were not going to contemplate any other share repurchase programs.

But it is not out of the question as far as over the next 12 months, do you --

We haven’t said that we weren’t going to do it. We haven’t said that we are going to do it, so --

Okay, great. And just a detail, the pension contribution for the impact for 2007 would be roughly how much do you anticipate, for the year?

The pension contribution in terms of reduced pension expense?

Yes.

On an annualized basis, about $0.05.

Thank you.

Your next question is coming from Gregg Orrill of Lehman Brothers.

I was wondering if you could quantify what the impact of the Perry, the recent Perry outage was, and then remind us of the dividend policy?

You’re talking about the Perry outage to replace the recirculation pump?

The one to replace the motor.

Yes, that was a 26-day outage. I guess the general rule of thumb that we often apply to nuclear outages is for purchase power cost, roughly $1 million a day. This is a larger-than-normal, obviously, nuclear plant so I would expect it to be somewhat higher and this outage was in July. Although the month overall was mild, it was still the summer period so I would think something north of $1 million a day is probably the appropriate number that we would expect to see from this outage. Minimal, very minimal, O&M costs related to that so most of the impact was from the purchase power side.

Okay.

I’m sorry, and the second part of your question?

Dividend policy.

Obviously a very important element of the thinking of both the board and management, something that we review on a quarterly basis. I think everybody is aware that in the beginning of the year, we increased the dividend over 11% in order to show our commitment to that and that remains a very important component of our going forward uses of cash over time. The board will continue to consider that each quarter.

Great. Thank you.

Thank you. Your next question is coming from Greg Gordon of Citigroup.

Thanks. I’m hoping you can put something in context for me with regard to Pennsylvania. The PPL utilities did their first bridge auction recently, began sourcing power for fiscal year 2010 to their customers. That price was, depending on how you look at it, in the low to mid 90s for the generating companies that won that bid. Can you help us understand, as we look at your 2011 situation, how much load for FE actually goes to market that is currently being served by FirstEnergy services? And if you were pricing in this market, looking at that auction, can you give us a sense of what the price might be today?

The first part of your question is easier then the second part. Total load for our Pennsylvania companies, for Met-Ed and Penelec it’s about 30 million megawatt hours. FE serves about two-thirds of that in 2010. In terms of what the price might be there, your guess is as good as ours. I think we see more data points as these auctions continue. Obviously the PPL auction was another interesting and relevant data point, I think.

So let me ask the question a different way -- what’s the contract price going to be in 2010, in rough numbers?

If you are talking about the contract between FES and the companies, it is 41.50.

Okay, and PPL price in the low to mid 90s. So I guess when you look at your plants relative to their plants and your load relative to their load, do you see a wider basis differential? Do you see, you know, you just price off a much different hub? Allegheny Energy, for instance, has said that the comparable price for them was around 75, because their plants are all the way in Southwest Pennsylvania. I’m wondering contextually, as we look at your current contract price and we look at clear differences between your portfolio and your load versus their portfolio and their load, if there’s any way we can triangulate around an approximate comparable number.

I certainly know where you are going with your question, Greg. I’m not sure if I can give you a much better answer in terms of specifically what the price might be, but if you look at projected demand growth and relative limits or relative options for new load coming up, I guess our feeling would be that the fundamentals seem to increase, the prices would remain relatively high over that period of time. But specifically what they may be within that pricing point, whatever, I just can’t go there right now with any degree of accuracy. Tony, do you want to add anything to that, or --

No, only that it’s pretty clear in 2011, we’ll no longer have to supply that requirement under the existing contract, and therefore that power can be placed into the market. Whether it is placed into the Ohio market or the Pennsylvania market will depend on where the price points are from our standpoint.

Okay, thank you, guys.

Thank you. Your next question is coming from Paul Fremont of Jefferies.

Looking out into the future and maybe to the 2011 that you are talking about, there seems to be an awful big price differential right now between the Pennsylvania market and the Ohio market, especially given the 2008, 2009 PGM auction results. Is there an expectation that that price gap will ultimately close to the construction of transmission lines or the use of existing transmission lines to bring power from let’s say Ohio into Pennsylvania?

I’m not sure there is even a relevant price point in Ohio at this point, since there’s not been any retail auctions for several years in Ohio, since the auctions we did a few years back. So I’m not sure it’s even comparable there. Certainly different companies have talked about different transmission options between MISO and PGM and so forth. Whether any of those will happen or what timeframe, I really don’t know. Typically there is somewhat of a spread. Ten dollars per megawatt hour is the number that gets bandied around something, but how that will persist over time is yet to be seen.

And the second question I have is I guess earlier on a conference call, Duke sort of expressed that the Governor of Ohio has a fairly high priority energy in terms of new legislation. Can you comment at all as to how his proposal might deal with either an extension of your existing plan or going to market?

The Governor laid out some principles several months ago that are fairly consistent with what we have filed. I think the Governor is particularly interested in conservation, energy efficiency, and we are awaiting more definitive information from his staff and from him concerning which direction he’d like to move in with respect to those kinds of matters.

Thank you.

Thank you. Your next question is coming from Charles Fishman of A. G. Edwards.

Good afternoon. Following the -- with the competitive bid process, you’ll have a hearing I believe on the 16th?

Technical conference.

Technical conference, and then after that, briefs, reply briefs. Is that correct?

The procedural schedule has not yet been established, Charles.

Okay.

-- will be laying all that out.

Well, is it still -- I know at one time your strategy was to avoid any kind of formal testimony. Is that still the strategy?

I’m not sure I understand.

Well, would there be like -- you know, in a traditional rate case, you’d have a lot of filings, a lot of testimony and there’s obviously not the, really the technical -- or not necessarily technical but the quantity of data obviously isn’t there with respect to the competitive bid filing. So is this a process that can be expedited and reach a decision pretty quickly so you can keep on your schedule to actually bid that first tranche this year?

Again, we’ve asked for a commission order in November of this year and that is going to require a movement through the process at a relatively good pace. I think the technical conference as a starting point is probably the way to help facilitate that as we try to get the questions of people answered in a more, kind of deal with the more technical aspects of it so we are not chasing necessarily issues that can be resolved pretty easily just by face-to-face conversation.

Are there any big industrial groups or other user groups that are against the competitive bid process at this point that have surfaced?

I don’t know who has intervened in that proceeding at this point. With respect to the processes that we’ve identified, I don’t quite -- quite frankly, I don’t know what the timeframe is for them to do that. It may extend until after the technical conference. I’m just not sure, Charles.

Okay, and at this point, from an answer you gave to a previous question, I assume the Governor’s office, his Director of Energy or the commission has not approached you to negotiate an extension of the rate certainty plan versus the, you know, in lieu of the competitive bid process. Is that -- I took that to be the case from your previous answer. Is that correct?

With all the discussion and conversation that is going on in Ohio, I would say that is on its face correct, but there is certainly a lot of discussion at the general assembly and with members, with the PUCO, with the Governor’s staff of what the future of Ohio might look like.

Okay, well, thank you. This will certainly be an interesting time to watch Ohio.

Thank you. Your next question is coming from Steve Fleischman of Catapult Partners.

On the share repurchase plan, do you have some update on how far along the banks are in completing that plan?

Well, the shares came off our books the day we executed the ASR. [CEPO], they are out there covering their short position. There is a pricing grid in the mechanism, Steve. We haven’t disclosed what those price points are but obviously as the stock price goes down, the number of shares purchased go up. I think we said this program would be completed probably, depending on where the stock price is, later this year and that expectation is still --

Okay, but would there be any update, for example, in your Q on that?

No.

Okay, and then is there, along some of the other questions, this may have been answered already; is there any update on your hedging in Pennsylvania?

Are you talking about energy hedging?

Correct.

Capacity hedging, or all of the above?

I guess the whole picture.

There’s really no changes in that. I think we’ve talked about that in the past. There’s been nothing new to report there.

Thank you.

Thank you. Your next question is coming from Hugh Wynne of Sanford Bernstein.

Good morning. I was wondering if you had any views regarding the legislative initiative in Illinois to phase in the increase in the rates of Exelon and [Ambren], and whether that has implications for legislative action, similar legislative action in Ohio and Pennsylvania with respect to rate transitions to market in those states, or whether you feel that’s an isolated Illinois event and that Ohio and Pennsylvania are unlikely to take a lesson from that.

Well, the fact of the matter is, Hugh, as part of our generation filing, we proposed to phase in, in the event that the rates exceed 15%, the increase would exceed 15% for certain residential tariffs. I think we’ve tried to address that as what it is. It is just kind of a political transition to make it a little easier on customers. We thought about it when we made our filing and I think we’ve addressed it and I believe Ohio has the tools to allow that to happen.

I think my question was more towards the mood, let’s say, of the legislators in the two states and whether you saw a sort of popular stance to utility sentiment as strong, and whether you expected therefore the type of legislative intervention and conflict, frankly, that we’ve seen in Illinois.

Well, again, I think we try to manage that through dealing with issues hopefully before they become that type of political issue, like a phase in, like our phase in proposal would accomplish.

Okay, and then just a final question on that point -- do you see the transition to market rates in Ohio as being managed on a company-by-company basis, or do you see some kind of statewide policy likely to be implemented?

Well, I think we have a statewide policy right now that says we are going to market. I think every individual company might choose to get there. For example, I think AEP and Mike in his most recent conference call talked in terms of moving to market in a stepped process, in which the difference between market prices and price to actual customers would be deferred and collected as a regulatory asset. That’s another way to get to the same point. I think there is the potential to do that, with the goal ultimately being moving in the direction of market prices. That’s effectively what we propose when we say we are going to phase in if the price gets above 15%. We put the step in at that level.

Right. Okay, good. Thank you very much.

Thank you. Your next question is coming from Paul Ridzon of Key Bank.

The Ohio questions have been asked, just more near term, it looks like trailing 12, we’re at about the top end of your guidance. Aside from Perry, which was a surprise, is there anything else in the back half of the year that we need to be thinking about with regards to maybe potential detractors from earnings?

The two things I had mentioned, Paul, were just the Perry outage and the mild weather we saw during July in this part of the service territory. Otherwise, no.

No incremental nuke outages or refuelings or --

No.

Okay. Thank you.

Thank you. Your next question is coming from Dan Jenkins of State of Wisconsin Investment Board.

Good afternoon. First, just a clarification; I missed, you talked about your second half financing. I think you mentioned a $600 million long-term issue. If you could just run through those details again real quickly.

What I had said again is that we have about $600 million of unsecured debt issued out of our operating companies during the second half of the year. We are still working on exactly when, where, who and how but that is our expectation.

Okay, and then related to that, your financing of the financial lease back, did that pretty much take care of all your short-term refinancing, of that short-term debt?

Yes. Those proceeds were applied to reduce short-term debt, so we have our liquidity where we want it to be and in fact, that will continue to improve during the year, so we are in good shape there.

Okay, and then I was wondering about the Perry, the unplanned outage. Could you give me just kind of some details as to what happened to cause that outage, and then if there are any issues that the NRC is looking at related to that outage?

What happened was a circulation pump motor in the recirculation system, a large motor, I think it’s about 30 tons, failed. This happens from time to time, which is why we had a spare there which we were able to take out and put in. It was a big project. This is a big piece of equipment. You have to move a lot of things to get it out of the containment and put the new one in. An unfortunate circumstance which is one of those random things that happens from time to time and that’s why we had the spare in place ready to go when those kinds of things do happen. But that was completed, no NRC implications from that.

Okay, and then I was curious on the $0.25 increase at the generation. You mentioned that was both due to higher volume and higher prices. I was wondering if you could break that down between the two pieces -- how much was volume and how much was prices?

Hang on just a second here -- of the retail generation sales, let’s see -- $0.16 and $0.09 from the wholesale sales. I think most of that was rate driven -- all of that was rate driven.

Okay, and then just the decline in the wholesale, is that primarily due to the plant outages or --

Yes.

Okay. I think that’s all I had then.

Thank you. There appear to be no more questions at this time. I will turn the floor back to your host, Mr. Rich Marsh, for any closing remarks.

Thanks, Cheryl. I just again want to thank everybody for their time today and their continued support and interest in FirstEnergy. If anybody has any follow-up questions, please feel free to get a hold of our investor relations group and I hope everybody has a great day. Thank you for your time.

Thank you. This concludes today’s FirstEnergy Corp. second quarter earnings conference call. You may now disconnect.