Greetings, ladies and gentlemen and welcome to the FirstEnergy Corp. second quarter 2009 earnings call. (Operator Instructions) It is now my pleasure to introduce your host, Irene Prezelj, Manager, Investor Relations for FirstEnergy Corp. Thank you. You may begin.

Thanks, Jen. 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; Mark Clark, Executive Vice President and Chief Financial Officer; Leila Vespoli, Executive Vice President and General Counsel, Harvey Wagner, Vice President and Controller; Jim Pearson, Vice President and Treasurer; Bill Bird, Vice President of Corporate Risk, and Ron Seeholzer, Vice President of Investor Relations. I will now turn the call over to Mark.

Thanks, Irene and good afternoon, everyone. As I review our second quarter results, it may be helpful for you to refer to our consolidated report to the financial community which was issued this morning. Our financial results for the second quarter were positive despite the effects of both the continued slow economy and our region’s mild weather. Excluding special items, normalized non-GAAP earnings were $0.87 per share, which matches our results in the second quarter of 2008. On a GAAP basis, second quarter earnings were $1.36 per share compared to $0.86 per share in the same period last year. Five special items have the net effect of increasing GAAP earnings by a total of $0.49 per share. The largest of these was the $0.52 per share gain from our previously announced sale of a 9% participation interesting the Ohio Valley Electric Corporation. This gain was slightly offset by four items that together reduce GAAP earnings by a total of $0.03 per share. These were the impairment of securities held in trust for future nuclear decommissioning activities, organizational restructuring charges, a loss on early debt redemptions, an implementation of our work plan as a result of the strike at Penelec. There were primarily four positive drivers of this quarter’s results. First, new distribution rates at our Ohio utilities added $0.09 per share to earnings. Second, investment income from corporate owned life insurance increased earnings by $0.01 per share. The third positive was generation gross margin, which increased earnings by $0.08 per share. Similar to the first quarter, the generation story is made up of several components so I will spend a few minutes going into detail on these results. Within generation margin, there were principally three positive drivers -- lower fuel expense increased earnings by $0.08 per share. This relates to…

Thanks, Mark and good afternoon, everyone. I would like to start with an update on our operations. Beginning with our announcement last Friday that we intend to align all of our transmission assets within PJM, this change is not a reflection on the job [Miso] has done for us over the years. It’s simply recognition that because Miso operates in predominantly regulated states, PJM is a better fit for our competitive focus. We expect to file with FERC soon for approval to integrate within PJM on June 1, 2011. This will coincide with the implementation of the next generation procurement for our Ohio utilities. Moving now to an update on our Montana coal mine operations, construction is well underway at Signal Peak. We expect to move into production later this year. Both the wash plant and rail line are nearing completion. The long wall is scheduled to be in operation in late November. We’ve also secured multiple test cargos that will be shipped into the Asian markets in the fourth quarter. When complete, this facility will provide us with a source of fuel that has the environmental benefits of western coal, better heat value than [Potter River] Basin coal, and as much as 170 megawatts of additional capacity at our fossil plants. We’ve also made significant progress on the regulatory front. In Ohio, we recently held two collaborative meetings with the signatory parties to our ESP case to discuss issues surrounding the next competitive generation procurement process. We will use those discussions as the basis for MRO application which we plan to file with the PUCO later this year. Also in Ohio, last week we filed applications with the PUCO to recover approximately $298 million of deferred distribution costs on an accelerated basis. Collection of these deferrals was originally to…

(Operator Instructions) Our first question comes from the line of Greg Gordon with Morgan Stanley.

Can you -- I have a couple of questions. The first one is explain the rationale for the transition to PJM, and is one of the reasons to get better transparency and better pricing signal on the underlying value of capacity? Because when I look at the implied value of capacity in the pricing you got in the last procurement, it seems to be pretty skinny.

I would say yes.

And if you were to be accepted into PJM, would you be pricing that capacity through the same types of pricing mechanisms that current PJM generators -- the auction that they currently bid into, and if so, when would that event occur?

Let me take that one because it will have some -- there will be a transition involved if, depending on how the FERC reacts and the timing of their decision. Let’s just assume that the FERC approves the transaction, us moving into PJM by January or by December or January of this year -- this December of 2009. We would intend to participate in the May auction for the 2013 and 2014 capacity in that time frame, or the capacity requirements when we move into PJM on June 1 of 2011 through May of 2013, that would be conducted under a special transition mechanism that will be proposed as a part of our filing.

Right, so that would be -- there would sort of be a fill-in auction.

Yes, that’s what we will propose.

Okay. Second question -- anecdotal evidence on industrial, potential pick-up in industrial production, we’re seeing a lot of news about the big, the huge feedback that the government is getting on the cash for clunkers and I read some things over the weekend about dealers actually saying that they are running out of cars in specified models. Taking that, as well as other economic factors into consideration, do you think industrial production in your region has bottomed? And if you were to give us sort of a base case for the next six to 12 months on what we should be assuming, what would it be?

I don’t know if we’re prepared to give you a base case but I will give you a couple of, which you referred to, anecdotal evidence. We saw steel in May for the first time not actually continue to decline but with a slight increase and then in June, it kind of stayed around where it was at the end of May. So we’ve seen that declining month over month balance stop. In the auto sector, Ford has announced a 16% increase in their production from their prior schedule. I believe it was today the large Lordstown facility announced that they are bringing 2,000 workers back. Chrysler, out of bankruptcy, is bringing their plants back. General Motors, Lordstown is also the plant that is in the hundreds of millions of dollars of conversions for the Cruise automobile, so I wouldn’t say, as I said in my comments, that we are indicating that we are out of the recession but it does seem to appear that some of the more positive events have stabilized and they are no longer in kind of a declining mode. Refineries would be another example. They are tracking closer to where they were in January. So we are seeing bits and pieces across the whole service territory.

Thank you very much.

Your next question comes from the line of Ashar Khan from Incremental Capital.

Good afternoon. Just going back to the question, the fill-in auction, Tony, that you referred too -- that will price the capacity as part of that auction, is that correct? And which zone will we be allocated? Is there some thoughts on that?

Well, I don’t believe there will be any zone reallocation. There will be a special auction conducted. It will have certain terms and obligations within it that will -- and mitigation measures, obviously, because this is kind of a single area auction. A lot of the details will be covered, at least some of the details will be covered in the application that we intend to file and we’ll just have to see how that plays out.

But then in the May auction which, for 2013 and 2014, do you have a sense -- are you going to be part of the RTO or is it going to be a special zone? Do you have a sense where you would fall, or that is to be determined?

I am going to let Bill Bird try to answer that for you.

We expect our [load zone] will be included in the rest of pool capacity [done at PJM].

Okay. Thank you very much.

Your next question comes from the line of Paul Fremont with Jefferies Capital.

Thank you. I guess my first question would be the cash that you took in from the sale of [OVEC], is that very close to the gain of $254 million that you reported?

Yes.

Second question is on the load following utilization, there was a significant drop-off I guess to -- on those units to like 25%. What would be sort of the drivers behind the reduction in utilization in that part of your fleet?

I think the economy would be one and then the mild weather. I mean, for example, in July 2008 there were 249 cooling degree days and in July of 2009, there were 130 -- it was almost a 50% drop in cooling degree days. We talked about the economy so I guess the simple answer is if no one is requiring use, we’re going to shut our plants down.

And was there any evidence of switching to gas or gas displacing coal or that didn’t really happen?

No, not that we’ve seen.

And I guess the last thing is you guys pointed out mild weather so far in July -- should we read into that within the range of your guidance that you -- that that would place you towards the lower end or is it just too early at this point to gauge the weather impact?

Well, I would say we’re just too early. We’ve still got two months of this quarter, three months of the fourth quarter. But it was, you know, as we said, very abnormal weather in July. I think you heard that almost repeated throughout the region.

Thank you very much.

Your next question comes from the line of Hugh Wynne with Sanford Bernstein.

Good afternoon. I just wanted to congratulate you all for this exceptional reduction on O&M expenses. It’s really very impressive. The question I have is with respect to the cash flow statement. The third quarter showed some material improvement in cash flow from operating activities, almost $700 million over the same quarter of last year. Cash used for investment falls by something just short of $500 million. My question is are these developments driven by temporary factors, shifts in working capital that are unlikely to recur? Or is there something more structural afoot here that’s indicative of more robust cash flow going forward?

Well, I think there’s some structural issues. We’ve reduced our work force. We’ve changed healthcare benefits, things like that, so there are some structural changes. There are what I will call intermediate changes as the load is down. We’ve deferred or accelerated some of our outages. We’ve reduced overtime. We’ve reduced contractor spend. Clearly as the economy comes back, if it’s more economic to have the unit back up, we will and those expenses will be offset by revenue. I think Harvey could give you some additional flavor.

The major drivers there for this year over last year, obviously the gain on the OVEC sale added about $158 million to operating cash. We had a collection of receivables were $116 million higher than the prior year, and reduced tax payments of about $258 million, so those are the major drivers. Obviously receivables, tax payments, there’s a lot of timing around that. I wouldn’t call those structural things.

All right, so I think basically in your view, the bulk of this is driven by timing of collections and tax payments and the OVEC sale. What about the CapEx -- is that --

You might recall last year in the second quarter is when we made our acquisition of Freemont, the partially completed natural gas plant. That constituted I think somewhere around the $250 million range, so that’s probably the biggest driver for the change in the investing activities.

Great. Thank you very much for the detail in the answer. Appreciate it.

Your next question comes from the line of Gregg Orrill with Barclays Capital.

I was wondering if you could follow-up on the increased level of generation hedging for 2010, just kind of what -- where the additional retail sales came from and how the pricing was relative to your expectations.

I think the incremental sales came from the fact that we’ve announced that aggregation of the communities. Ohio is significantly different than other states in that you can aggregate entire communities at the same time. I think we are up to 50 or 60 communities, in that range. Also individual sales to large commercial industrial accounts and some smallish mass market types of mailing but it’s principally aggregation and then the large commercial industrial sectors.

And the mix of pricing there, how did that compare to expectations?

It’s going okay, Gregg.

Thanks, Tony.

Obviously we’re not going to talk about pricing information at this point.

Okay. Good news either way.

Your next question comes from the line of Paul Ridzon with Keybanc.

Could you elaborate a little more on progress you’ve made today moving outside your traditional Ohio footprint, and kind of what you envision there and what you think your competitive advantage could be?

Principally, you have to take Western Pennsylvania, Illinois -- [the only difference] between the two is that in Pennsylvania, some of that can be sourced from our own generation. In Illinois, we were sourcing out of the market but now we can source from our own generation. But I would characterize that our main focus right now is capturing customers that have the ability to shop in Ohio. That’s somewhat time constricted but once we get through Ohio and we’re pretty comfortable with where we want to be in Ohio, we’ll start to again move aggressively both to the southern part of Ohio and then also East and West outside.

What’s the time constraint on doing this?

Customers can shop now. It’s open. It’s a market. We’d like to sign up the customers before somebody else does. It’s just kind of traditional marketing.

I understand. Okay. Thank you.

Your next question comes from the line of David Frank with Catapult.

Good afternoon. A question -- how would joining PJM impact the cost of transmitting power from Generation Ohio to Pennsylvania? Are there some seams payments that would decrease or go away?

I don’t think so, David -- not material, anyways.

Okay. And what was the embedded value of capacity, either in terms of megawatt hour in the last auction or megawatt day in the Ohio auction?

I don’t think it was -- it’s not broken out and I don’t think you will find many competitors willing to break it out.

Okay. You guys can’t provide an estimate for us?

No. It’d be difficult.

Okay. Thank you.

Your next question comes from the line of Kit Konolige with Soleil Securities.

I have a feeling from the no comment answers so far that I’m not going to get too much further on some of this but just to shift over a little from the Ohio sales and developing your marketing there at the beginning of ’11, or I guess before then you will have auctions and you will be selling into Pennsylvania. Can you give us some sense of what that’s going to be -- I mean, is that just its own auction as well and there’s very little we can compare that to to get an idea of how much, what kind of pricing we are going to be seeing there?

Kit, I think at this point, you are just going to have to wait. I mean, those auctions will probably take place for at least our Pennsylvania subsidiaries at Met-ed and Penelec, probably beginning sometime next year is what our game plan is. So sometime in 2010. I believe we are proposing multiple auctions, all of which will take place before probably the end of the fourth quarter.

Right, and they will be done the way the other auctions are in Pennsylvania, just like a -- there will be I think four -- is there four of them and they’ll just be done -- pick four days, have an auction, everything’s rolled into it and you’re not bidding separately for any capacity, anything like that?

Right now, there is a procurement case going on at the commission and we’ve announced with the judge that there will be a settlement filed shortly. The contents of that settlement are not public at this point but will be shortly, but you can expect something similar to what you saw in Ohio, although in Pennsylvania, there are slightly different legislative requirements so you might see some things with respect to shorter term product that you did not see in Ohio.

Kit, it’s probably just a little early for that -- why don’t we wait until that material gets filed and then you can take a look at it?

Well, that’s no fun. You’ve got to know it in advance, right? Okay. Thank you.

Your next question comes from the line of [Vidula Murty with CDTUS].

A couple of things -- one, I’m wondering, can you -- in terms of -- I think you mentioned that you now have 86% of your service territory through the first [inaudible] versus 100 previously. Can you talk about whether -- when you think about your opportunities outside of your service territory and customers you may be picking up, net net whether you are offsetting the reduction of your market share within the historic base?

It’s not so much in our minds megawatt hours or market share as it is margin -- how much margin we may be picking up in -- you know, I don’t know, Illinois, Western Pennsylvania, Ohio, what’s left in Ohio, Southern Ohio. We prefer to think of it as margin, we could pick up a substantial amount of megawatt hours and lose money at the same time, just based on pricing. So our focus is going after those markets where we believe there’s sufficient margin in Ohio and southern Ohio. There’s certain rate classifications that that’s attractive. In Illinois, some of the large commercial/industrial accounts, similar in Western Pennsylvania, so it’s really more looking at the types of rates, the customer, the load factors, the shapes of the load, those types of things, all play into which customers per se we go after.

Well, I mean, have you been able to basically build off of your gross margin base that you had from 100% through optimizing your customers availability and their margin profiles?

Yes, but I would only characterize it to say that we had margin from FES before. It’s just now that it’s significantly larger. In Tony’s comments, we didn’t just start in the retail business. We’ve been doing it for almost a decade so it’s -- I would characterize it more as building upon the margin that already existed.

Okay, my second question relates to the pension expense here in the second quarter. Is this -- this is not something -- should we be annualizing this going forward in terms of the rest of the year or is there some timing issues? How should we think about that?

I think that I would just encourage you to annualize it. It will be re-measured at the end of the year based on the asset base and the amortization of any expenses, so I think we’ve given pretty clear guidance that it’s about that annualized and then when we make the calculation again, I think Harvey, you make that what, December 31st?

Right.

And then we’ll include that into the ’10 guidance.

Okay. My last question is can you talk about how, now that you’ve gone through your credit reviews and everything like that, can you talk about the financing plans in terms of dealing with the short-term debt balances and the maturities coming up?

Sure. I think if you look at it, we have the whole [code] debt in 2011, we have the revolver in ’12, we have the pension short-fall in ’15, we have the sale leaseback in ’16. So we are fairly aware of what’s coming. The issue to us is I think it’s somewhat two- or three-fold. One is we want to make certain that the capital structures of the operating companies are aligned with the regulatory rate-making structures. Second, we want to make certain that the liability of the debt is aligned with the asset, and as you know, we use short-term debt principally to fund the AQC project. We’d like to take that, make that more permanent, put the liability there versus the holding company. And third, we’d like to get some of the variable rate debt down. I think we are looking at pulling it down about 5 or 6 percentage points -- if I’m wrong, Jim will correct me here. Just because we are not certain where the rates are, it’s an attractive market now to do that, so I would say those three components, aligning the cap structures with the regulatory process, aligning the debt with the asset, and moving some of the variable rate debt over to the fixed side.

So it would be fair to say that the last two are things that may well occur during the balance of 2009?

Most definitely, yes.

And can you give us a range of how many dollars are probably tied to that part of it?

You know, one thing we have from the -- we’ve requested regulatory approval to issue up to $600 million at Pennsylvania Electric. We’ve also requested up to $300 million at Cleveland Electric, so those are some of the financings that we could be doing from the regulated side. And as Mark alluded to earlier, at FES, you know, we’ve funded the Fremont, the AQC, as well as some of the repurchases of our nuclear sale and leasebacks using our revolving credit facility and we have about $1 billion borrowed on our revolving credit facility there, so as Mark alluded to, we would be looking at replacing a portion of that with longer term financing in time.

Okay. Thank you very much.

(Operator Instructions) Your next question comes from the line of Brian Chin with Citigroup.

On the PJM topic, we’ve read that the supply in the FirstEnergy region would add roughly around 7% to PJM’s peak supply, and that the load in your region would add roughly 8% to PJM’s peak load, so the net RTO reserve margin decrease would be around 1% or so. Do those numbers sound generally in the right ballpark or is there something there that we might be missing?

No, they sound about right. I don’t know how they are calculated but that sounds about right.

Great. Thanks a lot.

Your next question comes from the line of Daniele Seitz with Dudak Research.

Thank you. I was wondering if your estimates on the generation that you did earlier on are still on target in terms of total generation for this year?

Yes, we’re not at this point planning any change in our generation forecast. Obviously that’s subject to weather, the economy, and a host of other factors.

And no major change -- you can still make those numbers?

Yes.

Okay, great. And as far as the O&M, did I understand right that you were saying that you would reach your target in 2010 or I was not correct?

I’m sorry, what’s the question?

You mentioned when you mentioned the $330 million of O&M savings, you mentioned that you will reach that target in 2010 or was that not what I was supposed to understand?

We’re going to reach that target in 2009.

Okay, and these are -- you do not anticipate that there is a lot of one-time are in that number, it’s something that will be pretty much permanent?

Well, there are some one-time items and there are some permanent items -- for example, staffing reductions, those that were made in March are more than likely permanent. There are some other reductions that may be one-time. For example, if we’ve extended an outage because of the market conditions, next year we may not do that but if you just look at the expense without looking at the revenue offset it, it’s attractive to accelerate that plan and bring it back into the market soon. Someone might argue that was a one-time expense but on the other hand, the revenue is offsetting that so we end up with a positive, so there’s bits and pieces of everything in there.

But it’s not -- no major numbers there that would -- what I understand is that the O&M savings are likely to continue in 2010 from other areas?

Maybe I can rephrase your question and say it a little bit differently -- do I think that we are going to see a major reduction in that O&M number, and I would say no.

Okay. Thank you for asking me. Thank you.

We’ll take one more call.

Your final question comes from the line of Travis Miller with Morningstar.

Good afternoon. Remind me if I am -- I want to make sure I am correct here. You guys had two extra nuclear outages in the quarter, is that correct?

Yes, I think if you take it over the course of the year, we had three plus I’ll say a half that we took a plant down, or maybe somebody here can give you the exact numbers but I think the scheduled planned, unplanned nuclear outages for the year are roughly 175 days.

175 days, and if I look at your release here, you had three -- at least portions of three in the second quarter. How much did that add to the other operating expense line versus 2Q08?

No, nuclear generation was down for the quarter so that’s our least costly fuel based plant, so you just -- you’d have to compare that to what our next most expensive fossil [inaudible] plant would have been on an economic dispatch.

That’s on the gross margin line though, right?

Right.

What about in the other operating expense line, O&M?

Pretty much similar.

Similar to 2Q08?

Oh, to ’08? I would say they are fairly constant, in terms of budget reductions and other cost changes.

I don’t remember whether or not we had a nuclear outage in the second quarter of 2008 to make a comparison with but --

In the second quarter of 2008, we had planned outages that were 39 days, second quarter of ’09, we had planned at Perry of 42, Beaver Valley one of 31; maintenance at Davis Bessie at 17, and forced at Perry of five, so that would be like 95 days to 39 in the second quarter, roughly round numbers 100,000 megawatt hours and the O&M expenses are roughly the same between quarters year over year.

On just those -- I’m just thinking the outages should cost more, right? I mean, if you have more outages you should have higher operating expense, or is that not correct?

We’d have higher fuel expense.

Fuel, sure, but even at the operating line, would you not have extra O&M for an outage?

It depends on the scope of the work that’s being done. Some if it is capital, some of it is O&M, year over year -- frankly, the O&M costs excluding fuel were flat.

Okay. Great. Thanks a lot.

Thank you. At this time, I would like to turn the call back to management for any closing remarks.

I’ll just make one correction from the script -- we had Tony misquote something in his portion of the script. I want to make sure it was corrected -- we talked about usage dropping in steel and automotive customers in the [high region]. He misspoke and said 800 million megawatt hours; it should have been 800,000 megawatt hours. Thanks.

I would like to thank everyone for joining us on the call today and as always, we appreciate your continued support and interest in FirstEnergy. Thank you.

Thank you. Ladies and gentlemen, this concludes today’s conference call. You may disconnect your lines at this time. Thank you for your participation.