Greetings and welcome to the FirstEnergy Corp Fourth Quarter 2013 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. (Operator Instructions). As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Meghan Beringer, Director of Investor Relations for FirstEnergy Corp. Thank you, Ms. Beringer. You may begin.

Thank you, Christine, and good afternoon. Welcome to FirstEnergy's fourth quarter earnings call. First, please be reminded that during this conference call we will make various forward-looking statements within the meaning of the Safe Harbor provision 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 various risks and uncertainties. A number of factors could cause the 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 information and financial releases link. Today, we will be referring to operating earnings, which is a non-GAAP financial measure. Reconciliations to GAAP earning from operating earnings are contained in the consolidated report, as well as on the investor information section on our website at www.firstenergycorp.com/ir. Please note that our annual report on Form 10-K is expected to be filed within the next several days. Participating in today's call, are Tony Alexander, President and Chief Executive Officer; Leila Vespoli, Executive Vice President, Markets, and Chief Legal Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of First Energy Solutions; John Taylor, Vice President, Controller and Chief Accounting Officer; Steven Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations. Now, I will turn the call over to Tony Alexander.

Thank you, Meghan, and good afternoon everyone. I'm glad you could join us. I will start today's call with an overview of 2013 including our unaudited results and accomplishments. We will also take another look at our areas of focus for 2014 and the next several years. I will then turn the call over to Leila. In January, Leila took on an expanded role that now includes responsibility for our competitive business. So she will provide a power market outlook in addition to our normal update on regulatory developments. Finally, Jim will share a more detailed overview of the fourth quarter financial results and review our 2013 financial achievements. Then, he will discuss 2014 initiatives before turning the call over for questions. Okay. Let's get started. This morning, we announced operating earnings of $0.75 per share for the fourth quarter of 2013 and $3.04 per share for the full year at the upper end of our guidance which reflects our strong operating performance for the year. As you know, 2013 was a challenging year for the company as we took action to improve our financial position, lower our cost structure and position the company for more stable and predictable growth through our regulated holdings. And some of our key accomplishments included successfully implementing our financial plan which reduced our debt out of our competitive business by $1.5 billion, improved its credit metrics and strengthened its balance sheet. We reconfigured our generation, our competitive generation fleet and as a result reduced cost while retaining a mix of generating assets that is more cost effective, efficient and environmentally sound. We also successfully completed the Harrison and Pleasants' asset transfer, which is expected to help ensure reliable power for our Mon Power and Potomac Edison customers in West Virginia for many years to…

Thanks, Tony. I will start with an update of the status of several matters in New Jersey, Pennsylvania and Ohio before moving to a high level look at FirstEnergy Solutions and developments in our region's power market. Starting with New Jersey, yesterday we signed and filed a settlement agreement with board staff in rate council to permit recovery in base rates of $736 million of JCP&L, $744 million of cost related to the significant weather events of 2011 and 2012. The agreement upon which no other party took a position to oppose or support is now pending approval before the board of public utilities. Of course, we still do have a base rate case pending in New Jersey. Hearings have concluded and we filed a reply brief rate in this case yesterday. We expect resolution of the base rate case within the next four months. Let's turn to Pennsylvania for an update and the transmission service charge rider, which relates to the recovery of $254 million in marginal transmission losses and associated carrying costs for the June, 2007 through March, 2008 period. As you know, we completed the process of refunding Met-Ed and Penelec customers in this case last spring and we recognized an impairment for this item in our third quarter financial statement after the US District Court dismissed our proceeding. However, we continue to believe in the merits of our position and during the fourth quarter we appealed to the third circuit. Briefs have been filed and oral argument has been scheduled for April 9. Moving now to Ohio, in December, the public utilities commission denied our re-hearing request for recovery of $43 million of renewable energy credit purchased to comply with Ohio's renewable energy portfolio standard. On December 24th, we filed the notice of appeal and motion…

Thanks, Leila. Let's move right into our financial results. You may want to refer to the consolidated report which was issued this morning and is available on our website. As Tony mentioned earlier, our fourth quarter operating earnings of $75 per share were at the higher end of our expectations, these results compared fourth quarter 2012 operating earnings of $80 per share. On a GAAP basis, this year's unaudited fourth quarter earnings were $34 per share, compared to a loss of $35 per share last year. The full list and special items that make up the $41 per share difference between GAAP and operating earnings can be found on page 4 of the consolidated report. Most significant of these are a charge of $51 per share related to the transfer of our Harrison and Pleasants plants in West Virginia, a $14 per share charge related to plant deactivation cost associated with a closure of fossil units, and regulator charges of $12 per share. These were partially offset by a gain of $38 per share related to our annual pension and OPEB mark-to-market adjustment which benefited from a higher discount rate. Other special items for the fourth quarter include trust securities impairment of $0.02 per share, non-core assets impairments of $0.02 per share, a decrease of $0.02 per share related to merger accounting for commodity contracts and a gain of $0.04 per share for other mark-to-market adjustments. Let's move now to review of our business results. In our distribution business, higher revenues increased fourth quarter earnings by $0.05 per share as total distribution deliveries increased 4% or 1.4 million megawatt-hours, compared to the fourth quarter of 2012. On the Residential and Commercial side, the gains during the quarter were largely weather driven with colder winter temperatures driving 3% increases in both…

(Operator Instructions). Our first question comes from the line of Julien Dumoulin-Smith with UBS. Please proceed with your question.

First, I just wanted to clarify your comments on the first quarter guidance if you could. Could you provide a little bit more clarity in terms of how much of the year-on-year impact is from the outages and perhaps also how much is impacted from the latest weather, if you will, versus plan when you release '14 guidance?

Julien, in the main, I mean, as you look through the year, you got to remember that in part the first quarter would not have only affected by the Davis-Besse outage, which is scheduled for basically all of February and all of March; losing Beaver Valley was also impacting that January timeframe. So the first quarter is going to be impacted by that probably more than we would have expected, but about in the same range as where we were originally anticipating. As you think about the year, however, the growth in earnings from the segment were rising as time went on. For example, the capacity revenue in the first quarter of this year is about $27 a megawatt a day or whatever that is. Starting in June it goes to $126 per megawatt a day. So there is a very large impact on capacity revenues quarter to quarter as you move through this timeframe. Also, when we talk about the annual guidance over the year need to think about the transmission investments that we are making in the earnings that arise from the -- when you start those expenditures in January they grow over time. And as they are placed in service in the later part of the year, those earnings tend to be more tail end loaded than front end loaded in this overall timeframe. So while the first quarter with expectations are probably little lower than what people would have thought normally just by dividing by four they're not too far off of what we would have otherwise expected.

And so perhaps just to summarize, how do you think about your net exposure ultimately to the latest volatility on pricing? Was it net benefit or net reduction I mean, sort of excluding the impact of the Beaver Valley outage?

Julien, we are going to go through all this stuff when we get to the first quarter timeframe. We are only through one month of the first quarter. But obviously, when you have the type of weather we had, we had more sales on both the competitor side and the utility side in January than we otherwise would have anticipated. And obviously with the extension of the Beaver Valley outage part of which we have already talked about earlier I think, this year towards the end of last -- earlier this year, that had an impact. And clearly there the prices were somewhat higher than we would otherwise anticipated and we are also seeing some PJM costs that are a little higher than we would have anticipated, but we don’t have the final bills on all of those things yet. So I think at this point that the best way to look at it is that from a company perspective, guidance range is the same and segment ranges are the same. So how they shake out during the year and the actions we will take offsetting one way or the other, will take place naturally as it always does during a year when you are dealing with multiple issues.

Great. Thank you.

Our next question comes from the line of Neel Mitra with Tudor, Pickering and Holt. Please proceed with your question.

Hi, good morning, I just had another question on maybe the retail exposure. When you look at super peak periods, do you typically used the FE fleet with peakers to serve that demand or do you usually go out into the spot market to procure some of that, but I know that you are fleet is more heavily weighted towards the base load than the peaking generation. So just wanted to know how you handle that going forward?

Neel, this is Donny. We rely heavily on our fleet as you know but we also utilize call options and purchase power as need be. If the fleets running flat out the way per design, we are pretty well hedged; we don’t have to rely much on the spot market.

Okay. So, I'm trying to understand this just a little bit better. Is the exposure that you incurred in Q1 as a result of some of your base load plants being out on an unplanned outage and you being forced buy power or was it from kind of the spot power that you would buy from the peaking transaction side of it?

Yes, I think as Leila and Tony both said, obviously we at the Beaver Valley outage that was almost the entire month. In addition, to that while in aggregate for the month our fissile fleet ran pretty well, we did have some outages at our Mansfield plant that occurred in inopportune times, specifically when there was a very coldest weather and the prices were the very highest. So having to buy to replace for those outages was expensive.

Neel, so we are still looking in that but I would imagine when we file we would file the cases that we are going to file this year at one point in time. But as to the particular utilities, I am not prepared to say right now. Obviously, we would want to talk to folks in Pennsylvania and tee that up before announcing that publicly.

Okay. Thank you very much.

Our next question comes from line of Dan Eggers with Credit Suisse. Please proceed with your question.

Hey, good afternoon. I guess we may -- we try to understand that the guidance question maybe little better, so I apologize for repeating this to death. But if you assume normal weather for the three quarters of the year as you would have light up the plan when you guy revised it for the year, where would you guys fallout within the $2.45 to $2.85 range?

Steve?:

Dan, I think if I understand your question you are trying to find out where we would fall between the two goalposts, $2.45 to $2.85?

Right.

I think we are at -- and as way I see it right now, although we had some extreme weather and had some higher cost there is other items that we have identified that would help offset that. Take -- one example would be the higher prices than we originally expected would happen in the Ohio auction. So I am pretty comfortable that we are still right in the same range that we talked about on the last call.

Okay. So you are comfortable in the middle of the range, so this is -- the first quarter variants was within your plan?

Yeah, I am still comfortable that we are at the same place within our range, yes.

Okay. And then, I guess on a New Jersey, the -- can you just give me that data once going on with the CTA and you are kind of where that JCP and all rate case gets done with that issue still outstanding?

Okay. So a lot of moving pieces and parts in Jersey. So with the settlement of the storm case, we roughly -- with respect to the $7.5 million that roughly makeover $1.5 million in revenue requirement. So while the settlement deals with the prudence, if you will, of those dollars, what it does not settle is whether the 2012 storm dollars are going to go back into the rate case. If you recall the BPU had indicated that 2011 storm cost would go back. And so, roughly according to our approach and how you would look at the storm cost roughly -- the revenue requirement roughly $23 million would go back into the base rate case. And we are now briefing as to whether the 2012 storm cost should go back in. But if you think about the commission's or the BPU's original order establishing the test year, they established the 2000 test year but also included any out of period measurable changes that were shown to be prudent, were major in nature in consequence and that were quantified though proof and had reliable data. I think the 2012 storm cost fit all those categories, so I think we have a very good argument to pull those strong cost back into the base rate case. Where we stand with respect to that, with five briefs have been filed. ALJ has 45 days to issue their decision, his decision and there is no extension, reply exceptions are generated around 30 days and the BPU may be another 30 or 60 days. With respect to the CTA, I would have love to have position paper by the staff. Unfortunately, that did not come out prior to the briefs in the rate case and staff took a position that was consistent with the BPUs order which said that until we have an ultimate decision in the CTA generic proceeding, we were going to continue with what their prior position had been. So that essentially was they were negative with respect to us and the CTA. So will I still would like to see an order coming out of the commission with respect to the generic proceeding in the CTA, it is definitely on a slower path than I would have anticipated.

I mean is there a chance that CTA you can get done before the case gets done and if it is not getting done is there a way to just slow down your case and hopes it does get resolved because it is not an inconsequential issue?

You are correct. It is not an inconsequential issue, it is roughly $56 million in revenue requirement and roughly would negate about a quarter of the rate base. So just looking at it from that perspective shows the gross and fairness of applying a CTA adjustment in this case. I would hope that BPU would look at that. The fact that JCP already has the lowest rate in the state of New Jersey, which again further exasperates the consequence of that. But right now, we need the staff to issue an order and I have not seen a timeline for that to happen. Ultimately, if the BPU should be issue an order and should be negative in terms of not providing further the CTA in appropriate manner, our option would be file another rate case. And by that time the decision on the next case, I believe we should have a resolution of the generic case.

Great. Thank you for that.

Our next question comes from a line of Jonathan Arnold from Deutsche Bank. Please proceed with your question.

Just a quick financial. First, on the competitive segment, the interest expense around $35 million, the full capitalization in fourth quarter, is that a reasonable run rate going forward or is there something else going in there? Have we kind of found the new level with the all the repositioning of the balance sheet?

Yes, I think it would generally be slightly higher than that, Jonathan. You might recall we called in one pollution control note, that was about $230 some million and we had a about $10 million favorable interest that Dutchman associated it with that.

In 4Q and specifically in competitive?

Yes, that generally grow the $0.01 improvement in earnings that I talked about.

There is a number from third quarter, probably a better level?

Yes, I would say that is correct, Jonathan.

Okay, great. Thank you. And then, I missed the number you had on the hedging for 2015, would you mind repeating that? I apologize. I think I got 94 in '14 and 29 in 16.

That was in years later, was it?

56?

Yes, we have 52 million megawatt-hours in 2015 Jonathan.

Okay. And is this as of right now or is that as of end of the year?

That is current right now.

Okay. And so, you talked about being at the lower end of the glide path and to be positioning yourselves to take advantage of moves. We have seen some moves, particularly in the winter pricing in '15 and to an extent in '16. Can you tall at all about kind of what you have, how you -- what you have been hedging? Are you kind of locking in any about seasonality or just generally trying to stay as open as you can given the increased volatility we've seen in the market?

Jonathan, this is Donny. We have not really tried to position it for seasonality up to this point. Generally, what happens is the customers are going to buy to lineup with the planning here so to speak. So it is not unusual for a customer to want to buy June through May or perhaps though by on a calendar year, but to this point we have not seen much customer demand for kind of a seasonal -- not say we won't be looking at that but at this point we have not have that opportunity.

Great. Thank you very much guys.

Our next question comes from line of Steve Fleishman with Wolfe Research. Please proceed with your question.

Yeah. Hi, good afternoon.

Hi, Steve.

Hi, Tony. I guess this question might be for Leila. I think you mention the PJM ancillary cost that some of those get pass through the customers?

Yes.

Is that just in certain states or how does that work? How do we know which areas get pass through or not?

It is pursuant to contract in a specific language within the contract so it is not a state by state kind of thing, Steve.

Okay. So it is certain types of your customer classes?

In?

In a retail business?

It is not even the same throughout particular classes.

Okay.

It is as that contract language was developed for that particular customer or grouping of customer. So there is no way I can even give it to you by segment.

Okay. So some of the cause when you get this data come up will be cause that you absorb but some of those would be available to essentially pass through your contracts to the customers?

Correct.

And in the future, do most of your contracts have that clause, so new ones do or not older ones or vice versa?

I think it would be safe to say that we are going to be adding that language where we can in the future.

Got it. Okay. Thank you. Just want to clarify that.

Okay.

Our next question comes from line of Stephen Byrd with Morgan Stanley. Please proceed with your question.

I wanted to just explore retail margins in the out years and just given the kind of volatility that we are seeing I think on some of your prepared remarks you talked briefly that maybe recognition of greater volatility being reflected in markets. But just curious, if you could talk at a high level to given the kind of volatility you are seeing? Is that impacting how you see the margin potential on the retail side events?

Yes, Steven this is Donny. I think especially if you look at like the Ohio polar auction and you can see that those prices are up substantially, I think that's reflective of the volatility. Obviously, as we move forward and price new contracts on the retail side, we will begin the higher volatility so they will naturally drive the margins up, if you will.

Okay. Understood, and just relating to that volatility topic, given the kind of volatility we have seen, is that caused you to think further about through the right size or role of the retail position in terms of the target gigawatt hours or you sort of comfortable where you are?

Steven, I think you are always looking at where your right level of sales are and, in part, it's driven by what the market provides or delivers to you. If customers are willing to pay the risk premium associated with carrying the volatility in the market then I suspect you will see retail sales at certain levels if customers are not anticipating paying that, but I would expect it would be a just to (inaudible) because the cost don't go away from a volatility stand point. And some point the market is going to have to period. And at the end it's going to be whether or not it is going to be from a customer stand point or ultimately at that point whether or not a retail market for customers exists in the same format that we see it today. We are already seeing the impact of variable pricing on not only industrial customer for residential and commercial customers that have chosen that path whether or not they stay in that environment over a long period of time is if volatility continues to be a issue in the market and my own sense is that perhaps it will given the structure of it we could see some very different forms of retail contracts.

Can you just speak, Tony, maybe a little further to those different forms of retail contracts that you are (inaudible)?

Well, like Donny said, there could be more adjustment clauses in them, there could be more risk add it to fix contractor. There is a whole series of things that could be put in place to try to mitigate or address those types of differing issues.

Steven, this is (inaudible). The list that Tony just gave one of the things that you clearly look at is tolerance bands. What we are seeing today in the marketplace any customer that had decided to go to an hourly kind of product they are already calling us and wanting something different because they were obviously hit high prices in the month of January.

I see and so some of your customers are seeking that reduce that risk, we'll just have to see the degree to which they are willing to paid to get that risk protection.

Okay.

Okay. Thank you very much.

Our next question comes from line of Paul Patterson with Glenrock Associates. Please proceed with your question.

Just quickly following up on Steve's question with respect to the ancillary service cost, you guys mentioned that there was still some settlement and settlement billing that had to be coming out of PJM and we're going to January and February and obviously I guess March coming up, but any sense that we might see in terms of if there is any variation with this or any quantitative numbers that we might be talking about that some range in terms of exposure here or?

I can tell you with respect to kind of global PJM and ancillary resources and again these are parsed out on load ratio share. Just kind of order of magnitude for ancillary services the billing throughout PJM for January 2014 equaled the charge for ancillary services for all of 2013.

Which is how much? Roughly speaking not putting on the spot, if you don't have it that's okay. I just --

$800 million.

I'm sorry, could you repeat that?

$800 million.

$800 million?

That's PJM total, Paul.

No, I got you. Okay. But you guys do with your contracting and everything and you are hedging that you guys have been able to really mitigate the exposure to this stuff, correct? I mean, if I understood you guys correctly right? It's all in guidance other words.

We are working through that process right now on a contract by contract basis and we work with PJM to make sure that the buildings that also got (inaudible) charge to us are appropriate.

Okay. Fair enough. And then just finally on the Ohio alternative energy monitor that $40 million is there any ongoing exposure other than that which you guys are fighting, which you guys are going to court on? Is there any other exposure going forward that we should think about with respect to that at all?

No, I don't believe so.

Okay. Great. Thanks so much.

Our next question comes from the line of Gregg Orrill with Barclays. Please proceed with you question.

On Davis-Besse, I was wondering if you could talk a little bit more about the scope of the work around the unplanned concrete fixtures during the current outage and kind of the level of correspondence that's required with the MRC?

I will try to give you as much as I can. Gregg. Don't hold me as being the expert on this at this point. I have briefed a couple of times, but we will go through the process, we believe that what we found is that structurally significant to the overall shields integrity. And it is fixable in the upcoming when we actually close the opening. It primarily resulted, if I understand it correctly primarily resulted because this was a -- it was left in a more temporary position with framing still in place on the back side, because we knew we're going to cut it again in a year. What happened is that it didn't completely settle into all areas and so there were some gaps. We think it's fixable fairly straightforward inside the scope of the timeframe of this outage.

Thank you.

Operator, Christine, we will take one more question.

Thank you. Our final question comes from the line of Paul Freemont with Jefferies. Please proceed with your question.

Thank you. Just point a clarification on the JCPL case is if the 12 costs are not included in the GRC, would they be included in whatever the NJBPU decision is in the generic proceeding or would you have to wait for a whole new rate case to include those costs?

The answer is unknown. The BPU left open the possibility of another mechanism for recovery unspecified in nature. So obviously we would prefer something that gives us more immediate recovery even if it's not included within the current base rate case that's in front of the BPU right now, but as kind of an outside bookings to think about if they weren't included, if things didn't go on our way we would be filing another rate case basically on the heels of this decision and we would get those costs included in that case.

Okay. And the second question is of the $736 million of costs that you identified how much of that would essentially represent an increase in the rate base of the company?

The $736 million is all (inaudible) represent it is all rate base.

But I guess some of it is going to be the recovering (inaudible)

I'm sorry --

Let us give that number for you. I think the rate base numbers in the $400 million range --

Its $407 million in capital and $329 million in deferred.

You got that?

Sorry about that. Okay.

Okay. So essentially it's $407 million of increased rate base?

Yes, that would be the capital fees. That's right, Paul.

Okay. And you would be able to earn a full return equity or full weighted average cost to capital return on that $407 million, right?

We should, yes.

Okay. Thank you very much.

Thanks Paul. I like to thank everybody for joining us today. We appreciate your continued support and we remain committed to providing long time value and sustainable growth. Bye now.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.