Greetings. And welcome to the FirstEnergy Corp.’s Third Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. (Operator instructions) As a reminder, this conference is being recorded. I would now like to turn the conference over to Ms. Meghan Beringer, Director of Investor Relations. Thank you, Ms. Beringer. You may begin.

Thank you, Manny, and good afternoon. Welcome to FirstEnergy’s third 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 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 also available on our website under the Earnings Information link. Today, we will be referring to operating earnings, operating earnings per share, operating earnings per share by segments and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations between GAAP and non-GAAP financial measures are contained in the consolidated report. The updated fact book, 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; Chuck Jones, Executive Vice President and President, FirstEnergy Utilities; Leila Vespoli, Executive Vice President, Markets and Chief Legal Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of FirstEnergy Solutions; Jon Taylor, Vice President, Controller and Chief Accounting Officer; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations. Now I will turn the call over to Tony Alexander.

Thanks, Meghan, and welcome, everyone. Thank you for joining us. Today, we will provide an update on the important initiatives that are shaping our company's future. Since our last earnings call in August, we have continued to build positive momentum in our regulated businesses and limit risk at our competitive operations. And at the same time, we are starting to see real progress as a result of our efforts to advocate for a competitive market that supports price stability and reliability. I will start with the review of development across our business, including some of the early and encouraging signs of reforms in the regional competitive markets. Then Chuck will join us with an update on the distribution business and our transmission investments. Leila will then discuss the status of the rate cases at our utilities, the ATSI filing that we made last week and other regulatory matters, as well as an update on the changes we have put in place in our competitive business. Finally, Jim will review our third quarter and year-to-date financial results. Okay. Let's get started. I'll start with a look back at events that have shaped this year so for. We believe 2014 will be remembered as a pivotal period for both our company and for the competitive environment in our region. The stage was set with the unusually warm temperatures in our region in September 2013, which strained the regional grid. With the start of the next year the same region was impacted by the polar vortex and subsequent severe weather events throughout the winter. These episodes of increased demand, revealed weaknesses in the regions power supply and resulted in nearly 100 emergency actions, interruptions of service to customers and severe spikes in wholesale power prices. We reacted quickly to the deterioration in market…

Thanks, Tony. I'm pleased to join the call today. I'll start with a brief look at our distribution business and then move to an update on our Energizing the Future transmission expansion program. We remain encouraged by the steady growth and stable load in the commercial and industrial sectors of our distribution business, both of which continue to benefit from the modest economic recovery and increased economic investment primarily related to shale gas. While weather was significantly mild compared to the third quarter of 2013, our distribution business continued to produce solid results. More important, as you have heard over the past several earnings calls, the overall trends for commercial and industrial deliveries remain very solid. In fact, adjusted for weather, we have now seen five consecutive quarters of growth in both the commercial and industrial segments. The industrial pipeline remains promising. Among this region's traditional industrial base, including steel, automotive, electrical equipment and petroleum sectors nearly all of our key customers are expanding and clearly shale related activity remains a bright spot. Signs point to continued and accelerated growth in this sector. In addition to its considerable impact on our distribution business, the shale industry is also driving growth in our transmission segment. Approximately $250 million of the regulated transmission investments we have identified for 2015 at TrAILCo are designed to meet rising electric demand, driven by the shale gas industry across our regulated service territories. This infrastructure, including high-voltage substations and transmission line is coming online to accommodate new shale gas processing facilities pipeline compressor stations and other energy intensive operations in Ohio, Pennsylvania and West Virginia. These midstream projects alone account for 1100 megawatt of anticipated electric load growth in 2015 through 2020. The rapid growth in the shale gas industry is transforming communities and creating new…

Thanks, Chuck and good afternoon, everyone. I'll begin with a brief update on our competitive business and then I will look at the status of our distribution rate cases and other regulatory matters. The transformation of our competitive business is well underway. As we announced in August, we are pursuing the effective hedging of the majority of our generation resources with reduced risk and at the highest margins possible, while leaving a portion of our generation available to capture market opportunities. The actions we have taken put our competitive business in a stable position, from which we can gauge market conditions and participate when and where the opportunities are most promising. Consistent with our strategy, we continue to allow attrition of our MCI and mass market customer base as contract terms expire, as well as weather sensitive LCI loads. Overall, contracts sales volume decreased by 4.5 million megawatt hours, compared to the third quarter 2013. At the same time, we are maintaining targeted sales levels to government aggregation customers in Ohio and participating in POLR auctions where we see value. During the past month, POLR auctions were conducted in both Pennsylvania and Ohio that will ultimately determine retail generation service rates for these small service customers. Both auctions produced results that appear to reflect an increased risk premium, which we believe is associated with volatility and uncertainty in PJM. In Pennsylvania, the auctions were for 12 months and 24 months, residential and commercial products for delivery beginning June 1, 2015. Auction clearing prices for residential products range from between $70.09 to $85.15 per megawatt hour, while clearing prices for commercial products range from between $74.46 to $89.65 per megawatt hour. HPS won nine tranches in that auction. In Ohio, HPS won four tranches in the 10th wholesale auction, which produced…

Thanks, Leila. As I discuss our financial results, it may be helpful for you to refer to the consolidated report, which was issued this morning and is available on our website. As Tony mentioned earlier, our third quarter operating earnings were $0.89 per sh0are in line with our expectations. Third quarter 2013 operating earnings were $0.94 per share. On a GAAP basis 2014 third quarter earnings were $0.79 per basic share compared to $0.52 per basic share in the third quarter of 2013. A list of the special items that make up the $0.10 difference between our GAAP and operating earnings can be found on page 2 of the consolidated report. Now let’s review the key drivers of operating earnings across each of our business segments. We will begin with our distribution business where we reported third quarter operating earnings of $0.56 per share compared to $0.60 per share in the third quarter of 2013. Moderate weather was the most significant factor this quarter with lower distribution deliveries impacting earnings by $0.03 per share. With respect to the other drivers in the distribution business pension expense, depreciation, and interest expenses all increased slightly in the quarter. However, these factors were offset by earnings related to the Harrison/Pleasants asset transfer and a lower effective income tax rate. Looking more closely at the affects of weather on third quarter results, cooling degree days were 15% below last year and 17% below normal, which led to a 1.5% decrease in total distribution deliveries. Most of this impact can be seen in the residential sales, which decreased 784,000 megawatt hours or about 6% compared to the third quarter of 2013. In the commercial sector, third quarter distribution deliveries to commercial customers decreased by 199,000 megawatt hours or 2% due to the moderate weather. We…

Thank you. (Operator instructions) Our first question is from Dan Eggers of Credit Suisse. Please go ahead.

Hey. Good afternoon guys.

Hello Dan. Dan Eggers - Crédit Suisse: Hey. There was huge matter of information. Thank you for all that. I guess, looking at the PPA or the ESP process in Ohio, something that’s come up and raised is the idea of the off-market transaction for 15 years in those assets. Can you just kind of walk through, maybe a little more of the legal justification for beyond the obvious benefits to Ohio customers or the visibility?

Hi, Dan. This is Leila. So obviously and proposing this, my legal team was very mindful of the legal precedence that was out there. I think from a policy perspective, we put forward a very wonderful case that we address that and then, I will go into more of the legal specifics. If you think about these plans, especially Ohio plans build and service Ohio customers, Ohio jobs, Ohio tax saves . So from a standpoint of, whether this is something that is beneficial certainly from an economic standpoint is very beneficial. Having this generation, as we justified on our filing also, over the 15-year period would provide essentially $2 million worth of benefits to customer, so acting like an insurance policy. From a legal perspective, if you think about the aggregate rule, Ohio is a competitive state. So we do not have captive customers. So FERC has waived the rule, it applied to us. Also, we were very mindful of two of the other cases up there, being the -- hit the (indiscernible) case and the Hanna case. And have put in place mechanisms within the case, so that we do not run or fall of the particular things in those cases that triggered FERC’s finding that they were legally informed. So, offline, we can go into the details. But, again, the legal team is very mindful of that in the structure of the PPA proposal and what the commission can and can’t do and the terms and conditions actually associated with the PPA. Dan Eggers - Crédit Suisse: Okay. And I guess on the West Virginia settlement, the element that I haven’t gone through all of it, given the earnings day today. But the Harrison plant probating contributed as much or any on this that we’d expected on the first transfer. Would this settlement help get the full value of that rate base uplift into earnings going forward?

So, essentially, what this case did, so let me back up for a second so. In the Harrison transaction, we stipulated that case. In that agreement, we agreed to file this base rate case and so this is the case where we basically flipped what would have been surcharged into base rate. So, essentially, all we did is take what we’ve covered in that revenue stream and flip it to base rate treatment. And then on top of that, the stipulation provides for an additional $15 million increase. And in addition to that, roughly $48 million of our vegetation management surcharged, which should help with our distribution and reliability which is good in West Virginia but should help enhance that as we go forward. The stipulation also provides for establishment of regulatory assets associated with mass investments in 2016 and ’17, and other different provisions from the company's perspective, which we believe is very good. Again, this is a case that we filed as a result of a stipulation and I think -- prior stipulation and I think from a company standpoint, our customers’ standpoint is a very good result. Dan Eggers - Crédit Suisse: Okay. And just one last question just on the quarter. With this lower demand with the weather and all that, how much benefit did you guys see out of the retail business despite reduced volatilities, is that kind of what helped on some of the earnings gap this quarter?

Dan, this is Donny. In the main, what we saw obviously, there wasn’t a volatility issue that we faced in the first quarter. But we took advantage of a lot of the O&M savings. We’ve reduced the workforce and that sort of things, so that's really what flowed through for us in the quarter. Dan Eggers - Crédit Suisse: Okay. Thank you guys.

Thank you. The next question is from Paul Fremont of Jefferies. Please go ahead.

Thank you very much. I guess my first question is, if I look at capacity performance and the potential hatter, how should we think of that relative to your PPA proposal in Ohio? Would you potentially rethink the offer in Ohio?

Hi Paul. This is Leila. So we made our filing and we are going to go full with our filing. I think, having the potential for capacity performance proposal by PJM and if it gets eventually approved by FERC, will be even a more enhancement for Ohio customers. But we would not withdraw our ESP commitment. I think overall the proposal by PJM is a positive development. But as I noted, I think there are ways that it could be improved. I think that they should consider with performance persistent pricing mechanism. If you think about it in terms of the generation, the need for revenue and kind of the longer-term horizon, if it were to have a mechanism whereby year-to-year, the downside were kept by 5% generators, where we could get a better sense of what the capacitive pricing might be from year-to-year that would definitely be a positive development. In the transitional years, we think it should be uncapped up to net cone, given that the markets, I think everybody’s account have not produced the revenues that most agreed that they should have. We think that that would be a more appropriate place getting revenue to generators, so they can make the investment in their plans to increase reliability and a better balancing of the penalty structure. I think PJM approved upon it but we still think the penalty structure is a little bit more draconian than it should be at this point in time.

And when, Jim when you ran through corporate another, I guess corporate another is already benefiting this year from tax, from lower tax what should we think of -- in terms of corporate and other as sort of a better indication for a run rate?

Okay, Paul. I’d said earlier our effective tax rate would be anywhere between 30% to 31% this year and its going to most likely move back up to the 36% to 38% of our range next year. So that that would be probably about $0.25 a share, Paul, and most of that flows through corporate another.

So a $0.25 per share increase off of the 17, right?

That’s correct. No, not all of that will go to corporate but most of that would.

Okay. And in terms of the nuclear leases. The last nuclear leases if I recall you bought them in the range of like $1500 per KW. Can you -- what type of a price did you pay for the most recent lease purchases?

We haven’t disclosed that yet Paul. The transaction hasn’t completed yet. I can say I would say both parties are very comfortable with the price we paid. So that’s something we are ready to disclose at this point.

And the last question in West Virginia, was it a black box settlement or was there some agree to level of ROA?

So the parties agreed to the $15 million increase in the other terms. The commission actually asked that we -- in our filing how we got to that. So you will see us part of the settlement. If you go to the exhibits, each of the parties will lay out how it got there. The company has not laid out the ROE associated with it. But there is an ROR number.

Thank you.

Thank you. The next question is from Jonathan Arnold of Deutsche Bank. Please go ahead.

Yeah. Good morning. Sorry, good afternoon guys.

Hi. Jonathan.

Hi. Just a quick question on as we look at these adjusted EBITDA outlooks for the competitive business, am I right that this is a delta between the commodity margin and the EBITDA number is mainly O&M consistent -- and probably general taxes consistent with the earnings statement?

That will be correct Jonathan.

Okay. So I guess my question is when you look at the 15 to 16 numbers the implied expense number goes down about $100 million between 15 and 16. And if you look at the run rate on 14, its down quite a bit more than that 15 or 14. So can you just talk about how we think the components that bridges that as those numbers just seem quite big?

Jonathan, this is Donny. Yeah I think if you take a look at the EBITDA from 15, if you’re trying do come up a walk from 15 to 16. In ’15, we’ve got a midpoint of $950 million. And then if you look at what the capacity revenue does from ‘15 to ‘16, it comes down about $225 million…

Yeah but…

And then we have improved margins about a dollar megawatt hour so that’s a positive about $80 million. And then other O&M and cost reductions, that’s about $100 million, gets you right to about $900 million for midpoint.

Okay. That was already my question, is there a $100 million of O&M saving embedded in that forecast, it sounds like the answers is yes.

Yes. That’s throughout and we have one last nuclear outage in the ‘16 timeframe and that especially helps.

Okay. Can you also bridge so that we’re in a $1.5 billion of non-GAAP O&M in a year-to-date through September and it’s been running about $400 million at least last quarter. So how does it got from that number down to the $1.250 billion or so implied in the ‘15 guidance? What are the big drivers there? I’m looking at the delta between…

Jon, it’s one or two have high rates, take it get back because there’s probably a lot of components to make that up, so I shall get back to you after the call.

Happy to do that.

Thank you. The next question is from Stephen Byrd of Morgan Stanley. Please go ahead.

Good afternoon.

Hello.

I wanted to explore the capacity performance penalty side of the equation and Leila, you touch briefly on it. Just curious if the ultimate roll ends up quite similar to the proposed penalty rule that PJM has laid out. Would that as you assess kind of the risk reward of your fleet? Do you think that would likely lead you to think about some degree of asset shutdowns, not at all or how do you generally think about that the risk of penalties?

So the penalty structure again, I think was mitigated from their prior proposal. But you can’t look at it in isolation, you have to look at the other moving pieces in parts. Right now, the coalition noted in their comments that right now if you had a single 12-hour too bleak, it could cause you to lose the equivalent of 71 days of revenue. So there are both kind of things you need to look at and have a trade-off. If the pricing mechanism will raise in that color and you’re able to recover that level. You might be able to think a little more positively about that kind of penalty. So again, there are a lot of moving pieces in parts and I wouldn’t look at the penalty just in isolation.

Okay. Understood. And then just thinking also about carbon regulation and how the different states might look at that, I was particularly interested in Pennsylvania and Ohio, is it your sense that there is some probability to those states who think about joining the regional carbon mechanism such as regi, do you think the states are more likely to resist the proposed regulations? What’s your general sense of those two states and how they are thinking about carbon?

Stephen, this is Tony. I think at this point it’s a little too early to tell. I still think that each states evaluating and trying to understanding and comprehend the proposed rule and as well as trying to figure out whether or not the alternatives to them moving from to a mass kind of calculation would be easier for them to manage. So, I think, at this point, everybody is trying to understand what’s going on, not clear where they are going to end up yet. And my senses is that until we better understand how this rules going to be applied in the options, it will be hard for any one of the states to otherwise indicate exactly which way they are intending to go.

That’s helpful. Thank you very much.

Thank you. The next question is from Angie Storozynski of Macquarie Capital. Please go ahead.

Thank you very much. I have two questions. One is, so I’m clear in the guidance of 2016 the generation capacity that didn’t fear in either the original or incremental auction is assumed not to receive any capacity revenues?

That’s correct, Angie.

Okay. And then second, I hope I misheard that one is, okay. So there is a change in the effective tax rate between ‘14 and ’15, and what is the $0.25 of a swing? Is -- are you suggesting that the parent level drag increases from $0.17 to like $0.40? Jim?

Yes. That’s right, Angie. That will be the range.

Okay. But why is -- I mean, what was then the effective tax rate in ’13 when we have about $0.27 or $0.26 drag?

I think the effective tax rate in ’13 was about 36%.

Okay. So it’s a same type of rate that you’re guiding for ’15 and beyond. So why such a big delta?

We have some additional debt outstanding and we have some of that debt had variable rates, so those rates could increase on that also Angie. So it’s primarily associated with additional interest costs.

Okay. Thank you.

Operator, we’ll take one more call.

Certainly, the next question is from Paul Patterson of Glenrock Associates. Please go ahead.

Good afternoon. Can you hear me?

Yes, Paul. How are you?

All right. There is some -- on slide 161 of the investor handbook. There is a large pension and OPEB cash flow item of $750 million to $550 million. And I was wondering that wasn’t their last time and I’m wondering what’s the driver in that and why is there a cash benefit associated with that?

Paul, this is Jim. What that slides referring to is that we looked at the discount rate at the end of the third quarter, which we traditionally do and we say what would be change to our GAAP earnings be, if that discount rate remain in effect till December 31. So what that’s representing is a discount rate that goes from 5% down to a range of either 4.25% to 4.5%. That also takes into account a change in the mortality tables where the liability increases by 4%. So that’s not a cash flow benefit, its just a change in the liability of our pension plan that we would have to report the impact to GAAP if the discount rates stays where it is today.

Okay. So, I mean, so in the sense, reconciliation of net income GAAP to FFO, this is a non-cash reversal.

That’s correct.

So, I guess, okay. I’ll have to follow up offline, I guess. And the deferred taxes in ITC that went down by about $190 million, anything in particular there?

This is Jon. This is primarily just utilization of some of our NOLs that are making up the difference. So that’s primarily the largest driver.

I mean, just two back on the CES EBITDA, there seems to be an other income decrease on slide 136 and I’m just wondering, what’s the driver there in 2016?

That’s primarily lower earnings from some of the investments we have. We have an equity interest in a couple of different investments and we’re seeing lower earnings in that period, so that’s going to drive that down.

Okay. Thanks so much, guys.

Okay. Thanks everybody. Thanks for joining us today. If you didn’t have a chance to ask your questions, please contact our IR Department. We look forward to seeing many of you next week at the Annual EEI Financial Conference in Dallas. As you heard today, we’re making solid progress on the initiatives that the designed to deliver predictable and sustainable growth at our regulated distribution and transmission businesses. And you will hear more at EEI of our future transmission investment opportunity. In our competitive business, we’re implementing a sound strategy to reduce risk, while positioning the business for the future. At the same time, we continue to strongly advocate for market reforms that can better support much needed price stability and service reliability and we’re pleased to see growing momentum in support of these changes. We’re building a foundation for long-term value and growth for our investors and we appreciate your continued support. Thanks and look forward to seeing you in Dallas.

Thanks everyone.

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