Greetings, and welcome to the FirstEnergy Corp. Second Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Meghan Beringer, Director, Investor Relations for FirstEnergy Corp. Thank you. Ma'am, you may begin.

Thank you, Brenda, and good afternoon. Welcome to FirstEnergy's second 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 and 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 on our website at www.firstenergycorp.com/ir. Participating in today's call are Tony Alexander, President and Chief Executive 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.

Thank you, Meghan. Good afternoon, everyone. I'm glad you're with us. Today, Jim and I will provide an overview of second quarter results, an update on operational and regulatory developments and a review of the progress we are making on the financial plan we outlined earlier this year. I will also take this opportunity to clarify several topics that seem to be on the -- seem to be on our investors' minds, which I believe have put undue pressure on our recent stock price. We'll begin with a look at our financial results. Today, we announced solid second quarter non-GAAP earnings of $0.59 per share. These results are in line with our expectations, and we are also reaffirming our 2013 non-GAAP earnings guidance range of $2.85 to $3.15 per share. While I'm pleased with our second quarter performance and our outlook for the remainder of the year, the PJM capacity auction results for the 2016, 2017 period were disappointing. As in the past, we are not disclosing the number of megawatts from our competitive business that cleared the auction. However, as has been the case in other recent auctions, not all of our generating units cleared. Respecting the PJM auction, I believe that there are significant and fundamental flaws in the process. These flaws will not only impede investments in competitive generation resources and the development of a robust competitive market, but will also, ultimately, impact reliability. We will continue to work with PJM and others to address these flaws, and in some cases, loopholes that encourage gaming the system. In the meantime, however, and in the wake of these auction results, we are taking additional aggressive steps to further reduce our costs and improve operational performance. We have thoroughly evaluated the economics of each of our plants as a…

Thanks, Tony. As we walk through the second quarter results, you may want to refer to the consolidated report, which was issued this morning and is available on our website. As Tony mentioned, our strong results were solidly in line with our expectations. Non-GAAP earnings for the second quarter of 2013 were $0.59 per share compared to $0.60 per share in 2012. On a GAAP basis, this year's second quarter results were a loss of $0.39 per share compared to earnings of $0.45 per share last year. The full list of special items that make up the $0.98 per share difference between GAAP and non-GAAP second quarter 2013 results can be found on Page 4 of the consolidated report. Most significant of these is $0.85 per share related to plant deactivations. Other special items for the second quarter include: trust securities impairment of $0.05 per share, debt redemption cost of $0.04 per share, regulatory charges of $0.02 per share and a decrease of $0.02 per share related to merger accounting for commodity contracts. Let's turn now to the results from our business units. We'll begin with distribution deliveries, which added $0.02 per share due to a 3% increase in residential deliveries. Overall, distribution sales decreased by 325,000 megawatt hours, or 1% compared to the second quarter of 2012, as the increase in residential sales was more than offset by a 3% decrease in commercial deliveries and a 2% decrease in industrial sales. Typically, when we speak of the weather impact on residential distribution deliveries, we are looking at heating and cooling degree days. This quarter, the discussion is a bit different because, while second quarter temperatures were warmer than normal, they were significantly cooler than the 2012 period. However, the month of June was more humid in 2013 than in…

[Operator Instructions] And our first question comes from the line of Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Listen, I wanted to dig a little bit more into the $150 million to $200 million of savings. And, Tony, I appreciate it's still a bit early in the process, but can you maybe help bucket out what fits into kind of capital savings relative to O&M savings, given all the efforts you guys have done in the last couple of years already to bring cost down and capital out of the business?

Dan, this is Tony. When you think about it, it starts off all as an expense reduction. But a big part of our expenses end up being capitalized because it's all people-related. So it's going to really turn out to be a function of whether or not the workload and how it gets allocated -- is just going to be a question of whether or not that $150 million is going to be allocated to expense because that's where the individual would have or is working on, or whether that will be moved over to capital because of that same rationale. This isn't capital in the sense that we're delaying projects or eliminating projects. These are real cash savings that will then get allocated depending on where our people are working and what projects we're working on during the time frame. Dan Eggers - Crédit Suisse AG, Research Division: So how much headcount reduction goes into this, then? Because that's -- I mean, it's a lot of efficiency gains relative to your cost base.

I'd say, Dan, we said that there would be about 250 positions that would be eliminated. Some were not filled, and that was in addition to the 380 positions that were associated with the deactivation of those plants. I think the bigger cost item will be the elimination of some of our benefit cost. It's a bigger cost reduction than just the staffing in itself, Dan. So I would say that would be the more significant component of the cost reduction. Dan Eggers - Crédit Suisse AG, Research Division: And this doesn't -- this is separate from the money you're saving from Hatfield and Mitchell closing, right?

That right, that's right. What I would say the O&M savings associated with Mitchell and Hatfield, that would align with the several-cent incremental earnings per share. Dan Eggers - Crédit Suisse AG, Research Division: Okay. I got it. And then, I'd ask just maybe 1 more question on this, is that if you think about, kind of, from an O&M inflation perspective, net of these benefits, what should we think about, from a '13 baseline, will be the O&M inflation for FirstEnergy on a consolidated basis?

I guess, Dan, we're going to wait and give you that next year or later this year when we give you 2014 guidance. Obviously, we'll be looking at all of our costs, not just the ones that we've dealt with here. But fundamentally, each and every time we go about developing what our game plan is for the upcoming year, we'll scrub all of the numbers and determine where best to spend our available cash.

Our next question comes from the line of Brian Chin with Bank of America.

Question, you have in the release a reference to net MISO and PJM transmission costs. What is that? And can you talk about whether transmission rights and underfunding, is that the issue that you are referring to in that, similar to one of your peers earlier this earnings season?

Brian, this is Donny. Let me talk about the FTRs first because that seems to be a hot issue. Like many of the other PJM market participants, we also have experienced FTR underfunding. However, as we went into this year, we had adjusted our hedging strategy to be less dependent on FTRs. So versus our expectations, the impact has been very minor. If you think about what's going on there, what's driving this underfunding, there is a whole myriad of issues. There's the themes issues between MISO and PJM. There's the difference between what you would anticipate from kind of an infrastructure perspective, when the FTRs are allocated versus what actually occurs with outages and that sort of thing. And then, obviously, differences between how the day-ahead in real-time congestion is settled. I think we also released that we, in fact, filed a complaint with FERC back in 2011 to try and address these issues, and that case is still pending. We are seeing funding coming in, about 75% to 85% of what we feel we're entitled to. So we believe we're being shorted somewhere in the neighborhood of 15% to 25%. So while versus expectations, it's a very minor impact to us, on a year-to-date basis, we believe our revenue was off for about $6.5 million, about $0.01.

Okay. And so that's not the MISO, PJM transmission issue, it's a separate issue. Understood.

That's correct.

And then, with regards to the cost cuts, just jumping back on Dan's earlier question. Is there a breakdown you can give to what extent those cost cuts are related to deregulated operations versus regulated operations?

No. Right now we don't have that breakdown, Brian. And as a Tony said, we're going to incorporate that into our 2014 plans and we'll probably be able to give a little more clarity then.

And our next question comes from the line of Julien Dumoulin-Smith with UBS.

So quick question. It seems that there's been a little bit of a change in tact with regard to regulated rate base growth and positioning of the company. Could you, perhaps, confirm that and, perhaps, speak to what a new rate base growth trajectory could be prospectively, given some of the spending ambitions you guys spoke about on the distribution side?

Julien, I wouldn't necessarily describe it as difference. I mean, I -- we've always invested heavily in our regulated operations. The fact is, however, that as you look to the future, that there are probably stronger returns available, and more predictable returns available, from shifting investments towards transmission and other items as opposed to investing in generation assets. That's kind of a decision we make all the time in the business. The growth opportunities in transmission and distribution, we're looking very closely at. You've kind of -- I tried to give you a sense for the type of opportunities that are in the transmission business. I wouldn't necessarily say they are the same types of opportunities in the -- one-off opportunities, if you will, in the distribution business, but they are significant in the distribution business if, in fact, we start to, perhaps, accelerate smart meter technology throughout the system. The timing is going to be dependent, in large measure, on when we believe it's time to begin to expand rate base in those areas and take advantage of those growth opportunities.

Okay. So still not quite clear yet, but stay tuned. Perhaps, looking at the back of the regulated -- unregulated side, rather. The latest RPM auction, while you guys didn't want to disclose how many megawatts cleared kind of indicatively, if you would, in the latest auction relative to the last, how significant was the change in cleared capacity? Do you get what I'm asking? If you can provide anything.

Nice try. That's pretty good, though. Since you didn't know the first one or the second one, I don't really know how to answer that. The question was clear, though. You guys are getting better at this.

Our next question comes from the line of Jonathan Arnold with Deutsche Bank.

Tony, you may have sounded more enthusiastic about the economy than you have in a while. And even though the numbers -- the sort of sales numbers, were not -- we're not seeing it in the numbers, can you just sort of give us some more insight into what you're seeing in the customer base? And what's the basis for your commentary in the prepared remarks?

Yes, I think what we're seeing, basically, Jonathan, is -- we think the bottom is behind us now. Most of the plants that we think were particularly exposed, for example, the Ford Brook Park plant we talked about and that 1 steel operation, they were closed in 2012, and we're starting to see that the other items are up significantly. Some of the other steel mills that we have are up. So once you get kind of through this period that we think now is bottomed out, we're seeing some -- we're seeing really strong growth in shale areas, in steel-related, particularly item -- particularly, steel mills that are operating in the pipe-related types of activity. Like I said, housing starts are up. It's a slow start, but it's far more positive than what we've seen in the past. And we're starting to see some activity across each segment of the business. Are you still on? Hello?

Yes, I'm sorry, Tony. Hit the mute button. You mentioned the accordion facility at the parent to upside that line $500 million. Does that have cost implications?

No. It really doesn't have any cost implications other than you get, always, a charge for your unused capacity. So you have very minor incremental cost associated with it.

Not something we're going to notice, then, Jim?

Say that again, Jonathan?

Not something we're going to notice?

No, you will not notice it. No.

And our next question comes from the line of Paul Patterson with Glenrock Associates.

I was wondering, just -- sorry to be a little slow here but Brian, I think, was asking this. What is the PJM, MISO transmission cost? What is causing that? Because it was also a thing that hit you guys had in the first quarter as well?

Yes, I think, Jonathan -- this is Donny. The biggest driver there is just increased sales. I mean, we have to pay network transmission to deliver our product, in many cases. And so that's the biggest driver, but we'll net some other things against that.

Okay. And then, the net financial sales and purchase, what was that? The $0.02 there?

Yes, that's basically, when you look at that, we're hedging -- that's one of the instruments we use to hedge the congestion. So we'll do a financial sale and a financial buy to hedge the congestion, and that's the net of the 2.

Okay. And then, just in terms of the nuclear expense, with the steam generators and everything, just -- is there any flexibility on that? You did mention that you were thinking of, potentially, augmenting the CapEx going forward. And I was just wondering, given market conditions and everything, whether there's been any change or any thought process on that, if there is any flexibility on that.

Those steam generators, you're probably referring to the Davis-Besse that we're planning in '14; and then, we also have Beaver Valley 2 that's in '17. And although you could move that, it's very unlikely that we would because you have a pretty laid out schedule right there that you've got to meet and then you also got to plan what your outages are. So I think it would be very unlikely that we'd be making any modification to that construction schedule.

Okay. Great. And then, just finally, with respect to the cost savings and stuff, you mentioned a lot on the benefit side and what have you. And I do see that the retirement benefit sort of noncash -- impact on the cash flow statement has sort of increased. Is that the kind of thing that we should be thinking about? Should we be thinking about this as being one of those things that over the long term provides savings but in the near term, that sort of accelerated in terms of the noncash accounting benefit because of the OPEB and the pension liability are lower?

No, I think the ones that we're talking about today, while there could be some impacts there, the ones we're talking about today are fundamental changes in plans. Single administrator, as an example. Changing in plans that have higher deductibles. Things of that nature are driving the real change and the cost savings.

So it will have a direct cash impact pretty quickly, it would sound like, starting in 2014?

That's what we're expecting, yes.

Our next question comes from the line of Steven Fleishman with Wolfe Research.

A couple of questions. Just on the equity issuance through the DRIP programs, is that just a 2013 -- or do you intend to continue new equity through DRIP after '13?

At this point, we would expect that this would continue throughout next year. And as we said, it would be about $100 million on an annual basis, Steve. So you won't see $100 million this year. It probably won't really get implemented until probably by the fourth quarter of next year. But we would expect that to continue into next year.

Okay. So from a model standpoint, like, just assume $100 million per year, really, starting in '14?

That's correct.

And then on retail margins, it sounded like, if I heard it, you said that maybe you're actually seeing improving retail margins. Because it seems like most other people keep complaining that retail margins are declining. So maybe you could just give some color. Just clarify kind of what you are seeing on retail margins? And maybe, is it that you're targeting this different customer base or why do you think it might be very different than what we're hearing from others?

Yes, Steve, this is Donny. I think it is the way we're pushing into the different channels. I think over the last several years, we have talked about our multichannel approach. And some of those channels are harder. I mean, retail sales, residential retail sales is much harder than selling to a big C&I customer. Generally, you get stronger margins there. You have to be very careful about your cost to acquisition. But if you think about, for example, our $0.07 for 7 years, in today's market, those contracts are paying very nice margins to us. In general, I think right now we've sold about 75 terawatt hours forward for 2014, and we're seeing an aggregate rate, about $1 better than what we're delivering this year. I think this year we're right about that $53 a megawatt hour. Next year, what we've got booked so far, will produce something right around $54 a megawatt hour.

Okay. And then, my last question is just on the -- you mentioned the Hatfield shutdown and Mitchell that's about a 10% reduction in megawatt hours, but obviously, a lot of cash flow benefit from that. The Other savings at generation in terms of cash flow, I mean, is there any additional impact on megawatt hour production? Or should we assume about that 10% reduction just from those plants?

Yes, I would assume it's probably about 9.5 to 10 million-megawatt hours that would be associated with the Hatfield and Mitchell. So that's what I would assume for that.

But the other cash flow savings that you mentioned don't have any associated reduction in megawatt hours?

No, no, no. That's correct.

Our next question comes from the line of Stephen Byrd with Morgan Stanley.

I wanted to just talk about the credit position and the equity needs. Regarding Harrison and the asset transfer, if that were to not be approved, how would that impact your thinking about equity requirements?

I don't think that it would change our thought process on equity at all.

We've laid out our game plan for equity. Those will not affect our decision-making.

Okay. So a -- the period to get that transfer of Harrison would not -- wouldn't impact that, okay.

No.

Okay. And then, just switching over to transmission, you had mentioned a lot of potential growth. As you think about the financing and structuring of that, do you think much about different options in terms of how to finance that? Some folks have thought about a pure-play transmission approach or is this something we should just assume would very likely just continue to be funded sort of organically within FirstEnergy?

My sense is that we will look at a number of different opportunities and determine what's in our best interest and our shareholders' best interest going forward.

Okay. So that is something that you are -- you do think about a variety of options there? It's not set in stone that it will always be simply funded within FirstEnergy?

I think that's a fair statement, yes.

And our next question comes from the line of Ashar Khan with Visium.

Tony, I just wanted to recap what I heard, so I apologize if I might be repeating some things. One thing you said is that the generation transaction would be at least a couple of pennies or more accretive to EPS starting next year, 2014. I think -- so the other thing that came out is that there's $875 million of reduction in CapEx over this time horizon of MATS. And if I can get what that is -- over what period, is it 3 years? 5 years? I forget what the time frame of that is. Thirdly, you mentioned about $150 million to $200 million of lower cost reductions. These are additional stuff. And if I'm right, you mentioned that a lot of them would be related to retirement benefits. And if I'm hearing that's lower deductible and everything. If I'm right, those would mean lower, I guess, pension or retirement costs, if I understand rightly, what was described in the Q&A. If I can get a little bit of a clarifications on what I said, if they are on the right track or not on the right track?

Okay. Well, let me deal with the first one, since I only said it's accretive. I think Jimmy said it's, what, a couple of cents?

Yes.

So I think the couple of cents is kind of what you ought to be thinking about. The $875 million reduction in capital, I think that's -- was that 5 years? Over that 5-year time frame. With the bulk of that coming in the earlier years, the time when the MATS expenditures would be coming through. And with respect to the $150 million to $200 million, I think you're a little confused. The bulk of these expenditure or bulk of these savings relate to current employees. Somebody raised a question with respect to retirees, but the fact of the matter is, the medical plan benefit changes and the other change that we are contemplating in benefits and otherwise, are really related to the current benefit package we offer employees.

Okay. Fair enough. And then, if I heard, we might get 2014 outlook this year at EEI or is that what we should look forward to?

We'll give it to you when we're ready.

Our next question comes from the line of Angie Storozynski with Macquarie.

I have 2 quick questions. One is the $54 per megawatt hour margin for the retail business for 2014. Is that really comparable to the margins from this year, given that there's a change in mix? For instance, between retail and C&I sales?

Yes. I think it's very comparable. I mean, if you think about what the markets have done as we booked those sales, the wholesale markets have dropped off fairly steadily over the last several years. And to be able to deliver a higher aggregate rate, I think is significant.

No, I'm actually more asking about, if there is, like, a significantly higher SG&A expense associated with those sales compared to the sales that are being executed this year?

No. No, generally, I think, Angie, what you'd see is our SG&A expenses have come down. I would especially point to fuel, for example, has come down significantly based on the work we did last year.

Okay. And secondly, I know that you're still in the midst of the hydro asset sales process. But can you at least give us a sense of, at this stage, your expectations for the outcome of that sale as similar to expectations that you had earlier in the year?

Yes, I think, at this point, Angie, we had the first round of indicative bids. We had a lot of interest in the hydro assets. We're in the process now of narrowing that down, and we're continuing to evaluate that. So I don't think there is any change at this point. Okay. Thanks, everybody. Thanks for participating in the call and your continued interest in FirstEnergy. Thanks.

Bye now.

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