Peter Sena - Senior Vice President of Operations for Nuclear Division William D. Byrd - Chief Risk Officer and Vice President of Corporate Risk Anthony J. Alexander - Chief Executive Officer, President and Executive Director Irene M. Prezelj - Mark T. Clark - Chief Financial Officer and Executive Vice President Harvey L. Wagner - Chief Accounting Officer, Vice President and Controller

Dan Eggers - Crédit Suisse AG, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Paul Patterson - Glenrock Associates LLC Greg Gordon - ISI Group Inc., Research Division Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division Dan Jenkins - State of Wisconsin Investment Board Unknown Analyst - Raymond M. Leung - Goldman Sachs Group Inc., Research Division

Greetings, and welcome to the FirstEnergy Corp. Third Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Irene Prezelj, Executive Director of Investor Relations for FirstEnergy Corp. Thank you. Ms. Prezelj, you may begin. Irene M. Prezelj: Thank you, Melissa, and good afternoon. 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 on 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; Harvey Wagner, Vice President and Controller; Jim Pearson, Vice President and Treasurer; Bill Byrd, Vice President of Corporate Risk; Pete Sena, President and COO of FirstEnergy Nuclear Operating Company; and Ron Seeholzer, Vice President of Investor Relations. I'll now turn the call over to Tony. Anthony J. Alexander: Thanks, Irene, and good afternoon, everyone. Thank you for joining us today. I will provide an update on our merger synergies, the progress with our retail strategy and more details about the expected impact of environmental regulations. Then, Mark will provide an overview of our third quarter results and our progress towards our key financial initiatives, including debt reduction, asset sales and our liquidity position. But before I get started, I'm sure you're all interested in an update on our Davis-Besse nuclear power station, so I'll address that first. As you know, we began a scheduled outage on October 1 to install a new reactor vessel head and complete other maintenance activities at the unit. After we opened the shield building, we identified hairline cracks in the building's architectural elements. Our team has determined that this cracking does not affect the structural integrity of the shield. During our investigation, we also identified other indications, included among them were subsurface hairline cracks in 2 areas of the shield building, similar to those found in the architectural elements. While our overall investigation and analysis continues, we currently expect to safely return Davis-Besse to service around the end of November. I'll note that we have had a good dialogue with the NRC throughout this process. Respecting the remaining outage work, this past weekend, the new reactor head was transported into containment, and our other outage activities are about on schedule. We'll continue to keep you advised and informed of our progress. Turning now to a review of earnings and our strategic initiatives. Today, we reported solid third quarter results, and I continue to be pleased with the progress we are making toward our goals. While the economy, obviously, still isn't where any of us would like it to be and power markets reflect the continued excess capacity in our region, we are making progress and expect to be well positioned to benefit as conditions improve. Based on our strong third quarter results and our continued confidence in our business strategy, we are reaffirming this year's non-GAAP earnings guidance of $3.30 to $3.50 per share, as well as 2012 and 2013 non-GAAP guidance of between $3.20 to $3.50 per share. Let's look now at our merger savings progress. The Allegheny integration process is going very smoothly. The assets and the people are a very good fit with our organization, and we remain on track to capture the level of synergies we have previously identified. Through the end of the third quarter, we have completed merger-related initiatives that will allow us to capture approximately $165 million in pretax benefits this year. That's nearly 80% of the merger-related savings we expect to achieve by year end. I'm pleased with our solid execution in this area. At FirstEnergy Solutions, we continue to expand our retail sales, particularly in the direct commercial and industrial channels and in governmental aggregation. We recently added new communities in both the AEP Ohio and Commonwealth Edison service territories, and FES continues to champion new governmental aggregation opportunities. More than 100 communities in Ohio, representing nearly 500,000 households and 15,000 small commercial businesses have governmental aggregation issues on November ballots, including the cities of Cincinnati, Canton, Findlay and Newark. Of course, the outcome of the AEP-ESP case will determine if communities in that service area will be able to take advantage of the program due to the provisions that would effectively limit competition in that service territory until 2014. That decision will impact more than 60 communities that have valid issues up for vote next week. Also on the regulatory front in Ohio, we were 1 of about 25 key stakeholders in the Duke-ESP case signing on to a comprehensive settlement agreement last week. In contrast to AEP settlement, the Duke plan provides generation via market-based competitive supply and provides unrestricted access to shopping for all of its Ohio customers. This is very similar to FirstEnergy Ohio utilities plans, and if the commission approves the settlement, over 50% of Ohio's retail electric customers will have unlimited access to the benefits of competitive markets. Moving now to other recent developments, starting with new environmental regulations. As we analyze the impact on our company of CSAPR, the Cross-State Air Pollution Rule that addresses SO2 and NOx, we continue to believe we are well positioned to address these environmental requirements as a result of the investments we've already made at our supercritical units. And even though our compliance plans are not yet finalized, our emission allowance positions for both SO2 and NOx are such that we are able to offer some of that inventory to the market through a competitive bid process expected to be conducted later this month. Respecting the pending maximum achievable control technology rules for mercury and hazardous air pollutants, we still expect investments of about $2 billion to $3 billion in our generation fleet to comply. Our investments are expected to primarily focus on reducing mercury, and particulate emissions at our supercritical units. Again, as I mentioned last quarter, this analysis is ongoing. We do not plan to make any final decisions or announcements about plant status until after we have thoroughly evaluated the MACT rules and are -- that are expected to be finalized in December and develop a comprehensive plan taking into consideration both the MACT and CSAPR requirements and the results of the allowance auction. Finally, as many of you have experienced firsthand, we've had some very difficult storm season here recently. Our eastern utilities were severely impacted by Hurricane Irene and this weekend's snowstorm. These were unusually challenging events, and our crews encountered some very tough conditions. Hurricane Irene caused major damage and led to power outages for about 1 million customers in our Jersey Central, Met-Ed, Penelec and Potomac Edison service areas. Now many of these same areas are recovering from the rare October snowstorm this past weekend. This storm dropped more than a foot of heavy wet snow in some areas of Northern New Jersey and Eastern Pennsylvania. The snowfall, coupled with strong winds and, in particular, leaves that are still on the trees was especially damaging. We experienced substantially more tribulated outages from broken limbs and falling trees, and in some ways, the damage to the system was even more devastating than the hurricane. Almost 800,000 customers were impacted by this event. Hurricane Irene's restoration costs, primarily for Jersey Central Power & Light and Met-Ed, totaled $78 million. While $53 million of this was related to O&M activities, $50 million of that expense has been deferred for future recovery under existing regulatory practices in New Jersey and Pennsylvania. Due to the extensive damage from the snowstorm, we anticipate that we will need to literally rebuild our system in some areas. While we don't have cost projections yet, we expect the majority of those expenditures to be capital in nature with most of the rest of the costs deferred for future recovery. Now I'll turn it over to Mark for a review of the third quarter. Mark T. Clark: Thanks, Tony, and good afternoon, everyone. Today, I will discuss third quarter results, and then similar to last quarter, I will spend a few minutes updating you on our progress against some of the financial targets we outlined during our Analyst Meeting in May. As Tony mentioned, we delivered strong results during the quarter. Excluding special items, third quarter 2011 non-GAAP earnings were $1.34 per share compared to $1.28 per share in the third quarter of 2010. On a GAAP basis, this quarter's earnings were $1.22 per share compared to $0.59 per share in the same period last year. As I walk through our results, it may be helpful for you to refer to the consolidated report to the financial community we issued this morning. On Page 18 of the report, you'll note the list of special items that decreased this quarter's GAAP earnings by a total of $0.12 per share. By comparison, in the third quarter of 2010, special items decreased GAAP earnings by $0.69 per share. And as a reminder, the 2010 reduction was primarily related to the impairment of several of our smaller coal-fired plants. The largest in the third quarter 2011 special items was a $0.06 per share reduction related to purchase accounting for commodity contracts. Additionally, non-core asset sales and/or impairments reduced earnings by $0.02 per share. Finally, there were 4 items that each reduced GAAP earnings by $0.01. They are the impairment of nuclear decommissioning trusts securities, merger costs, mark-to-market adjustments and, finally, the resolution of litigation. Having outlined the special items, let me discuss our third quarter drivers. I'll start with 4 items that had a negative impact on results. The first of these is $0.06 per share in higher O&M expense, and I'll take a moment to describe the O&M drivers. The first was related to generation outages, including outage preparation costs at Davis-Besse and expenses associated with outages at our Fossil plants. The other significant O&M item in the quarter was higher incentive compensation expense. As a reminder, this expense may go up or down depending on how successful we are in achieving our financial and operating targets, including goals related to increasing shareholder value. The actual progress affects the timing of expense recognition during the year. And finally, as Tony mentioned, O&M costs related to Hurricane Irene had minimal impact on third quarter results. Moving now to the second negative driver of third quarter results, financing costs primarily due to lower capitalized interest related to the completion of the Sammis environmental project reduced earnings by $0.05 per share. Third is the $0.02 per share and higher depreciation expense, reflecting the placement of the Sammis air quality control projects in service at the end of 2010. The Sammis impact was partially offset by the reduced depreciation expense related to the impairments of the Lake plants and the retirement of Burger in 2010. And finally, general taxes decreased earnings by $0.01 per share. Turning now to positive drivers of our third quarter non-GAAP results. Let me start with the merger, which continues to be accretive to earnings. The $0.35 per share impact of shares issued in conjunction with the transaction was offset by the $0.32 per share contribution from Allegheny and $0.04 per share from the impacts of purchase accounting. As Tony mentioned, we continue to be pleased with the integration of Allegheny, and we believe that we are solvently on track to achieve the benefits we expected from this combination. Second, commodity margin was an overall positive driver this quarter, increasing in earnings by $0.19 per share. However, there were several pluses and minuses within commodity margin, and I will detail those now. You can find a detailed summary of this on Pages 2 and 3 of the consolidated report, including additional information on megawatt hour volumes. Generation output for the quarter was 4% below the third quarter of 2010, or 905,000 megawatt hours. This decrease resulted primarily from the extended outage to repair the generator at one of our Sammis units, which I would note was successfully brought back online in late July. Looking at the positive elements of commodity margin, there were several moving parts in the fuel area this quarter. The decrease in generation output contributed to lower fuel expense, offsetting the trend of higher overall fuel costs, and we particularly benefited from the restructuring of a long-term fossil fuel contract. In previous discussions, our ability to extract fuel savings due to the substantial size of our generation fleet was identified as a potential major benefit of the merger. Subsequent to our closing the transaction last February, we have spent considerable time at FES addressing our fuel contracts and procurement, and we are now starting to see the benefit of those efforts. As I mentioned earlier, we began a fairly comprehensive RFP process on the Fossil side. Recently, we negotiated several new agreements, completed negotiations related to price reopeners for 2 of our larger contracts and renegotiated a below-market, long-term fuel contract. For the quarter, we realized an $0.18 per share benefit. So we are very pleased with our solid progress to contain fuel expenses, and we remain on track to hold our fossil fuel expense to $28 per megawatt hour for the year. Commodity margin also benefited from higher capacity revenues for our generation fleet in connection with transitioning the ATSI zone from MISO to PJM, a reduction in purchase power prices and fewer bilateral purchases. And sales of renewable energy credits increased slightly despite higher costs imposed by renewable obligation requirements. Negative drivers of commodity margin included increased capacity expense as a result of FES serving more retail load, higher congestion, network and transmission line loss expense in PJM, lower contract generation sales as FES continues to successfully execute its strategy of reducing POLR sales as it increases to serve more retail customers and a 23% reduction in FES wholesale electricity sales. Looking at the FES sales position, our direct sales force continues contracting 2012 sales and currently stands at 85% of that target, while 2013 sales are at 47%. Now turning to distribution deliveries. Deliveries were up 2% overall with a 6.5% increase in industrial deliveries. A slight decrease in the still nagging commercial market offset a modest increase in residential sales. Third quarter cooling degree days were 2% lower than in 2010 but 30% above normal. Third quarter industrial sales growth was driven by a 9% increase in demand from steel manufacturers, which are benefiting from the demand related to the Marcellus Shale drilling, while the automotive segment is down 3% year-over-year. We've seen certain pockets in that sector continue to grow, such as the Lordstown, Ohio, GM plant, which manufactures the Chevy Cruze and is now running 3 shifts in overtime. But we also saw the closure of a Ford plant in Ohio at the end of 2010. While the increase in distribution deliveries had no material impact on earnings compared to the third quarter of 2010, the industrial growth is encouraging and certainly consistent with our earlier expectation that industrial sales will continue to increase in the second half of the year. Through the third quarter of 2011, industrial sales were up 4%, and what's even more encouraging is that industrial sales for the first 9 months of 2011 are only 1% lower than the same period of 2007, which was the peak industrial sales year. Moving now to an overview of our progress towards our financial targets. This spring, we described our plans to deliver solid financial results in 3 ways. Consistent earnings, positive cash flow and an improved balance sheet. Additionally, we outlined our strategies to grow our competitive business and achieve benefits from the merger. I am pleased to report, we continue making solid progress executing our strategy on all fronts. As we stated on our second quarter earnings call, we narrowed our guidance for 2011 non-GAAP earnings to $3.30 to $3.50. We remain confident in that guidance, and as Tony outlined, we are very pleased with our progress to capture merger synergies. We fully expect to be right on the annual merger target of $210 million by the end of the year. Looking at debt reduction. Through September, we have reduced long-term debt and short-term debt by about $1.7 billion. In addition, we expect to reduce debt by an additional $700 million in the fourth quarter, which includes the deconsolidation of debt associated with Signal Peak, bringing the full year total to approximately $2.4 billion. The restructuring in renewal and completion of our $5 billion revolving credit facilities provide us a significant level of liquidity, which stood at $5.7 billion as of the end of last week. With regard to the divestiture of non-core assets, we have completed the sales that we outlined in May, and we are extremely pleased with the outcome of these transactions. We reported the Fremont sale last quarter, and 2 weeks ago, we completed the divestitures of the Richland and Stryker units and our share of interest in the Signal Peak coal mine located in Montana. The Signal Peak deal is complex, so I'll spend a few minutes on it. As we reported on October 18, a subsidiary in the Gunvor Group, one of the world's largest leading commodity traders, purchased a 1/3 interest in the coal mine for $400 million. This transaction has a number of significant benefits. On the financial side, we received $260 million of the proceeds. Further, the transaction will allow us to deconsolidate Signal Peak from our balance sheet, which will result in a $365 million debt reduction and a $50 million increase to equity. Finally, a $370 million after-tax gain on the transaction will be recognized in the fourth quarter 2011 GAAP earnings. In total, the combination of equity increases and debt reduction results in more than $1 billion in added strength to our capital structure and moves our balance sheet in a very positive direction. On the operating side, this transaction also maximizes the mine and rail investments, and we will be able to utilize the Gunvor Group's commodity trading relationships including its arrangements with Westshore Terminals in Vancouver to sell more high-quality, low sulfur bituminous coal to such markets as Japan, China, Korea and Chile. As part of the agreement, we have also revised our original coal purchase agreement from 7.5 million short tons annually to an obligation to accept up to 2 million each year of the mine's production. Overall, the production forecast of Signal Peak, including future service operations, is in the range of 10 million to 15 million short tons per year, which can be sold to Gunvor as well as to existing domestic and international customers. In total, the Signal Peak and Richland, Stryker divestitures added more than $340 million to our overall liquidity, and we will continue using that cash to reduce our net debt position. As you can tell from our financial results, our team remains focused on delivering on our financial commitments, executing our strategy and building a strong foundation for our overall future success. Thanks for listening, and now I'd like to open up to the call for your questions. Thank you.

[Operator Instructions] Our first question comes from the line of Jonathan Arnold with Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Just a quick one on the comments you made about the coal contract restructuring. Mark, I think you had said $28 a megawatt hour would be -- you're on track for that number? Does that include the $0.18 gain effectively in the annual fuel cost? Mark T. Clark: Yes. Jonathan P. Arnold - Deutsche Bank AG, Research Division: And so how should we think about that as we move forward into next year? Is there a kind of annualizing effect? Are you anticipating further restructurings? Mark T. Clark: Yes. We have a number of fuel contracts in the process of being restructured and, of course, we're always open to restructuring coal contracts. So the short answer would be yes. Jonathan P. Arnold - Deutsche Bank AG, Research Division: So we're going to be at this $28 number partly courtesy of the gains on the restructurings? Or is that really where the underlying costs are actually shaking out? Mark T. Clark: I'm not certain I understand. Are you asking if our fossil fuel costs will stay at $28 per share? Jonathan P. Arnold - Deutsche Bank AG, Research Division: You've given this guidance that it stays reasonably flat around that level. Mark T. Clark: Yes, we said that they're going to stay reasonably flat. I think, I would say they're going to be consistent with what we said back in May. Jonathan P. Arnold - Deutsche Bank AG, Research Division: But is that because of the gains on contract restructurings? Or is that because -- does that fade as a factor as you look forward? William D. Byrd: Yes, Jonathan, this is Bill Byrd. At any point in time, there are different drivers to the fuel expense. The $28 will reflect selling allowances one quarter and a contract restructuring the next quarter. It's all part of the fuel expense that we report.

Our next question comes from the line of Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I guess I just had a similar question about the fuel contract. I work out that $0.18 a share on a pretax basis is about $100 million of savings, which works out to about 15% of your fuel expense in the quarter. How much of the $0.18 was a one-off benefit from the restructuring and how much will stay with us in future years? Anthony J. Alexander: Well, I think, Hugh, I guess -- this is Tony. I guess the best way to answer that is we've laid out the expectations for fuel over the next 3 years, and we said they're essentially going to be flat. So we'll be taking advantage of whatever opportunities we have to drive fuel savings, whether it's through restructuring contracts, reopeners or new contracts and -- or changing fuel mixes to maintain that basic cost per megawatt hour that we laid out earlier. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: So this was a below-market contract. Is that right? Anthony J. Alexander: Yes. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: And what -- how did you restructure it to save money? Mark T. Clark: Oh, we took advantage of the price and restructured over a longer term. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Okay, and then you were able to take to earnings this quarter the benefit of the restructuring over the term of the contract? Mark T. Clark: Correct. Yes.

Our next question comes from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Turning gears to Ohio real quick. Could you guys just share your thoughts on kind of how these government aggregation efforts are going to go if AEP's successful in getting their settlement implemented, as they proposed. Anthony J. Alexander: Well, the community will vote next Tuesday. I would expect, if they follow the same pattern as many other communities in Ohio, they're likely to vote in support of government aggregation, because it produces lower prices for them as they gain more bargaining leverage in those transactions. AEP's settlement, as proposed, will likely limit the ability of those communities and those customers to take advantage of the competitive market and/or their aggregation votes that they've put in place. So they're either going to be very much delayed and very much unhappy that they're not going to have those savings as early as they otherwise would, because I don't believe the numbers and caps that the AEP plan has will accommodate very much more shopping. Dan Eggers - Crédit Suisse AG, Research Division: So how do you guys go about trying to pursue those customers in the absence of a final resolution. Do you guys sign nonbinding contracts? Or is it something that -- an option that is going to kind of pass from your opportunity because you don't know what's going to happen with AEP? Anthony J. Alexander: Well, I think we try to work with the customers. Some of the communities were -- obviously are working today on whether or not if they get the legislation -- legislative authority to move forward. They are further along the path. Other communities are probably waiting until -- to determine whether or not the voters support it. And then you'll have to put that in the space of whether or not they will qualify under the AEP plan. Obviously, the plan, if the Cincinnati plan or the synergy plan is approved, Duke Ohio's plan is approved, then those communities will have access to the competitive markets as early as January 1. Mark T. Clark: Dan, this is Mark. I would only add that in some cases our retail people are helping the communities, organizing around what it takes to aggregate, what it takes to get it on the ballot and building relationships in anticipation of hopefully the success of those ballots. Dan Eggers - Crédit Suisse AG, Research Division: If there is a delay in shopping in AEP's territories, is that going to affect your targets kind of over the next 1 or 2 years as far as what your customer mix is going to look like relative to what you guys laid out this spring? Anthony J. Alexander: No, we have a lot of places to sell whether that's moving towards west into Illinois or further east into PJM, and as you know, that was one of the benefits of the Allegheny transaction itself. Dan Eggers - Crédit Suisse AG, Research Division: Okay, and I guess just one more question. I hate this to be an AEP conference call, but the idea that they can build generation in array base and kind of just subvert the competitive process is laid out by PJM in the settlement. How do you guys see that playing out? And is there a prospectively a legal challenge you can pursue if they are successful in getting that put into their settlement? Anthony J. Alexander: Dan, there's a lot of avenues that you can pursue with that type of proposal. The -- obviously, the very first hurdle is they still have to meet the requirements in the state of Ohio, which says you have to have a need in order to be able to justify that type of process, and I suspect that need is going to be -- will be highly challenged and very difficult to prove when you don't have an obligation to serve. Mark T. Clark: And I would add, Dan, participating in auctions outside your own service territory.

Our next question comes from the line of Greg Gordon with ISI Group. Greg Gordon - ISI Group Inc., Research Division: The hairline cracks on the architectural element of the Davis-Besse stuff, I understand, that's clearly not an issue that pertains to the viability of the point of having it there, but what about the other cracks you found? Can you elaborate a little bit on that and explain why there will only be a modest delay in the restart? Anthony J. Alexander: Well, we haven't even talked about a delay at restart at all as far as I know. We think we'll be able to resolve the other indications that have come up and still are holding at this point to a restart date by the end of -- or towards the end of November. Greg Gordon - ISI Group Inc., Research Division: So logistically, what is the sort of process for determining that you can continue on your current schedule and get restarted on schedule? Like, what has to happen for the NRC to sort of sign off on that? Anthony J. Alexander: In the main, this is going to be evaluated by Davis-Besse experts as well as experts we've brought in from the outside, and we'll be looking at it as part of our CAPS (sic) [CAP] program to reach resolution in much the same way we've pretty much reached resolution with respect to the architectural elements at this point. The evaluations are continuing, and again, at this point, we see no reason to believe that this unit will not be back online by the end of November.

[Operator Instructions] Our next question comes from the line of Paul Patterson with Glenrock Associates. Paul Patterson - Glenrock Associates LLC: Just to get an idea here with the restructuring of the coal contract and your sale of the coal mine interest. Are you guys thinking that perhaps coal prices might be declining and that this is a good time to monetize? Or is there any outlook that you guys have on that with respect to these activities? Or is it just sort of -- they just coincide with each other and... Mark T. Clark: Well, I think we've been fairly consistent with regarding the Signal Peak, that it was non-core and it was never our intent to own it. I would say they were more coincidental than anything, and as you know, we generally don't discuss our view on forward coal prices as viewing that as competitive. But I would say, Paul, it was more of a coincidence that they occurred at the same time. Paul Patterson - Glenrock Associates LLC: And then the second thing is the POLR auction that came out recently in your service territory, any thoughts about what was happening there? And thanks a lot for the shopping statistics that you guys provided in your release, but any more information you can give us in terms of what you're seeing just trend wise? I mean, I saw what your -- what has happened with respect to the retail margin, but just in general, sort of going forward, what you guys are seeing in terms of that? How competition -- if you could just maybe elaborate a little bit on that, the competitive environment that you're dealing with both in the POLR and the retail sales. William D. Byrd: Paul, this is Bill Byrd. As far as the POLR auction, it was clearly competitive. There were multiple bidders and multiple winners. As far as the pricing went, you've got to adjust for the different capacity components. This auction had a much lower capacity component than prior auctions, and there were slight changes in the product in how transmission expense was treated. But when you make that as adjustments, it appears to us that there's a consistency or firming of the energy component of the auction price, which is a positive sign as far as we're concerned.

Our next question comes from the line of Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: So I wanted to follow-up on Greg's question a little bit there. Just in terms of added cost with regards to, call it remediation, if you will, or what have you, at Davis-Besse, how did that look? I mean, you've talked about the schedule, but what in terms of sort of motions do you need to move through, if you will, to get there? Mark T. Clark: Our current analysis shows that the hairline cracks are acceptable as is and will not impact the structural integrity of the shield building, thus, no remediation would be necessary. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: And secondly, you discussed CSAPR and don't intend to update too much. You're ahead of finalization of MACT, but I wanted to get your latest sense first, on your own dispatch; secondly, on accelerated plant retirements and perhaps just on moving forward those or conceptually sort of seeing -- have MACT move forward as proposed currently. And then finally, do you think it's adequately reflected in carryforwards particularly in your regions? Anthony J. Alexander: Well, I'm not going to speculate on what the plans are going to be in terms of how the evaluation will turn out after or whatever the MACT rules are when they come through. Now we're going to take a look at all the information we have, and we'll make the appropriate decision to -- for FirstEnergy at that point. I think it's kind of mixed. We've seen some indications, like Bill talked about earlier, of energy prices seeming to be firming up. I still think it's -- not everyone yet appreciates the impact these rules will have on the generating fleet, and until those become clearer, depending on the individual positions of the generating owners, I think it's hard to say whether or not they're fully reflected in the marketplace. Much of it is going to depend on how fast the economy improves and secondly, what specific actions are taken at specific units and where they are located potentially on the grid and how that might affect market prices going forward. It's pretty complex. My sense is it's not all being factored in at this point in time. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Appreciate it. Then finally, last follow-up, on the prior question, you suggested if Ohio perhaps isn't as available, if you will, given some of the limitations we've discussed, you said looking eastwards. Where would eastwards be, if you will, just to be a little bit more specific in terms of the states of opportunities? Anthony J. Alexander: Met-Ed's service territory in part, but primarily more aggressively in the Penelec, West Penn Power, Duquesne service territory and into Northern Maryland, perhaps into Central Maryland.

Our next question comes from the line of Paul Ridzon with KeyBanc Capital Markets. Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: Have you completed your assessment at Davis-Besse? Or are you still kind of looking around, maybe taking core samples or ultrasound probing? Mark T. Clark: The inspections have wrapped up and we are now completing our evaluation to determine the final acceptability of the hairline cracks. We anticipate having the final acceptability for the 2 remaining localized regions complete by the end of the week. Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: And how should we think about this with regards to the relicensing process? Mark T. Clark: I'm not going to speculate what the NRC may conclude with respect to relicensing the plant. Obviously, operating experience will factor into the NRC's decisions, but that's what our corrective action process is for and our root cause process is engaged with right now.

Our next question comes from Adam Aron [ph] with Millennium Partners. Unknown Analyst -: It's David Frank [ph]. I had a question maybe for you or Mark on how much of the 10 million to 15 million tons of production at Signal Peak, is that the entire mine's output? Is that just what you guys -- attributable to your JV? Or does that include all Gunvor, everything? Mark T. Clark: That's the total output both the underground and the surface mining. That's everything. Unknown Analyst -: And at what point do you -- or is that sort of its maximum output? Would you expect volumes to increase? Is there a target for output from the mine? Anthony J. Alexander: Right now, David, those are kind of the current targets we have, assuming what we believe we can do with the underground operations as structured today, as well as what we believe we can do with the surface opportunities that are in and around that facility. Whether or not it has any greater potential long term, I mean, it's a wonderful piece of property with lots of reserves, and it's just a question of how you deploy and when you go about trying to capture them at any point in time. So right now, this is -- you kind of set your game plan, get the long-term underground facilities in place, allow the markets to develop as well as our ability to ship that coal primarily into Asian markets or elsewhere and then take advantage of that by expanding our operations at that facility to capture those margins available in those markets. Unknown Analyst -: Right. Okay, so you brought me to my next question, which is, I guess, is all 10 to 15 essentially going to Asian markets? You're able to get that out through Vancouver or... Anthony J. Alexander: No, no, no, we're not even at that production level yet. So there's no surface operation yet at Signal Peak, and the mine is -- while the mine is approaching operating at close to that level in terms of close to a 10-million-ton a year level of production, we're not quite there yet. And we're still in a very -- I wouldn't call it the very early stages, but the mine is still going through its development phase. It's not even yet to its longest panels or best panels in terms of the coal seam that we will be accessing the next time we make a longwall move. Mark T. Clark: David, this is Mark. I would just -- well beyond the financial positives of the transaction, I mean, having Gunvor as a partner along with the operating team at the mine gives us an awful lot of optionality in terms of what we can and can't do as the mine continues to develop.

Our next question comes from the line of Raymond Leung with Goldman Sachs. Raymond M. Leung - Goldman Sachs Group Inc., Research Division: A lot of my operational questions were asked, particularly on Davis-Besse, but a couple of finance stuff. Can you talk a little bit about -- I think you've mentioned some debt reduction of $700 million. We have like $360 million tied with the deconsolidation, so does that mean you're going to pay down the whole co debt with cash? And can you talk about the Allegheny Energy Supply maturity and what you guys are thinking about doing there in March? And the last thing is can you talk about any update on potentially combining Allegheny Energy Supply and FE Solutions? And any updated thought process there would be appreciated. Mark T. Clark: Yes, the $360 million deconsolidation, then there's a $250 million whole co debt, which Jim plans on paying down in cash. The AE supply transaction will also be done in cash. And I think your last question had to do with merging the 2 entities together. That's something that's for tax purposes. We're not going to talk about until we get through that period of time. Raymond M. Leung - Goldman Sachs Group Inc., Research Division: And how long is that period for tax purposes? Is that one year? Anthony J. Alexander: Harvey. Harvey L. Wagner: We'll be able to talk about that in 2012.

Our next question comes from the line of Dan Jenkins with State of Winsconsin Investment Board. Dan Jenkins - State of Wisconsin Investment Board: First, just one quick one on the Davis-Besse cracking situation. To return that plant to service at the end of November, do you need to get a go-ahead from the NRC or at this point, is that entirely your decision based on the current circumstances?

Dan, this is Pete Sena. The NRC, as you know, continues to monitor our activities, and they have access to the same facts that we do. No approval from the regulator is required, but of course, we do expect them to review our conclusions. Dan Jenkins - State of Wisconsin Investment Board: Okay, and then I just had a couple of questions on the detailed information you laid out on Page 3 of the release, just how we should kind of think about that going forward. In particular, in Subpart C, you mentioned that June and the increase, the $0.12 there, was in part due to the new capacity revenues beginning June 11. Should that -- will that continue through June of '12 or how should we think about that? Mark T. Clark: I would say yes, but it could go up and down depending on the mix, customer mix, but generally, I would, in short, I would say yes. Dan Jenkins - State of Wisconsin Investment Board: And then similarly, on the fuel expenses. You mentioned that the fuel contract restructuring in the third quarter increased by $0.18 per share, so would that benefit continue through to the next 3 quarters? Anthony J. Alexander: Again, Dan, with respect to that, when we talk about fuel, we talk about -- our target is about -- I think it's $28 a megawatt hour. That's our target for the next 3 years in terms of what our fuel costs are going to be. So this item that occurs this time will be substituted with something else. As you go in time, the whole fuel cost's relatively flat. Dan Jenkins - State of Wisconsin Investment Board: Okay, and then I was curious on the O&M part, you mentioned that, that was divided between outage expenses and I think incentive comp, but since the incentive comp can be kind of lumpy, can you break out what -- how much was for the outages and how much was for the incentive comp? Harvey L. Wagner: Dan, this is Harvey Wagner. I'm going by memory here, but I think the incentive comp was about $0.02 a share. It was about 1/3 third of that. And as you know, that's all based on where we are with regard to our financial and operational targets. As we progress through the year, it can go up or down. Mark T. Clark: I'd like to thank everyone for joining us on the call today. Before we conclude, I'm sure you saw our announcement this morning that Ron Seeholzer has been named Vice President of Financial Planning for FirstEnergy Solutions, and Irene Prezelj has been promoted to Vice President of Investor Relations effective today. I'm confident that Ron's experience, which encompasses public accounting, internal auditing, budgeting and financial forecasting, in addition to his IR responsibilities, will help enhance our financial planning, forecasting and analysis at FES. And I'm sure you recognize that Irene has been a very trusted liaison for the investment community since she joined the IR team in 2008. She has a tremendous depth of knowledge about the company and her promotion ensures a smooth leadership transition in this very important area. As always, we appreciate your continued support and interest in FirstEnergy, and Tony, Ron, Irene and I, along with other members of our team, look forward to seeing many of you at the EI conference next week. Thank you very much for being with us today. Anthony J. Alexander: Thanks, everyone.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.