Meghan Beringer Mark Tanner Clark - Chief Financial Officer and Executive Vice President Anthony J. Alexander - Chief Executive Officer, President and Executive Director Donald R. Schneider - Principal Executive Officer and President Leila L. Vespoli - Executive Vice President and General Counsel

Dan Eggers - Crédit Suisse AG, Research Division Stephen Byrd - Morgan Stanley, Research Division Steven I. Fleishman - BofA Merrill Lynch, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Ashar Khan Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Brian Chin - Citigroup Inc, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division

Greetings, and welcome to the FirstEnergy Corp. Third Quarter 2012 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 of Investor Relations for FirstEnergy Corp. Thank you, miss. You may begin.

Thank you, and good afternoon. During this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor provision of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of FirstEnergy Corp. are based on current expectations that are subject to 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; Leila Vespoli, Executive Vice President and General Counsel; Donny Schneider, President of FirstEnergy Solutions; Jim Pearson, Senior Vice President and Treasurer; Harvey Wagner, Vice President, Controller and Chief Accounting Officer; and Irene Prezelj, Vice President, Investor Relations. I'll now turn the call over to Mark.

Thanks, Meghan, and good afternoon, everyone. Thank you for joining us. With our 2000 earnings forecast being of great interest to many of you, we thought it would be best to start today's call with the financial discussion, then Tony will follow with closing comments on the company and the economy. Before I move to the third quarter review, I'd like to talk briefly about Hurricane Sandy, the most devastating storm in our country's history and its impact on 2.3 million customers in the communities across our entire service territory, no doubt including some of you who may be on the call. Outages related to the hurricane were fully restored in Ohio and Pennsylvania earlier this week, and we are working to complete restoration in our New Jersey, West Virginia and Maryland service territories as quickly and safely as possible. There may be isolated pockets of New Jersey customers located in inaccessible areas or who have individual flooding or down-line issues that will take longer. Yesterday's nor'easter created an additional 120,000 new outages in the areas affected by Hurricane Sandy, and we brought in 1,600 additional crews today to assist with restoration. In addition to nearly 1,000 -- excuse me, 11,000 of our own employees, hurricane restoration has been assisted by almost 9,000 outside crews that were available to us as a result of our membership in 4 mutual assistance organizations: Mid-Atlantic Mutual Assistance, The New York Mutual Assistance Group, Southeastern Electric Exchange and Great Lakes Mutual Assistance. Tony will talk more about the hurricane and its impact in a few minutes. Let's get started with a review of the quarter. Today, we were pleased to report solid third quarter earnings results that are very much consistent with our expectations, including continued growth in retail. Excluding special items, non-GAAP earnings for the third quarter of 2012 are $1.11 per share, compared to $1.39 per share in the same period of last year. On a GAAP basis, third quarter 2012 earnings were $1.02 per share, compared to $1.27 per share in the third quarter last year. Year-to-date 2012 non-GAAP earnings are $2.53 per share and GAAP earnings are $2.20 per share. We are narrowing our 2012 non-GAAP earnings guidance to $3.30 to $3.40 per share, which is the lower end of our previous range. Although we continue to successfully manage our costs and improve retail margins, these efforts have not been able to offset the impacts from the weak economy, which continues to languish much longer than expected, or the weaker sales generally and mild weather this year. As we discuss third quarter drivers, it may be helpful for you to refer to the consolidated report to the financial community, which was posted on our website this morning. Special items are detailed on Page 5 of the report. These 5 items have a net impact of decreasing third quarter 2012 GAAP earnings by $0.09 per share. Special items for the third quarter of 2012 include a $0.02 per share decrease related to tax legislative changes, a $0.03 per share decrease related to merger accounting for commodity contracts, a $0.03 per share decrease from regulatory charges and a charge of $0.04 per share associated with plant deactivation costs. These reductions were partially offset by a $0.03 per share gain from mark-to-market adjustments. As a note, we have normalized the revenues and expenses related to the older coal-fired units that we designated for deactivation as a result of environmental regulations. The Reliability Must-Run units are not being normalized after September 1, 2012. These units are receiving RMR payments from PJM that effectively makes their operating earnings neutral. Now let me move to the main drivers for the third quarter, starting with the positives. The first of these is lower operating costs, which include lower expense associated with ongoing fossil operations; the transfer from expense to capital of utility project costs relating to the alignment of Allegheny's work management system with the FirstEnergy system; and lower energy delivery expenses, primarily due to more devoted -- more work devoted to capital projects in the third quarter of 2012 compared to the same period last year, as well as lower overall non-deferred storm costs across all service territories this year versus last. Earnings also benefited from lower interest expense as a result of recent financing activities, lower depreciation expense due to a reduction in depreciation rates for West Penn Power and lower general taxes primarily due to lower gross receipts. With respect to the negative drivers for the third quarter, they include a higher effective income tax rate, lower distribution deliveries and reduced commodity margin. Distribution deliveries decreased earnings by $0.04 per share, compared to the third quarter of 2011 as overall deliveries decreased 1.7 million megawatt hours or 4%. Commercial deliveries were down 3%. And for the first time in several quarters, we also saw a decrease in industrial deliveries. While there was some growth in the chemical and refinery sectors, industrial deliveries were down 5% overall compared to the third quarter of 2011 as a result of lower steel and automotive production. Finally, residential deliveries decreased by 4% in the quarter. Some of the year-over-year decline in residential consumption can be attributable to weather. Despite the hot summer in much of our service territory early in the quarter, third quarter temperatures were actually about 4% milder on the whole than in 2011. Let's move now to a review of commodity margin, which is detailed on Pages 2 and 3 of the consolidated report. In that report, you'll also find additional information on megawatt hour volumes. Overall, commodity margin had a negative impact of $0.34 per share. As you know, this includes the absence of the $0.18 per share benefit realized in the third quarter of 2011 related to fuel contract restructuring. It also includes a $0.22 per share impact from lower PJM, RPM capacity revenues, which is primarily a result of lower capacity prices that became effective this past June. Excluding those 2 items, third quarter commodity margin increased earnings by $0.06 per share compared to the third quarter of 2011, driven by a 10% increase in competitive contract sales volume. These gains in contract sales once again partially offset energy prices. While overall prices were down about -- down by about $3 per megawatt hour, the net impact to our sales was only about $1 per megawatt hour after adjusting out the impact of lower capacity prices. Looking more closely at third quarter competitive contract sales, we achieved a 9% increase in direct sales driven by growth in Central and Southern Ohio; mass market sales more than doubled, driven primarily by growth in Pennsylvania and in Ohio; a 47% increase in structured sales; a 15% increase in government aggregation sales. In the past year, we have signed on 43 new communities in Ohio and 81 new communities in Illinois. This week's selection governmental aggregation was approved in about 200 Illinois communities and we will be actively participating in the process to make offer to those potential new customers. And finally, consistent with our retail strategy to realign our sales portfolio, solar sales continue to decrease. Commodity margin also benefited from lower congestion, network and transmission line loss expense, net financial sales and purchases and lower fuel expense primarily due to a 3.4 million megawatt hour decrease in generation output from our competitive fleet compared to the third quarter of 2011. This reflects the change in our economic dispatch strategy, a nuclear outage and the plant deactivations that occurred on September 1. Purchased power increased by $0.40 per share due to decreased generation volume and the increased retail sales I just mentioned. Finally, wholesale sales volume had an $0.08 per share negative impact on the quarter results. This also reflects the 21% decline in prices at the 80 Hub from $43 to $33 year-over-year. As I’ve said before, our retail strategy partially mitigates the impact of the prices established in the wholesale market. We remain very pleased with the overall performance of FirstEnergy Solutions. We've achieved a 42% increase in the number of retail customers compared to the same period in 2011, and we look to end 2012 with 101 million megawatt hours in competitive sales. We believe our retail strategy has 2 primary competitive advantages: First, we are building our retail book to look like a utility in a regulated market, using a generating portfolio that was originally built for that kind of load. The difference today is that we can optimize our channel mix because we are not constrained by the old geographic barriers. Second, we now have more than 2.5 million retail customers, which gives us a much larger customer base or denominator to spread back-office costs. We believe that these 2 advantages results in pricing flexibility that sets us apart even in a depressed power market. We believe this is why FirstEnergy Solutions has been so successful in the market. Now moving away from 2012 to a more detailed discussion of our 2013 non-GAAP earnings guidance, which is $2.85 to $3.15 per share. A high-level overview of the 2013 non-GAAP earnings drivers, sales forecast and generation forecast can be found on Page 22 of our consolidated report. In 2013, our regulated utilities are projected to deliver solid earnings of $2.08 to $2.13 per share, and our transmission segment is expected to earn between $0.47 and $0.52 per share. The earnings from our regulated operations are in line with our prior guidance. As we have said in the past, these 2 segments, combined, provide a solid foundation with stable earnings, cash and strong support for our dividend. Corporate and other is expected to reduce 2000 earnings by $0.25 per share. Our competitive operations are expected to provide between $0.55 and $0.75 per share in 2013. Total sales volumes to direct retail customers or those in the LCI, MCI, governmental aggregation and mass market channels are expected to grow by 12% year-over-year while POLR and structured sales are expected to be down 6% compared to 2012, again consistent with our strategy to shift away from POLR. Our competitive sales volume forecast for 2013 has been revised to 104 million megawatt hours, and we anticipate an average rate per megawatt hour of $53. At this point, our 2013 sales are already 81% committed. We are providing a range for competitive generation output next year of 78 million to 93 million megawatt hours. We are giving a range because it provides the flexibility to respond to market conditions as we continue to leverage our fuel and dispatch strategies accordingly. I'm sure you have questions on the drivers for 2013, some of which we can answer today. But I also want to note that we will be posting materials for the EEI Financial Conference to our website this Sunday afternoon. Those materials will include additional information in advance of the conference where we look forward to seeing many of you. One final note before turning it over to Tony. I wanted to also brief you on a project that we're very excited about. We've entered into a nonbinding memorandum of understanding with American Municipal Power or AMP to develop 873 megawatts of peaking capacity at our Eastlake plant located in the ATSI footprint and just east of Cleveland, Ohio. This project is subject to, among other things, regulatory approval. Under the MOU, we would supervise construction of the units. AMP would provide 100% of the construction financing and own 75%. Upon completion, FirstEnergy will purchase the remaining 25%. Importantly, FirstEnergy Generation will manage the project and operate the units. At this juncture, we anticipate the facility would be operational in early 2016 and would be bid into the 2016-2017 PJM-RPM auction scheduled for next May. This proposed project is expected to reduce our need for some of the previously announced transmission projects and extend the timeframe for others. As a result, our earlier estimates for transmission spending of between $700 million to $900 million for 2016 have been reduced by about $200 million, bringing the estimated transmission spend to $500 million to $700 million. Approximately $150 million of that will be incurred in 2013. We are very pleased with this project and its potential benefit to FirstEnergy. As we move forward, we will continue to assess our operations and look for additional opportunities to reduce our costs. Most importantly, we remain well positioned to take advantage of opportunities created by expanded competitive markets and improved economic conditions. Now, I'll turn the call over to Tony. Anthony J. Alexander: Thanks, Mark, and good afternoon, everyone. I'll begin today with a brief update on some recent events, and then I'll provide my perspective on the economy and the actions we are taking to strengthen the company as we continue to address the challenges of low market prices and weak demand for electricity. First, we know many of you experienced, firsthand, the devastating impact of Hurricane Sandy. The wind, flooding and snow associated with the storm ultimately resulted in power outages for about 1/3 of the utility customers we serve across our entire service area. The storm, which was far more destructive than Hurricane Irene and last year's unusual October snowstorm, has required replacement of more than 7,000 poles, 24,000 crossarms, 3,000 transformers and nearly 600 miles of wire and cable. Storm costs are expected to be in excess of $500 million and approximately 95% of that is expected to be capitalized or deferred for future recovery. Final storm costs will be determined during the fourth quarter. We called upon every available resource to restore service to our customers as quickly as possible. Our own employees from across our 10 operating companies were joined by thousands of contractors and mutual assistant crews from other utilities all across the United States. Together, they worked under difficult conditions to clear debris and make repairs at thousands of locations throughout our service area. I'd like to extend a special thanks to the elected officials, police, fire and emergency management personnel for their dedicated efforts in keeping public safety a priority and helping us meet the unprecedented challenges of this disastrous storm. We understand that losing power is a significant hardship, and we greatly appreciate our customers' patience and understanding as we continue to complete this massive restoration effort. Let's move now to a review of regulatory activity. In Ohio, a 3-year auction for generation supply for our Ohio utility customers was conducted on October 23 and resulted in a price of $60.89 per megawatt hour. FirstEnergy Solutions participated and won 5 of the 17 tranches available for bid. The next auction is scheduled for January 2013. Also in Ohio, the Public Utilities Commission approved our application to securitize previously incurred costs that are currently being recovered from customers under deferred recovery riders. As filed in the application, those riders were estimated at $436 million as of December 31, 2012. This was the first test of the state's new securitization law. We expect to file an application for rehearing on November 9 to obtain certain changes and clarifications to the PUCO order. Once the rehearing process is successfully resolved, we expect to use the proceeds from the transaction to reduce debt at our Ohio utility companies. Finally, in August, the PUCO ruled on AEP's modified electric security plan. And in mid-October, the PUCO upheld many provisions of its July order in the AEP Ohio capacity case. In addition, Dayton Power & Light filed an electric security plan in October. We continue to believe that giving customers the right to shop will result in lower electric bills in an improved Ohio business climate. FirstEnergy Solutions will continue to monitor and actively participate in these cases and remain a strong advocate for competitive markets. Turning now to new regulatory activity. Leila Vespoli and her team will be focused on 2 new proceedings over the next year or so. In New Jersey, we will file a rate case with the Board of Public Utilities by December 1. The filing was delayed from the originally scheduled filing date of November 1 due to the devastating impact of Hurricane Sandy on New Jersey. In West Virginia, we plan to file with the Public Service Commission for approval to transfer ownership of the Harrison plant to our Mon Power Subsidiary. West Virginia is our only fully regulated service territory and we deactivated about 600 megawatts of regulated generating capacity there earlier this year due to the new environmental regulations. This transfer is part of a resource plan to address the capacity shortfall and ensure reliable power for Mon Power and Potomac Edison customers in West Virginia. Under the terms of the proposed asset transfer, Mon Power would acquire an additional 80% of the Harrison plant, giving the utility sole ownership of the 1,984 megawatt facility. In addition, Mon Power would sell its 8% minority interest or 100 megawatts in the Pleasants Power Station to Allegheny Energy Supply. We considered a number of alternatives to obtain the necessary energy and capacity in West Virginia, including purchasing power from the market or building new generation. We believe this proposed asset transfer is the most cost-effective option for our customers and our company over time. And since the facility is equipped with modern emission controls and produces electricity with locally mined coal, the plan should be very positive for the economy of West Virginia. The proposed asset transfer will require approval from the West Virginia Public Service Commission and the Federal Energy Regulatory Commission. Moving now to an update on some of our marketing efforts. Our retail strategy focuses on optimizing our channel mix. And as you heard earlier, we expect to grow our direct retail sales by 12% in 2013. As a part of this effort, in late August, FirstEnergy Solutions launched a major new mass market campaign featuring a 7-year fixed price offer. This innovative product targets residential and small commercial customers in the Southern Ohio markets, as well as in our Ohio utility footprint. We are extending the offer and also plan to introduce similar fixed price offers in other states, consistent with our strategy of seeking higher-margin channels while continuing to offer innovative products to customers. This program, along with others, will help shape our retail portfolio, consistent with our overall strategy. We remain focused on building our retail business and strengthening our brand among customers in targeted markets. We believe this retail strategy, as well as the actions we're taking across the rest of our business, will position FirstEnergy to take advantage of improving economic conditions over time. Now with respect to the economy, we certainly anticipated that it would be more robust when we developed our initial forecast for 2012 and 2013. Instead, we continue to see very slow, even stagnant growth. The impact on our company, and in fact, our industry is essentially flat electric distribution sales with no growth in the residential sector, decreasing demand from many small and medium-sized commercial customers and very spotty growth in many sectors of the industrial customer class. This weak sales environment is coupled with depressed power and natural gas prices over the past year or so, which has put downward pressure on earnings from our competitive segment. With a significant oversupply of generation and weak demand continuing to dominate in our region, we expect these conditions to continue in the near term. Longer term, in 2015 and beyond, coal plant deactivations as a result of MATS and other environmental regulations should improve the power supply and demand imbalance that we have today. In response to these ongoing conditions, we took a step back and reframed our projections and some of our short-term strategies. We accelerated our normal budgeting process in order to share our 2013 outlook with you today. And we completed a thorough assessment of how we operate our facilities, taking the steps necessary to continue reducing costs and aggressively managing our expenses. As a part of that process, we completed an organizational study that resulted in the reduction of approximately 200 positions in our corporate support departments and at FirstEnergy Solutions. In addition, we anticipate the reduction of another 300 to 400 positions throughout 2013 due to normal attrition throughout our operations. We also implemented changes to the 401(k), health care and other employee and retiree benefits. We will continue to assess our operations, our regulatory opportunities and financial initiatives to ensure that we continue to deliver value and remain positioned to take advantage of growth when the economy does eventually recover. And as we pursue additional cost savings, we remain focused on ensuring we have a strong balance sheet given our increased capital program over the next several years. We have a strong management team, and we are prepared to meet these challenges in order to deliver shareholder value. As we look to the future, we see several catalysts for longer-term growth. First is the overall improvement in the general economic conditions over time should bring us back to at least modest levels of growth at the regulated utilities, and we see the potential for exciting additional growth opportunities associated with the Marcellus and Utica Shale build-out within our service area. Transmission investments within the FirstEnergy footprint will provide growth and stable returns. The current supply-demand imbalance will likely tighten as additional generating facilities in the region are deactivated due to more stringent environmental regulations. And improvements in the price of natural gas and power will benefit our fleet. Finally, I know there's been a lot of talk recently about dividends. That's where I would like to close. While it's always subject to board approval, we expect to maintain a stable and solid dividend. As the numbers earlier reflected, our regulated operations provide a strong foundation of earnings, cash and support for the dividend. And I am committed to our efforts at maintaining a stable and secure dividend. Thank you for your continued support of FirstEnergy. And now, I would like to open up the call to your questions.

[Operator Instructions] Our first question comes from Dan Eggers of Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Tony, when you think about all the process you guys went through in the last couple of months to reevaluate 2013 and really much of that inquiry of yours have been on the FES side. What is set out to you is kind of the biggest surprises, both positive and negative, to get to guidance where we are right now and if there's anything in there that you see as a bright spot or a negative spot amongst those bands, what do you think they are right now? Anthony J. Alexander: Well, if you take a look at the entire company and the bright spot in my mind, quite frankly, is the resourcefulness of company management and executives to take on problems like we have in the challenges of this current economic condition and come to a positions that allows this company to move forward, to position itself for the future, to be able to take advantage of improving conditions going forward and to deliver in the near term fairly solid results, given the circumstances in the market that we are currently facing. Dan Eggers - Crédit Suisse AG, Research Division: Tony, when you look at the O&M savings and kind of the ability to bring down headcount, of the decline in O&M in the winds of inflation, how much of that is going to be people-related? And if you think about looking to a recovery, can you support a recovery at this new base or will there be some greater acceleration in costs as the recovery takes off? Anthony J. Alexander: No, I think I'm pretty comfortable, Dan, with the headcount and numbers that we have in place at this point. We said it looks like about 200 positions have been eliminated. We expect another 300 to 500 next year through kind of normal attrition through the organization. We should be able to hold headcount steady. As the business grows, we'll evaluate the need for additional resources wherever those resources may be needed. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And I guess one last one. Just on kind of on the channels for customer positioning. I know you gave the 2013 numbers and you don't want to get into a '14 guidance situation. But if you were to look at trends, where do you think you're going to see more growth amongst those customer classes looking at kind of some of the market developments we've had recently?

This is Mark. I think it’s just as easy for Donny to answer, but we're really targeting the mass market and the middle commercial industrial market. We think those are very fertile for us. We like the stability offered to us by the large commercial industrial market. We said we're going to target less POLR. So you should see growth in both the MCI and mass market, and Donny's group is being very aggressive in those markets and targeting them and coming out with new programs.

Our next question comes from Stephen Byrd of Morgan Stanley. Stephen Byrd - Morgan Stanley, Research Division: I was just thinking through your 2013 guidance and the projected output of the power plants of 78 to 93 terawatt hours. And I'm just sort of thinking through in 2013 and beyond your sort of net long versus short position on power price changes and was wondering if you could give some guidance as to if the forward power price were to change, how that would impact you in 2013? Donald R. Schneider: Stephen, this is Donny. Rather than think about it from a power plant output perspective, I would draw your attention to our open book. Right now, I think Mark said we're about 81% closed, leaving about 19% of our book open for '13. So obviously, as prices move that -- those sales would reflect increased prices. Stephen Byrd - Morgan Stanley, Research Division: Understood. What I was trying to think through is the balance of the retail book that's about 81% hedged versus the power plant open position and trying to figure out sort of on a net basis whether you're sort of evenly matched or if a change in just change power prices would have a sort of net bottom line impact to EPS in 2013?

I guess all else being equal, any increase in the power price would have a positive impact on the bottom line. If you're getting to would we run more of our own plants if, in fact, the power prices went up? Yes, we probably would. Right now, we're keeping some of them down because we can buy it less expensive that we can produce it. Donny's also renegotiating a number of the fuel contracts. That'll have an impact next year depending on his success, and he's had great success so far, so higher power prices would in all likelihood mean more production from our side and -- but don't forget that, that also impacts what we can do on the coal contract side. Stephen Byrd - Morgan Stanley, Research Division: Okay, understood. And then you had mentioned ATSI and some work you're doing there. As you think about whether that zone may remain constrained or not, does some of your recent activity there sort of change thinking, or how do you generally think about whether that zone could be constrained? Anthony J. Alexander: Well, I don't think adding the generation there is really going to change the dynamics because PJM will make a decision based on the amount of new -- either new transmission or hard generating assets within that area to determine the extent of and where constraints may be and how they would attempt to address them. I still like -- like we've talked in the past, I still like the idea of having generation inside the City of Cleveland and I'm very pleased that we are able to work this arrangement out with AMP. I think it's a solid plan, and I look forward to proceeding with that and getting that deal put through all of the hurdles to make it -- to get started on it. Stephen Byrd - Morgan Stanley, Research Division: Understood. And lastly, if I may, just very briefly. On pension assumptions for 2013, anything you would highlight in terms of assumptions that you've made in terms of any material changes in terms of things like discount rates or anything else we should be thinking about as we think about your pension expense?

I don't think we've made any changes, but we're no different than anybody else watching the treasuries for what that impact could have on the end of the year.

Our next question comes from Steve Fleishman of Bank of America Merrill Lynch. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Couple of questions. I guess, first, the -- is there -- have you assumed the West Virginia transaction gets done in the guidance for '13 and is that meaningful within the range of numbers you're giving?

I think the answer to that would be yes and it's in the guidance, but I don't know if I'd characterize it as meaningful. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Okay, okay. And then on the mass market offers that you've had, could you maybe give us a little more color on what kind of take-up you've had for that offer? What kind of consumer reaction you've had? Anthony J. Alexander: It's been very positive.

Now that's a little bit like the margin question. We prefer not to deal with what individual margins are per channel and we prefer not to talk about the successes in the volumes we were having with respect to individual programs. But we've been very, very pleased with it; that's why we extended it past the October 31 date. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Okay. That's helpful. And then finally, when you gave the guidance a couple of years ago, in your channels there used to be a wholesale channel. I'm assuming now that your generation is so much lower that you're really not going to be selling anything wholesale. Is that the reason that's no longer showing up there? Donald R. Schneider: Steve, it's -- a big piece of it is just when you look at forward prices in the wholesale space coupled with where we're at with generation. It just doesn't make a lot of sense to forecast much wholesale sales.

Our next question comes from Julien Dumoulin-Smith of UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: So first question on retail. You've talked about expanding retail here. Just kind of curious on a go-forward basis '13 and perhaps beyond, matching up your load and you generation. I mean, is that an ambition here, obviously gas prices being as volatile as they are, or are they kind of being somewhat structurally separated here from a certain perspective?

I don't think they're being structurally separated. I think -- we want to have that retail book look more like a regulated utility and so that would be about 1/3 industrial, 1/3 commercial and 1/3 residential. That's why we're pushing a little bit harder on the mass market residential, the medium commercial, which is kind of the lower end of commercial. We might pull a little bit out of the LCI downward into those channels and we'll be trying to do less on the POLR side. So it ultimately should be pretty close to 1/3, 1/3, 1/3 and that's what we're targeting, but that's what our generation was built for as well, so... Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Right. And so maybe perhaps not to put words in your mouth, when you think about like '14 and beyond, is your thought process to keep your retail intact to 100 terawatt hours and over time see generation kind of leg back up into that level. Is that kind of the thought process?

Well, I think we've said in the past that retail will lead generation. As the retail side grows, we may add generation. We may go secure some other sources, but retail will lead the generation portion. In other words, we want to have the sale before we commit on the other side. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Right, right. Absolutely. And speaking of the other side of the equation, could you perhaps describe a little bit more of the economics of the new peaking plant that you described? I mean, I suppose the primary question I would have is didn't this clear in the last auction, the last ATSI capacity auction, that is, and are you benefiting from those kinds of economics or how are you getting paid for this?

Well, first, we're not funding the construction of it, so we were really looking at the market in '16 and '17 of which we plan on bidding into, but it did not clear when we proposed it to PJM. But my understanding from AMP is that they don't -- they're indifferent to that and they're going to build it no matter what. They have their own requirements. They self-serve and we're just happy to do this. We're going to build it; we're going to operate it. It helps the reliability issue. It drives down some of our transmission expense. And we're going to own 25% of it at the tail end. So it's kind of a win-win for us and a win-win for them. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Got you. And then just a last quick question here. In looking at the details on your '13 guidance, RPM revenues seemed to have come down from what you guided at your last analyst day. In terms of the year-on-year decline, it looked like it's less. You kind of described $200 million. Now it's closer to that $160 million level from what I can tell? Donald R. Schneider: Yes, Julien, this is Donny. We don't always clear 100% of our available capacity in those BRA auctions. And so when you think about the numbers we give, those are based on the BRA auctions. Subsequent to that, we will always participate in incremental auctions, and on occasion we'll do a bilateral contract for capacity. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Got you. So implicitly, what you're saying is you've locked in more capacity contracts in the interim, right? Donald R. Schneider: Yes, correct.

Our next question comes from Ashar Khan of Visium.

I was just -- Mark, I don't know if I am front-running the Sunday slides or I don't know if you can help me just trying to get a broader sense. The previous guidance midpoint was around like, if I'm right, $3.30 or so and we are now at $3 so there's a decrement of about nearly like $0.30 -- $0.30, $0.35.

It's actually $0.25.

$0.25.

Right, $3.10 to $3.40 was the prior guidance. Now, it's $2.85 to $3.15.

Now if I take the revenues numbers and if I'm throwing the wholesale piece out as Steve has mentioned, but if I just take the revenue that you had previously from the channel sales and which you're giving right now, the decrement is something like $0.80 or so. If I just do the -- decrease the revenues, I'm just doing it like that. And you've mentioned O&M, you pick up $0.15; Mansfield leases, you pick up $0.05, probably another $0.05 on this lower revenues and all that. So I'm left with like trying to account for another $0.40 of improvements to offset that increase in channel revenues. And I don't know if you can help me where those improvements are coming from because you mentioned the regulated business is similar to what it was before and there's been no change over there. Can you just help me where those other $0.40 of improvements are coming from, generally?

Well, I don't know if you're front-running or not, but I can tell you that Tony alluded to the fact that we're taking 200 positions out in the corporate and the FES side. Those are effective December 1. So those will not be in next year. We expect 300 to 400 to 500 people to attrit. They will not be in next year's numbers either, so -- and we changed some of the benefit programs, some of the other things around. Those are big numbers. They're well in excess of $100 million, just the things I had alluded to right there. I'd have to go through the whole list of all the changes, but it's pretty much across-the-board. I think Tony said it really, really well when he challenged all of us to go find money. And even though Chuck might be a midpoint of $2.60, which was the midpoint we had him before, there's a little bit of a mix in that. Distribution is up a little bit, transmission is down a little. So even though his numbers might be the same as to a midpoint, they're a little different. And I would say that, there's just a whole host of smallish-type things that added up to a big number. When you take -- after you factor out the volume and the price delta that we already alluded to.

Our next question comes from Paul Ridzon of KeyBanc. Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: Earlier this morning, PPL actually pointed auto as a bright spot in Kentucky. Can you given a little more flavor about what's going on with steel and auto?

Well, I can't give a description of Kentucky, but I know, for example, the Chevy Cruze, which is produced in Youngstown, had a record month last year in terms of sales of 34,000 vehicles. So I think some of it is just a little bit of catch-up. We were going for a while at double-digit year-over-year increases in industrial sales and then we kind of slowed up to the high single digits. So some of it, I think, is just catching up. But again, the Cruze is still running 3 shifts, but I don't believe they're running 3 shifts through the weekend. Ford backed off a shift, but they're still running 2 shifts instead of 3. Steel input -- steel output is strong and that's really, really tied anymore to what's going on in Marcellus and Utica. So it could be just a plant-specific quirk or it could be an industry quirk, but we're really pleased with the plants that we have in our territory because they're all running 2 or 3 shifts. Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division: And if you look at the midpoint of guidance at $3, kind of what underlies that with respect to your expectations economically? Is that just status quo?

We didn't do anything in terms of -- if you're asking did we get overly aggressive with the economy to bump the numbers up; no. In fact, I think we held them pretty consistently flat across-the-board.

Next question comes from Brian Chin of Citigroup. Brian Chin - Citigroup Inc, Research Division: For Hurricane Sandy, how much of that $0.5 billion cost comes from Jersey Central versus in Monongahela?

I don't have the numbers right in front of me, Brian, but I would say the vast, vast majority, probably 80% or higher. Brian Chin - Citigroup Inc, Research Division: Comes from Jersey Central.

Right. Brian Chin - Citigroup Inc, Research Division: Okay. I know that you guys have done historically a very good job in terms of recovering storm costs, but when I look at sort of the magnitude of the cost estimates here relative to the amount of outages, it seems like Hurricane Sandy is just a lot higher in order of magnitude of costs. Can you just talk about what was it in particular that made Hurricane Sandy a lot more expensive than, say, Irene or the October storm?

Tony flew over in a helicopter so I'll let him talk to that. But I spoke to Chuck Jones, the Head of Utilities this morning and he's been around for 35-some years and he's -- he just continues to say he's never seen anything like this before. But Tony flew over it, so I'll let him speak. Anthony J. Alexander: I think, Brian, the extent of the damage is extensive and broad, affecting -- when you think about it, it affected almost every customer we have in New Jersey in terms of we had over 1 million customers out. We had to build back the system with not only some transmission, but substation and sub-transmission, substation damage that had to be corrected. And the amount of trees in and across multiple power lines. It's just the way the storm hit, the way it came through New Jersey, hit our service territory and several other companies because they're struggling with many of the same issues that we are, very hard. And you can tell that with the restoration effort the way it is, I mean we're probably restoring at this rate faster than any other restoration any place in the country with this amount of extensive damage. But it's still a very slow go hooking up customers with the amount of damage that's been sustained. I mean it's significant; it's broader than what we've seen before and it's affecting many more circuits multiple -- in multiple places than what we've seen in the past.

Brian, I'd just give you one quick example. I mean, if you have a substation that's flooded, you have to wait until it drains out. But in this case, you might have a substation that's flooded with saltwater, which means you not only have to wait for it to drain out, but then you have to re-flush it out so you get the salt off all the circuits, so it's like almost you're getting penalized twice. Once, to have to wait for it to drain out then you've got to deal with the salt that's all over. So it's like this compounding effect. Brian Chin - Citigroup Inc, Research Division: Understood. And then my last question on this, so obviously the JCP&L rate case has been delayed in terms of their filing until December. When you make the December filing, is Hurricane Sandy cost recovery going to be a part of that or is that going to be handled in a separate proceeding? Leila L. Vespoli: Brian, this is Leila, yes, I would expect that filing to take into account the effects of Hurricane Sandy. We're still working through exactly how we would present that, but we would anticipate including it in the filing.

Our next question comes from Jonathan Arnold of Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Brian just asked one of my questions so I'm not going to ask that again. But on this issue of the capacity delta in 2013, the $160 million versus the $210 million before, you said it was due to having not placed all your capacity in the initial BRA auctions. Was there any element of that line that relates to having entered into some more term contracts where that's kind of part of the retail margin, or would that show up at a different line? I guess, that's my question. Donald R. Schneider: Yes, Jonathan, this is Donny. The -- if you're thinking about when we doing retail sale, take our 7-year product as an example, obviously that spans well into the '15, '16 BRA and beyond for that matter. And so there is a component of capacity revenue as you levelize that charge that you pull forward, but that would actually show up in our retail sales. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Okay. So what you're showing in that line is just the pure wholesale capacity PJM auction-type piece? Donald R. Schneider: Yes, that's correct.

The last question is from Hugh Wynne of Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: So New Jersey in the last 14 months or so has had 3 major storms that have caused extensive damage and extended outages for large numbers of customers. Now this last one cost your company something like $400 million in storm restoration cost. Is the industry thinking ahead to a need to harden distribution systems in a significant way to prevent the recurrence of these costs or is that something that's certainly not kind of become an issue for discussion yet? Anthony J. Alexander: I don't think generally that, that's been proposed. I mean, a lot of talk has been out about we should underground everything. The costs of doing that are pretty extensive and have significant impacts on individual customers and their neighborhoods as you begin to bore through the underground facilities. No one likes these types of storms, obviously, and to the extent that there are things that we can do over time to make the system a little more resilient, we'll be undertaking them. Obviously, after 3 storms, I'd be surprised if there's a tree left standing, but there certainly are more there that I expect that we had problems with last night as a result of the nor'easter coming through. So it is a combination of whatever system you have in our space. Essentially, 95-or-more percent of what we do is exposed on a day-to-day basis to the elements. Whether they are wind, whether it's flooding, whether it's surges off the coast, hurricanes, snowstorms, all of them have impacts that need to be taken into account. To the extent that there are other things that we can do over time, we're certainly going to look at them. But when a major storm like this comes through, whether it's in New Jersey or anyplace else, it has significant consequences.

We look forward to meeting with many of you at the EEI Financial Conference, which gets underway in just a few days. In terms of logistics, we plan to post additional materials on our -- of our 2013 guidance along with EEI materials to our website sometime midafternoon on Sunday. Tony and I'd like to thank everyone for joining us on the call today and as always, we appreciate your support and interest in FirstEnergy. Thank you very much. Anthony J. Alexander: Thank you.

Thank you for participating in today's teleconference. You may now disconnect your lines at this time; and thank you for your participation.