Meghan Beringer Anthony J. Alexander - Chief Executive Officer, President and Executive Director James F. Pearson - Chief Financial Officer and Senior Vice President Donald R. Schneider - Principal Executive Officer and President

Dan Eggers - Crédit Suisse AG, Research Division Brian Chin - BofA Merrill Lynch, Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Paul Patterson - Glenrock Associates LLC Steven I. Fleishman - Wolfe Research, LLC Stephen Byrd - Morgan Stanley, Research Division Ashar Khan Angie Storozynski - Macquarie Research

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

Thank you, Brenda, and good afternoon. Welcome to FirstEnergy's second quarter earnings call. First, please be reminded that during this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of FirstEnergy Corp. are based on current expectations and are subject to risks and uncertainties. A number of factors could cause actual results or outcomes to differ materially from those indicated by such forward-looking statements. Please read the Safe Harbor statement contained in the consolidated report to the financial community, which was released earlier today and is also available on our website under the Earnings Release link. Reconciliations to GAAP for the non-GAAP earnings measures we will be referring to today are also contained in that report, as well as on the Investor Information section on our website at www.firstenergycorp.com/ir. Participating in today's call are Tony Alexander, President and Chief Executive Officer; Jim Pearson, Senior Vice President and Chief Financial Officer; Donny Schneider, President of FirstEnergy Solutions; Jon Taylor; Vice President, Controller and Chief Accounting Officer; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations. Now I will turn the call over to Tony Alexander. Anthony J. Alexander: Thank you, Meghan. Good afternoon, everyone. I'm glad you're with us. Today, Jim and I will provide an overview of second quarter results, an update on operational and regulatory developments and a review of the progress we are making on the financial plan we outlined earlier this year. I will also take this opportunity to clarify several topics that seem to be on the -- seem to be on our investors' minds, which I believe have put undue pressure on our recent stock price. We'll begin with a look at our financial results. Today, we announced solid second quarter non-GAAP earnings of $0.59 per share. These results are in line with our expectations, and we are also reaffirming our 2013 non-GAAP earnings guidance range of $2.85 to $3.15 per share. While I'm pleased with our second quarter performance and our outlook for the remainder of the year, the PJM capacity auction results for the 2016, 2017 period were disappointing. As in the past, we are not disclosing the number of megawatts from our competitive business that cleared the auction. However, as has been the case in other recent auctions, not all of our generating units cleared. Respecting the PJM auction, I believe that there are significant and fundamental flaws in the process. These flaws will not only impede investments in competitive generation resources and the development of a robust competitive market, but will also, ultimately, impact reliability. We will continue to work with PJM and others to address these flaws, and in some cases, loopholes that encourage gaming the system. In the meantime, however, and in the wake of these auction results, we are taking additional aggressive steps to further reduce our costs and improve operational performance. We have thoroughly evaluated the economics of each of our plants as a result of the auction and current and future environmental regulations, most significantly, the Mercury and Air Toxics Standards, or MATS. As you may recall, in 2012, shortly after MATS Rules were finalized, we announced plans to deactivate units at 9 of our older coal-fire generating facilities. As a result of our recent analysis, we announced plans to further trim our fleet and deactivate 2 additional power plants by early October. These are the 370-megawatt Mitchell Power Station in Courtney, Pennsylvania; and the Hatfield's Ferry Power Station in Masontown, Pennsylvania, which is a 1,710-megawatt facility. These deactivations are subject to PJM review for any reliability impacts. The Hatfield Station is a large supercritical and scrubbed facility. And while the Mitchell Station is older, it is equipped with scrubbers. However, neither of these plants cleared in the 2016, 2017 capacity auction. And some of the individual units also did not clear in the 3 prior auctions. Our analysis, among other things, consider that together, Hatfield and Mitchell represent approximately 10% of our total generating capacity, with about 30% of our estimated cost to comply with MATS regulations. As a result of these closures, our MATS compliance costs are expected to decrease from around $925 million to approximately $650 million. And we continue to look for ways to refine and perhaps further reduce our expected MATS compliance costs. The total reduction in capital over 5 years at these facilities, including $275 million for MATS, is approximately $500 million. From an earnings perspective, the closure of these facilities will be accretive by several cents annually going forward. In addition to these decisions, we've also canceled or delayed certain investments in other generating facilities, which are expected to further reduce the capital needs in our competitive generation fleet by about $375 million over that same period. In total, this $875 million reduction in capital over the next several years is a vital component of our overall effort to manage cash effectively during this time frame. We have also identified, and are implementing, additional cost opportunities across our organization. These actions include reductions to medical and other benefits, and additional organizational changes, including a reduction in staffing and corporate support and the elimination of certain open positions throughout the organization. Combined, these actions are expected to reduce costs by about 100 -- by a total of $150 million to $200 million annually, beginning in 2014, with some impact in 2013, as the changes are implemented. These savings will run through both expenses and capital, and we will have a better sense for the allocation as the savings are implemented. We also announced that we will be moving to a cash balance pension plan for employees hired on or after January 1, 2014. While this will not impact current pension obligations, it should change our pension responsibilities over time. While many of the changes in our operations will have an impact on our competitive business, they do not change our strategy. We have had, and plan to continue, our asset-backed retail sales strategy in which our objective is to sell up to 25% more than we can produce. This allows us to increase the utilization of our generating fleet throughout the year, and take greater advantage of retail sales during otherwise low-load periods. Since our competitive production capability, however, is expected to be lower as a result of the plant retirements and perhaps further reduced by the Harrison and hydro transactions, we would expect that our future retail sales targets, consistent with our strategy, would also be less. Even so from an actual sale standpoint, our total retail sales may only be slightly less than current levels. And more importantly, given our current book of business, we are in a position to be far more selective in our channel and customer activity. Our strategy is about both volume and margin. For example, we have already booked more than 75 million-megawatt hours of channel sales for 2014 at prices above this year's. And through the remainder of this year, we anticipate locking in additional direct and POLR sales, as auctions are conducted. We are also seeing improved margin in our recent contracts and overall margin improvement by not pursuing renewal of some customer load. So while the reduction in our competitive generation fleet will impact our production capability, we do not expect it to have an appreciable effect on our retail sales plans. I remain confident in our strategy and in the manner in which we are executing to deliver higher value to our shareholders. Let me now move to a brief regulatory update, as Leila is unavailable to join us today. First, respecting the Harrison proceedings in West Virginia. We received FERC approvals for the proposed financing and transfers related to the transaction, and the West Virginia Public Service Commission hearings on the asset transfer were completed in late May. Briefs and reply briefs were filed by the parties in July. And with the conclusion of the regulatory proceeding, the commission may issue an order at any time. We are, however, currently in active settlement discussions with all parties in this case, and we are very hopeful that we can reach a resolution through this process. I continue to believe that this transaction provides positive benefits to our Mon Power customers and the state of West Virginia. And over time, it will help maintain our rates in West Virginia at levels that are some of the lowest in the region. Regarding the New Jersey generic proceedings on major storm costs. On May 31, the Board of Public Utilities clarified that the prudence of the 2011 major storm costs would be reviewed in the generic proceeding, with the goal of maintaining the schedule established for the base rate case, where recovery of such costs would be addressed. The board further indicated that it would review the prudence of our 2012 major storm costs in the generic proceeding, and the recovery of such costs would be considered through a Phase II in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding. On June 21, we filed a detailed report of 2011 and 2012 major storm costs in this docket. In the pending JCP&L base rate case, we will file rebuttal testimony this week refuting the testimony put forth by the Rate Council and other intervenors. Hearings on the base rate case are scheduled for mid-September through mid-November. We expect resolution in that case by the first or second quarter of 2014. It's important to note, however, that JCP&L has the lowest distribution rates in New Jersey and, in some cases, by a significant margin, despite having one of the more difficult areas to serve since it is exposed to some of the greatest tree-density in the state, as well as 74 miles of coastline. Now turning to Ohio. In Ohio, as we mentioned during our last earnings call, the State Senate introduced legislation, Senate Bill 58, aimed at amending the current energy efficiency law that was originally passed in 2008 under Senate Bill 221. In June, the Senate Public Utilities Committee conducted a series of public hearings to determine whether these costs -- whether these costly mandates are serving Ohio's best interest, and to gather stakeholder input on what changes are necessary. We were very pleased to see Ohio business owners personally attend these hearings to express their concerns with the current law. We expect that Senate Bill 58 will be revisited when the House and Senate reconvene in the fall. In the meantime, we remain actively involved in this process with Ohio's other electric utilities and other key stakeholders to determine what measures will most effectively reduce the cost burden of these standards in future years. Also in Ohio, the PUCO scheduled a series of workshops throughout the remainder of this year as part of a retail market investigation that the commission launched late last year. FirstEnergy is fully participating in these workshops, and we are sharing our thoughts on ways to create additional opportunities for suppliers to effectively compete. We have a lot on our regulatory plate, but with 10 operating utilities in 5 states, it will probably not be unusual. We have good regulatory relations and we are working with capable commissions to address all of these matters and other matters that will arise over time. Now let's turn to our 2013 financing plan. While Jim will provide additional details on our overall plan, I wanted to note that we continue to make significant progress. We recently became the first utility in Ohio to successfully take advantage of the new Securitization Act, which allowed us to redeem certain debt at our Ohio utilities. We also announced additional early debt redemptions at our Ohio utilities which, in combination with the Securitization, will put each of those companies in a very solid credit position. And with an equity infusion from FE directly to FES, along with the retirement of debt at FES, we have substantially improved the credit metrics of that entity as well. Further, we recently completed the extension of our credit facilities through May of 2018, and we exercised the $500 million accordion option at the FE credit facility, which should provide sufficient liquidity to the company. Combined with other -- the other actions we've taken since the beginning of the year, these are significant accomplishments in a very short period of time, and place our subsidiaries in a much stronger financial position. Progress also continues on our plan to sell up to 1,240 megawatts of our unregulated hydro generation assets. First round indicative bids were received early in the quarter, and we are involving a handful of interested parties in the deep dive process. I expect that we will be in a position to take the next step in this process during the third quarter. Through the combined actions we've taken across the company to reduce cash expenditures, particularly, the reduction in our generating fleet CapEx, our equity needs have been reduced. As a result, we plan to issue equity only through a dividend reinvestment program and various stock-related benefit plans beginning later this year. This is expected to provide approximately $100 million on an annual basis based on the current stock price and the anticipated participation levels. Beyond this, we have no plans to issue additional equity at this time. This clarification of our plan should put to rest any further speculation regarding amount and timing of additional equity. With respect to the dividend, as you know, our Board of Directors announced an unchanged quarterly dividend payment of $0.55 per share just 3 weeks ago. Our dividend continues to be supported by the strength of our combined regulated utility and transmission operations. As we reshape our balance sheet, improve our liquidity and reduce our capital and other operating costs, we will continue looking at opportunities for growth in our Regulated businesses, with a strong focus on those that will improve customer service and provide attractive near-term returns to the company. For example, we are making solid progress on the transmission projects that we outlined earlier this year. Portions of Black River Substation Ohio, as an example, is now in service and should be fully operational by September. We're also on-target with the construction of the major transmission line that will ultimately connect the Davis-Besse Nuclear Power Station to a substation in Lorain County. In New Jersey, open houses were held in late June for our proposed Oceanview Reinforcement Project, which will build a new 230 kV transmission line to reduce -- to add redundancy to the system and meet the growing demand for electricity. And we are still planning to invest about $700 million through 2016, utilizing ATSI and TrAILCo to address reliability issues related to coal unit deactivations within our footprint. We are also evaluating a number of additional opportunities within our service area that would further expand our transmission investments. Given the size of our transmission system and service area, the transmission investment opportunities that we have identified are in excess of $7 billion. While it would take us some time to further define the projects and related time frame, it is fairly clear that the opportunities within our footprint to grow our transmission business are substantial. In our distribution business, we are looking at the potential for rate cases in certain jurisdictions. Mon Power would be one of those, upon the successful completion of the proposed Harrison, Pleasants transaction. But we are also actively reviewing the potential for rate cases in other jurisdictions to assure a timely recovery of capital. Further, we are considering accelerated investments in smart meter technology, where such programs are supported by a regulatory policy. And we are looking for opportunities to expedite improvements in service reliability, as is being supported in Ohio, throughout our service area. On the overall economic front, things are obviously not yet where we want them to be, but we continue to see progress and believe that the bottom is now behind us. Our sales have been relatively stable over the last 3 years and we are now seeing increasing housing starts, as well as significant growth in shale-related segments. With continued growth and economic improvement, we expect to again see higher distribution sales over time. We continue to aggressively address our -- all aspects of our business: our generation fleet, our operations, our regulatory opportunities and our financial initiatives. And by taking advantage of growth opportunities across our businesses and reducing expenses, we believe we can continue to provide value to our shareholders. Our strong second quarter results, rigorous focus on cash management and our willingness to make decisions illustrate our ability to deliver even during tough economic times. Thank you for your support. And now I'll hand the call over to Jim for a review of second quarter results. James F. Pearson: Thanks, Tony. As we walk through the second quarter results, you may want to refer to the consolidated report, which was issued this morning and is available on our website. As Tony mentioned, our strong results were solidly in line with our expectations. Non-GAAP earnings for the second quarter of 2013 were $0.59 per share compared to $0.60 per share in 2012. On a GAAP basis, this year's second quarter results were a loss of $0.39 per share compared to earnings of $0.45 per share last year. The full list of special items that make up the $0.98 per share difference between GAAP and non-GAAP second quarter 2013 results can be found on Page 4 of the consolidated report. Most significant of these is $0.85 per share related to plant deactivations. Other special items for the second quarter include: trust securities impairment of $0.05 per share, debt redemption cost of $0.04 per share, regulatory charges of $0.02 per share and a decrease of $0.02 per share related to merger accounting for commodity contracts. Let's turn now to the results from our business units. We'll begin with distribution deliveries, which added $0.02 per share due to a 3% increase in residential deliveries. Overall, distribution sales decreased by 325,000 megawatt hours, or 1% compared to the second quarter of 2012, as the increase in residential sales was more than offset by a 3% decrease in commercial deliveries and a 2% decrease in industrial sales. Typically, when we speak of the weather impact on residential distribution deliveries, we are looking at heating and cooling degree days. This quarter, the discussion is a bit different because, while second quarter temperatures were warmer than normal, they were significantly cooler than the 2012 period. However, the month of June was more humid in 2013 than in 2012, which contributed to higher residential usage. In addition, you'll recall that June 2012 sales were negatively impacted by the derecho that swept through parts of our Ohio, Pennsylvania, Maryland and West Virginia territories on June 29, causing outages for more than 0.5 million customers. Second quarter industrial sales increased in the chemical and refinery class but declined in the steel and automotive, driven by the bankruptcy of RG Steel and the shutdown of the Ford Brook Park plant. Those events both occurred in May 2012, so we expect some improvement in our year-over-year comparison in the steel and automotive classes starting in the third quarter. Our full year forecast for 2013 calls for an overall increase of 2% in industrial sales, with most of the increase attributable to shale gas activities. Moving now to other drivers of the second quarter. Reflecting our continued focus on cost control, lower O&M expenses increased earnings by $0.06 per share. On the generation side of our business, O&M benefited from fewer nuclear refueling outages compared to the prior-year period and lower lease costs from the previously repurchased interest in the Beaver Valley Unit 2 and Bruce Mansfield plants. On the distribution side, expenses were lower due to our greater focus on capital work during the quarter and cost savings initiatives that were implemented last year. Higher general taxes and a higher effective income tax rate decreased earnings by a total of $0.04 per share. And finally, depreciation expenses decreased earnings by $0.03 per share. I'll turn next to commodity margin for our competitive business. Commodity margin increased earnings by $0.08 per share compared to the second quarter of 2012 when you exclude the $0.11 per share impact of lower PJM capacity revenues. While challenged by low market prices, FES continued to strategically grow its retail business. The total number of retail customers increased by approximately 700,000 in the past 12 months to 2.7 million by the end of the second quarter of 2013. Total megawatt-hour sales in our competitive operations increased 7%, and it increased earnings by $0.04 per share. Looking now at each of our channels. Governmental aggregation sales increased 31% in the quarter as a result of the continued successful expansion into Illinois. We achieved 35% growth in mass market sales, largely as a result of our successful marketing campaigns in Pennsylvania and Ohio. Structured sales nearly doubled due to increased municipal, cooperative and bilateral sales. Direct sales to large and medium-sized commercial and industrial customers increased 1%. And finally, consistent with the trend over the past year or so, and our retail strategy, POLR sales continued to decrease as we realigned our portfolio. Higher second quarter retail sales also had the impact of increasing both our purchase power cost and our transmission expense. However, these expenses were more than offset by lower capacity expenses, higher wholesale sales and the net benefit of financial hedges associated with our sales and generation portfolio. We also saw a lower average cost per fuel, which is, in large part, a result of the work we did late last year to restructure and terminate certain coal contracts, primarily, at Harrison and Sammis. We expect this fuel variance to continue through the end of the year. Total second quarter ongoing generation output increased modestly by 870,000-megawatt hours as a result of higher capacity factors at our Fossil fleet. Overall, we are pleased with the quarter's solid results, which demonstrate that even in very challenging times, we can strike the right balance of achieving short-term performance, while laying the foundation for what we believe is a strong long-term strategy. For example, as we mentioned last quarter, we have slowed FirstEnergy Solutions' future hedging based on current market conditions. FES has already exceeded its retail sales targets for 2013, with projected sales of 107 million-megawatt hours at an overall rate in line with the $53 per megawatt hour guidance we provided for the year. Going forward, we remain committed to implementing our plans for our competitive business, but we have adopted an even greater focus on higher-margin sales opportunities and selected customer retention. We continue to believe that our competitive retail strategy is the right approach for the long term, and with continued careful executions, will help ensure we are in a very strong position as market conditions recover. I'll turn now to an update on our financial plans for the year. As you will recall, in February, we laid out a plan that is structured to improve the balance sheet, particularly at our competitive operations and enhanced liquidity. As Tony said, we have made a significant amount of progress during the first half of the year. I'll walk you through the most recent accomplishments. Tony mentioned that in June, our utilities became the first in the state to successfully take advantage of the new Securitization Act, which allows us to finance deferred cost using AAA-rated long-term securitization financing. This transaction allowed us to redeem $410 million of debt at the Ohio utilities. In addition to Securitization, we plan to further reduce debt on our 3 Ohio utilities during the third quarter and have the issue notices to redeem an additional $660 million of debt. As these plans are implemented, we will have achieved our goal of significantly improving the credit metrics of each of our Ohio utilities. As we discussed in the first quarter call, through early May, we had already taken action that resulted in the reduction of about $1.5 billion in long-term debt at our competitive businesses. Subsequently, FE Corp. contributed $1.5 billion of equity to FES, which used the funds to repay outstanding debt. These actions have put the credit metrics for our competitive operations on more solid ground. During the second quarter, we also completed the extension of our credit facilities through May 2018. And as Tony mentioned, we exercised the $500 million accordion option on our revolver, bringing the total size of the facilities to $6 billion. Overall, we've made very solid progress on the financial plan we laid out for this year, and are reaffirming 2013 non-GAAP earnings guidance. And looking at the bigger picture, we're working through the challenging economic landscape by taking proactive steps to reduce capital and expenses, without restricting our ability to create and take advantage of opportunities across all of our businesses. As Tony mentioned, we've made significant capital reductions of $875 million on the competitive side of the business, with a continued focus on further refining both our MATS and other capital spend. We have an intense focus on cost, with $150 million to $200 million in further reductions already identified across the company through medical and benefit changes, staffing reductions and changes to pension funding. We are redeploying capital into regulated areas of our business that provide reliable returns, such as the investments in our transmission business and the potential rate cases and growth opportunities in distribution. In our retail business, which has a strong book already in place for 2014, we plan to continue to be more selective in our channel and customer activity going forward. Finally, we will continue working to strengthen our balance sheet through our equity program and continued implementation of our financial plan. As both Tony and I have outlined, we have taken significant steps to reduce costs, redeploy capital toward predictable and reliable return opportunities and move retail megawatt hours into higher-margin channels. The end result will be a stronger FirstEnergy, well positioned to address challenges and deliver positive results for shareholders. Now I'll open the call to your questions.

[Operator Instructions] And our first question comes from the line of Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Listen, I wanted to dig a little bit more into the $150 million to $200 million of savings. And, Tony, I appreciate it's still a bit early in the process, but can you maybe help bucket out what fits into kind of capital savings relative to O&M savings, given all the efforts you guys have done in the last couple of years already to bring cost down and capital out of the business? Anthony J. Alexander: Dan, this is Tony. When you think about it, it starts off all as an expense reduction. But a big part of our expenses end up being capitalized because it's all people-related. So it's going to really turn out to be a function of whether or not the workload and how it gets allocated -- is just going to be a question of whether or not that $150 million is going to be allocated to expense because that's where the individual would have or is working on, or whether that will be moved over to capital because of that same rationale. This isn't capital in the sense that we're delaying projects or eliminating projects. These are real cash savings that will then get allocated depending on where our people are working and what projects we're working on during the time frame. Dan Eggers - Crédit Suisse AG, Research Division: So how much headcount reduction goes into this, then? Because that's -- I mean, it's a lot of efficiency gains relative to your cost base. James F. Pearson: I'd say, Dan, we said that there would be about 250 positions that would be eliminated. Some were not filled, and that was in addition to the 380 positions that were associated with the deactivation of those plants. I think the bigger cost item will be the elimination of some of our benefit cost. It's a bigger cost reduction than just the staffing in itself, Dan. So I would say that would be the more significant component of the cost reduction. Dan Eggers - Crédit Suisse AG, Research Division: And this doesn't -- this is separate from the money you're saving from Hatfield and Mitchell closing, right? James F. Pearson: That right, that's right. What I would say the O&M savings associated with Mitchell and Hatfield, that would align with the several-cent incremental earnings per share. Dan Eggers - Crédit Suisse AG, Research Division: Okay. I got it. And then, I'd ask just maybe 1 more question on this, is that if you think about, kind of, from an O&M inflation perspective, net of these benefits, what should we think about, from a '13 baseline, will be the O&M inflation for FirstEnergy on a consolidated basis? Anthony J. Alexander: I guess, Dan, we're going to wait and give you that next year or later this year when we give you 2014 guidance. Obviously, we'll be looking at all of our costs, not just the ones that we've dealt with here. But fundamentally, each and every time we go about developing what our game plan is for the upcoming year, we'll scrub all of the numbers and determine where best to spend our available cash.

Our next question comes from the line of Brian Chin with Bank of America. Brian Chin - BofA Merrill Lynch, Research Division: Question, you have in the release a reference to net MISO and PJM transmission costs. What is that? And can you talk about whether transmission rights and underfunding, is that the issue that you are referring to in that, similar to one of your peers earlier this earnings season? Donald R. Schneider: Brian, this is Donny. Let me talk about the FTRs first because that seems to be a hot issue. Like many of the other PJM market participants, we also have experienced FTR underfunding. However, as we went into this year, we had adjusted our hedging strategy to be less dependent on FTRs. So versus our expectations, the impact has been very minor. If you think about what's going on there, what's driving this underfunding, there is a whole myriad of issues. There's the themes issues between MISO and PJM. There's the difference between what you would anticipate from kind of an infrastructure perspective, when the FTRs are allocated versus what actually occurs with outages and that sort of thing. And then, obviously, differences between how the day-ahead in real-time congestion is settled. I think we also released that we, in fact, filed a complaint with FERC back in 2011 to try and address these issues, and that case is still pending. We are seeing funding coming in, about 75% to 85% of what we feel we're entitled to. So we believe we're being shorted somewhere in the neighborhood of 15% to 25%. So while versus expectations, it's a very minor impact to us, on a year-to-date basis, we believe our revenue was off for about $6.5 million, about $0.01. Brian Chin - BofA Merrill Lynch, Research Division: Okay. And so that's not the MISO, PJM transmission issue, it's a separate issue. Understood. Donald R. Schneider: That's correct. Brian Chin - BofA Merrill Lynch, Research Division: And then, with regards to the cost cuts, just jumping back on Dan's earlier question. Is there a breakdown you can give to what extent those cost cuts are related to deregulated operations versus regulated operations? James F. Pearson: No. Right now we don't have that breakdown, Brian. And as a Tony said, we're going to incorporate that into our 2014 plans and we'll probably be able to give a little more clarity then.

And our next question comes from the line of Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: So quick question. It seems that there's been a little bit of a change in tact with regard to regulated rate base growth and positioning of the company. Could you, perhaps, confirm that and, perhaps, speak to what a new rate base growth trajectory could be prospectively, given some of the spending ambitions you guys spoke about on the distribution side? Anthony J. Alexander: Julien, I wouldn't necessarily describe it as difference. I mean, I -- we've always invested heavily in our regulated operations. The fact is, however, that as you look to the future, that there are probably stronger returns available, and more predictable returns available, from shifting investments towards transmission and other items as opposed to investing in generation assets. That's kind of a decision we make all the time in the business. The growth opportunities in transmission and distribution, we're looking very closely at. You've kind of -- I tried to give you a sense for the type of opportunities that are in the transmission business. I wouldn't necessarily say they are the same types of opportunities in the -- one-off opportunities, if you will, in the distribution business, but they are significant in the distribution business if, in fact, we start to, perhaps, accelerate smart meter technology throughout the system. The timing is going to be dependent, in large measure, on when we believe it's time to begin to expand rate base in those areas and take advantage of those growth opportunities. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Okay. So still not quite clear yet, but stay tuned. Perhaps, looking at the back of the regulated -- unregulated side, rather. The latest RPM auction, while you guys didn't want to disclose how many megawatts cleared kind of indicatively, if you would, in the latest auction relative to the last, how significant was the change in cleared capacity? Do you get what I'm asking? If you can provide anything. Anthony J. Alexander: Nice try. That's pretty good, though. Since you didn't know the first one or the second one, I don't really know how to answer that. The question was clear, though. You guys are getting better at this.

Our next question comes from the line of Jonathan Arnold with Deutsche Bank. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Tony, you may have sounded more enthusiastic about the economy than you have in a while. And even though the numbers -- the sort of sales numbers, were not -- we're not seeing it in the numbers, can you just sort of give us some more insight into what you're seeing in the customer base? And what's the basis for your commentary in the prepared remarks? Anthony J. Alexander: Yes, I think what we're seeing, basically, Jonathan, is -- we think the bottom is behind us now. Most of the plants that we think were particularly exposed, for example, the Ford Brook Park plant we talked about and that 1 steel operation, they were closed in 2012, and we're starting to see that the other items are up significantly. Some of the other steel mills that we have are up. So once you get kind of through this period that we think now is bottomed out, we're seeing some -- we're seeing really strong growth in shale areas, in steel-related, particularly item -- particularly, steel mills that are operating in the pipe-related types of activity. Like I said, housing starts are up. It's a slow start, but it's far more positive than what we've seen in the past. And we're starting to see some activity across each segment of the business. Are you still on? Hello? Jonathan P. Arnold - Deutsche Bank AG, Research Division: Yes, I'm sorry, Tony. Hit the mute button. You mentioned the accordion facility at the parent to upside that line $500 million. Does that have cost implications? James F. Pearson: No. It really doesn't have any cost implications other than you get, always, a charge for your unused capacity. So you have very minor incremental cost associated with it. Jonathan P. Arnold - Deutsche Bank AG, Research Division: Not something we're going to notice, then, Jim? James F. Pearson: Say that again, Jonathan? Jonathan P. Arnold - Deutsche Bank AG, Research Division: Not something we're going to notice? James F. Pearson: No, you will not notice it. No.

And our next question comes from the line of Paul Patterson with Glenrock Associates. Paul Patterson - Glenrock Associates LLC: I was wondering, just -- sorry to be a little slow here but Brian, I think, was asking this. What is the PJM, MISO transmission cost? What is causing that? Because it was also a thing that hit you guys had in the first quarter as well? Donald R. Schneider: Yes, I think, Jonathan -- this is Donny. The biggest driver there is just increased sales. I mean, we have to pay network transmission to deliver our product, in many cases. And so that's the biggest driver, but we'll net some other things against that. Paul Patterson - Glenrock Associates LLC: Okay. And then, the net financial sales and purchase, what was that? The $0.02 there? Donald R. Schneider: Yes, that's basically, when you look at that, we're hedging -- that's one of the instruments we use to hedge the congestion. So we'll do a financial sale and a financial buy to hedge the congestion, and that's the net of the 2. Paul Patterson - Glenrock Associates LLC: Okay. And then, just in terms of the nuclear expense, with the steam generators and everything, just -- is there any flexibility on that? You did mention that you were thinking of, potentially, augmenting the CapEx going forward. And I was just wondering, given market conditions and everything, whether there's been any change or any thought process on that, if there is any flexibility on that. James F. Pearson: Those steam generators, you're probably referring to the Davis-Besse that we're planning in '14; and then, we also have Beaver Valley 2 that's in '17. And although you could move that, it's very unlikely that we would because you have a pretty laid out schedule right there that you've got to meet and then you also got to plan what your outages are. So I think it would be very unlikely that we'd be making any modification to that construction schedule. Paul Patterson - Glenrock Associates LLC: Okay. Great. And then, just finally, with respect to the cost savings and stuff, you mentioned a lot on the benefit side and what have you. And I do see that the retirement benefit sort of noncash -- impact on the cash flow statement has sort of increased. Is that the kind of thing that we should be thinking about? Should we be thinking about this as being one of those things that over the long term provides savings but in the near term, that sort of accelerated in terms of the noncash accounting benefit because of the OPEB and the pension liability are lower? Anthony J. Alexander: No, I think the ones that we're talking about today, while there could be some impacts there, the ones we're talking about today are fundamental changes in plans. Single administrator, as an example. Changing in plans that have higher deductibles. Things of that nature are driving the real change and the cost savings. Paul Patterson - Glenrock Associates LLC: So it will have a direct cash impact pretty quickly, it would sound like, starting in 2014? Anthony J. Alexander: That's what we're expecting, yes.

Our next question comes from the line of Steven Fleishman with Wolfe Research. Steven I. Fleishman - Wolfe Research, LLC: A couple of questions. Just on the equity issuance through the DRIP programs, is that just a 2013 -- or do you intend to continue new equity through DRIP after '13? James F. Pearson: At this point, we would expect that this would continue throughout next year. And as we said, it would be about $100 million on an annual basis, Steve. So you won't see $100 million this year. It probably won't really get implemented until probably by the fourth quarter of next year. But we would expect that to continue into next year. Steven I. Fleishman - Wolfe Research, LLC: Okay. So from a model standpoint, like, just assume $100 million per year, really, starting in '14? James F. Pearson: That's correct. Steven I. Fleishman - Wolfe Research, LLC: And then on retail margins, it sounded like, if I heard it, you said that maybe you're actually seeing improving retail margins. Because it seems like most other people keep complaining that retail margins are declining. So maybe you could just give some color. Just clarify kind of what you are seeing on retail margins? And maybe, is it that you're targeting this different customer base or why do you think it might be very different than what we're hearing from others? Donald R. Schneider: Yes, Steve, this is Donny. I think it is the way we're pushing into the different channels. I think over the last several years, we have talked about our multichannel approach. And some of those channels are harder. I mean, retail sales, residential retail sales is much harder than selling to a big C&I customer. Generally, you get stronger margins there. You have to be very careful about your cost to acquisition. But if you think about, for example, our $0.07 for 7 years, in today's market, those contracts are paying very nice margins to us. In general, I think right now we've sold about 75 terawatt hours forward for 2014, and we're seeing an aggregate rate, about $1 better than what we're delivering this year. I think this year we're right about that $53 a megawatt hour. Next year, what we've got booked so far, will produce something right around $54 a megawatt hour. Steven I. Fleishman - Wolfe Research, LLC: Okay. And then, my last question is just on the -- you mentioned the Hatfield shutdown and Mitchell that's about a 10% reduction in megawatt hours, but obviously, a lot of cash flow benefit from that. The Other savings at generation in terms of cash flow, I mean, is there any additional impact on megawatt hour production? Or should we assume about that 10% reduction just from those plants? Donald R. Schneider: Yes, I would assume it's probably about 9.5 to 10 million-megawatt hours that would be associated with the Hatfield and Mitchell. So that's what I would assume for that. Steven I. Fleishman - Wolfe Research, LLC: But the other cash flow savings that you mentioned don't have any associated reduction in megawatt hours? Donald R. Schneider: No, no, no. That's correct.

Our next question comes from the line of Stephen Byrd with Morgan Stanley. Stephen Byrd - Morgan Stanley, Research Division: I wanted to just talk about the credit position and the equity needs. Regarding Harrison and the asset transfer, if that were to not be approved, how would that impact your thinking about equity requirements? Donald R. Schneider: I don't think that it would change our thought process on equity at all. Anthony J. Alexander: We've laid out our game plan for equity. Those will not affect our decision-making. Stephen Byrd - Morgan Stanley, Research Division: Okay. So a -- the period to get that transfer of Harrison would not -- wouldn't impact that, okay. Anthony J. Alexander: No. Stephen Byrd - Morgan Stanley, Research Division: Okay. And then, just switching over to transmission, you had mentioned a lot of potential growth. As you think about the financing and structuring of that, do you think much about different options in terms of how to finance that? Some folks have thought about a pure-play transmission approach or is this something we should just assume would very likely just continue to be funded sort of organically within FirstEnergy? Anthony J. Alexander: My sense is that we will look at a number of different opportunities and determine what's in our best interest and our shareholders' best interest going forward. Stephen Byrd - Morgan Stanley, Research Division: Okay. So that is something that you are -- you do think about a variety of options there? It's not set in stone that it will always be simply funded within FirstEnergy? Anthony J. Alexander: I think that's a fair statement, yes.

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

Tony, I just wanted to recap what I heard, so I apologize if I might be repeating some things. One thing you said is that the generation transaction would be at least a couple of pennies or more accretive to EPS starting next year, 2014. I think -- so the other thing that came out is that there's $875 million of reduction in CapEx over this time horizon of MATS. And if I can get what that is -- over what period, is it 3 years? 5 years? I forget what the time frame of that is. Thirdly, you mentioned about $150 million to $200 million of lower cost reductions. These are additional stuff. And if I'm right, you mentioned that a lot of them would be related to retirement benefits. And if I'm hearing that's lower deductible and everything. If I'm right, those would mean lower, I guess, pension or retirement costs, if I understand rightly, what was described in the Q&A. If I can get a little bit of a clarifications on what I said, if they are on the right track or not on the right track? Anthony J. Alexander: Okay. Well, let me deal with the first one, since I only said it's accretive. I think Jimmy said it's, what, a couple of cents? James F. Pearson: Yes. Anthony J. Alexander: So I think the couple of cents is kind of what you ought to be thinking about. The $875 million reduction in capital, I think that's -- was that 5 years? Over that 5-year time frame. With the bulk of that coming in the earlier years, the time when the MATS expenditures would be coming through. And with respect to the $150 million to $200 million, I think you're a little confused. The bulk of these expenditure or bulk of these savings relate to current employees. Somebody raised a question with respect to retirees, but the fact of the matter is, the medical plan benefit changes and the other change that we are contemplating in benefits and otherwise, are really related to the current benefit package we offer employees.

Okay. Fair enough. And then, if I heard, we might get 2014 outlook this year at EEI or is that what we should look forward to? Anthony J. Alexander: We'll give it to you when we're ready.

Our next question comes from the line of Angie Storozynski with Macquarie. Angie Storozynski - Macquarie Research: I have 2 quick questions. One is the $54 per megawatt hour margin for the retail business for 2014. Is that really comparable to the margins from this year, given that there's a change in mix? For instance, between retail and C&I sales? Donald R. Schneider: Yes. I think it's very comparable. I mean, if you think about what the markets have done as we booked those sales, the wholesale markets have dropped off fairly steadily over the last several years. And to be able to deliver a higher aggregate rate, I think is significant. Angie Storozynski - Macquarie Research: No, I'm actually more asking about, if there is, like, a significantly higher SG&A expense associated with those sales compared to the sales that are being executed this year? Donald R. Schneider: No. No, generally, I think, Angie, what you'd see is our SG&A expenses have come down. I would especially point to fuel, for example, has come down significantly based on the work we did last year. Angie Storozynski - Macquarie Research: Okay. And secondly, I know that you're still in the midst of the hydro asset sales process. But can you at least give us a sense of, at this stage, your expectations for the outcome of that sale as similar to expectations that you had earlier in the year? James F. Pearson: Yes, I think, at this point, Angie, we had the first round of indicative bids. We had a lot of interest in the hydro assets. We're in the process now of narrowing that down, and we're continuing to evaluate that. So I don't think there is any change at this point. Okay. Thanks, everybody. Thanks for participating in the call and your continued interest in FirstEnergy. Thanks. Anthony J. Alexander: Bye now.

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