Irene M. Prezelj - Anthony J. Alexander - Chief Executive Officer, President and Executive Director Mark T. Clark - Chief Financial Officer and Executive Vice President Charles E. Jones - Principal Executive Officer of Ohio Edison Company, Principal Executive Officer of The Cleveland Electric Illuminating Company, Principal Executive Officer of The Toledo Edison Company, Principal Executive Officer of Pennsylvania Electric Company, President, Firstenergy Utilities, President of Pennsylvania Electric Company, President of The Toledo Edison Company and President of The Cleveland Electric Illuminating Company James H. Lash - President of Firstenergy Generation Corp and Chief Nuclear Officer of Firstenergy Nuclear Operating Company Unknown Executive - Donald R. Schneider - Principal Executive Officer and President Leila L. Vespoli - Executive Vice President and General Counsel

Unknown Analyst Carrie Saint Louis Steven I. Fleishman - BofA Merrill Lynch, Research Division Irene M. Prezelj: Good morning, everyone. I'm Irene Prezelj, Vice President of Investor Relations, and I want to thank you for coming to FirstEnergy's Analyst Meeting today. Before I review this morning's agenda, I'd like to point your attention to the slide, which is also available in your presentation book. It contains the Safe Harbor statement, under the Private Securities Litigation Reform Act of 1995. For those listening on the webcast, this is also contained in the materials posted on our website. Please review this document closely as you consider the comments we will be making today. We have a full agenda and we'll kick the meeting off with Tony Alexander, our President and CEO. Tony will be followed by Mark Clark, our Executive Vice President and Chief Financial Officer, who will provide our financial outlook. Mark will be followed by Chuck Jones, President of our Utilities Group, who will review our regulated utility and transmission operations. Mark and Chuck will take questions after their presentations. We're planning a short break following Chuck's presentation; and then we'll have Jim Lash, President of FE Generation and our Chief Nuclear Officer. Donny Schneider, President of FirstEnergy Solutions will follow Jim; and Leila Vespoli, Executive Vice President and General Counsel rounds out our speaker list today. Tony will return to close the meeting, and he will take questions at that time. Members of the IR team will be in the audience with microphones. Since today's meeting is being webcast, I would ask those with a question to wait for the microphone so that everyone in the room and on the webcast can hear it. Finally, I'd like to announce that FirstEnergy is introducing an iPad app for investors today. This is a screenshot of the app, and you'll also see with your materials in front of you, the QR code that you can easily scan with your device here today. We will be introducing an iPhone app, shortly, that you'll also be able to get. The app can be accessed through our website or by going through the Apple Store and searching for FirstEnergy investors. We hope you will find this information useful. With that, I'll turn things over to Tony. Anthony J. Alexander: Thanks, Irene. Good morning, everyone, and thank you for joining us. Today, we'll be discussing FirstEnergy's strategy, our plans to grow our business, and how we expect to increase shareholder value. It's been about a year since we completed our merger with Allegheny Energy, and I'm very pleased with the progress we've made. Yet as you listen to the presentations today, you'll recognize that the merger is just one of the positive steps we have taken to better position FirstEnergy for the future. Let me start by saying our strategy hasn't changed. We operate 3 businesses, and have a substantial position in each. We draw first, flexibility, growth opportunities and financial stability. Our Distribution business has the largest regulated customer base in the United States. Our Transmission business is one of the largest holders of independent transmission assets in the nation. And our Generation business, operates one of the country's largest and most diversified competitive generating fleets. We do not need to grow our businesses by expanding rate base. Instead, we will continue to operate our company as we have in the past with a focus on our core businesses, operational excellence, retail sales growth and delivering solid financial results for our investors, including a strong dividend and investment grade credit ratings. Building on this foundation, I'm confident that our competitive business model, our diverse generating assets and the scale of our utility service area will help us become one of, if not the best-positioned company, in our industry. Today, we'll talk about our recent achievements, and our initiatives going forward. We'll discuss our plans to achieve the earnings guidance we've outlined, despite the headwinds faced by our entire industry. I will explain why FirstEnergy's position overall, provides a solid base to grow shareholder value, as the economy improves. Let me start with the Allegheny merger. It has been a terrific success story from the start. We worked through the merger approval process in about a year, an outstanding accomplishment in our industry, and the integration was even better than we expected. In fact, the merger has gone so well, that it sometimes seems like Allegheny has always been a part of FirstEnergy. The people and the assets are a very good fit. We essentially began operating as a unified organization from day one. We exceeded our first year synergy goals, and everything is in place to capture the savings up opportunities we've identified. At this point, we are making all business decisions as an integrated company. And as a result, tracking merger-specific synergies is no longer necessary, and we will no longer be doing it. And quite frankly, the way we operate the company, it would be a distraction. In 2011, we also achieved considerable success with our retail sales strategy. FirstEnergy solutions, our competitive subsidiary, captured new customers in Pennsylvania, and increased its governmental aggregation businesses in Ohio and Illinois. It now serves nearly 2 million customers across Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. We sell about 100 million megawatt hours directly to retail customers, and that's more than we did as a regulated company. Later this morning, Donny Schneider will talk more about our retail strategy, and how we are building a strong foundation for future growth. When we met with you last spring, we described our plans to continue delivering solid financial results, positive cash flow and a stronger balance sheet. Last year, we sold non-core assets like the Fremont Energy Center, the Richland and Stryker plants and a partial interest in the Signal Peak coal mine, and took other actions to reduce debt by $2.4 billion. We also recently adopted a change in our pension accounting method. And we made other -- and we made another significant contribution to our pension plan last month, that reduces the unfunded portion of our liability. As a result, we've driven our debt-to-equity ratio down to about 57%, and we will continue our efforts to further strengthen our balance sheet and financial position. Mark Clark will talk about the actions we are exploring to further enhance our financial profile, including opportunities related to the Bruce Mansfield sale leaseback arrangement, and the recent Ohio legislation that allows for securitization of deferrals. While we still have work to do, we are in a much better position today to meet the challenges of our industry. One of those key challenges is that our region is still stressed by the sluggish economy. For example, while industrial sales are improving with growth that facilities at GM Lordstown's plant, Chrysler Jeep in Toledo, and AK Steel in Butler, Pennsylvania, industrial sales are not as strong as anyone would like. We are also seeing limited residential and commercial growth. Although again, we do have pockets of very robust commercial activity, particularly in the healthcare, and in both Ohio and Pennsylvania, as the Marcellus and Utica shale fields are being developed. Overall however, sales have not yet recovered to the levels we had in 2007. In the current rate of economic growth, it is not strong enough to support higher power prices. Even though we're encouraged by increased capacity prices starting in 2014, overall improvement will depend on a host of market conditions including and primarily, the strength of the U.S. economy. One of the factors however, is -- that's also likely to impact what's going on, that is environmental regulations. And what they could do from a standpoint of cost of producing as well as the supply of electricity. These new environmental mandates will have an impact on FirstEnergy. For example, we recently decided to retire some older, less efficient Fossil units in response to EPA's stringent new standards known as MACT and other environmental regulations. We will however, make the investments needed to ensure that our remaining plants are competitive in the future. And we will focus our resources on the units that will remain in place over the long term. We've already reduced these investments by roughly half of what we anticipated last year. And we will continue to aggressively seek low-cost solutions or compliance and options to further reduce these capital costs. Jim Lash will talk more about our efforts and the expected impact of the environmental regulations on our fleet. Once our older Fossil units are retired, nearly 100% of the power we produce will come from resources that are low or non-emitting. Last night, we provided 2012 non-GAAP guidance of $3.30 to $3.60 per share. We also updated guidance for 2013 of $3.10 to $3.40 per share. The midpoint of each of these is within the range of guidance we provided last year. While these are not easy times for anyone in our industry, we are facing these challenges head-on as we always have. You can count on our management team to continue to drive costs and revenues, identify opportunities, and deliver on the commitments we've made to you. This is truly an exciting time for the company. The strength of FirstEnergy, rests on the diversity of its operations and the flexibility and responsiveness of its employees. And we are better positioned than ever, to grow, compete and increase shareholder value. Your support has been and continues to be greatly appreciated. Thank you. Now, I'm going to turn the podium over to Mark, and the rest of my senior management team will provide more details on the key areas of focus for 2012 and 2013. After each presentation, we'll provide time for your questions. And as Irene said, I'll be back at the end to close the meeting, and I will also be available for questions at that time. Okay, let's get started. Mark? Mark T. Clark: Thanks, Tony. Good morning. Before I start, I'd like to thank everyone for being with us today. We do appreciate it. As Tony said, no question, 2011 was a more than interesting year. Either selling assets, dealing with the weather, the integration of FirstEnergy, despite that we think we had a solid year. And we're looking forward to the next 2 years. My presentation today is going to cover 2 topics: First, I'm going to review 2011, and then I'll speak a little bit to 2012 and 2013. I suppose it would help if I put the slide up. But -- let me speak to 2012. As Tony just said, non-GAAP earnings for the year were $3.64, and GAAP earnings were $2.22 per share. Last May I stood up here and said our guidance would be $3.20 to $3.50, we changed that as we went through the year. We upped it a little bit. Now, we've ended the year at $3.60 -- $3.64. And also, a lot has happened between then and now, and I'll admit that this is an extraordinarily busy slide. But it does somewhat capture both the headwinds and the successes that we had last year. Three big impacts in terms of the difference between GAAP and non-GAAP, 2 negative, 1 positive. On the negative side, we have the mark-to-market adjustment for the pension accounting, which was $0.78. We had the generation impairment, which was $0.52 and as Tony alluded to on the positive side, we had Signal Peak, which was $0.93. Specific to the fourth quarter, weather was anything but cooperative. It was 17% below normal, and more than 20% below the fourth quarter of 2010. Generation output as you'll see on the upper right-hand side was down, as were wholesale sales. On the plus side, we continued to move customers from the polar side of the equation to the direct retail side of the equation. FirstEnergy solutions has done a great job with this, and I'm not going to stand up here and take Donny's thunder away from him. He'll be up here in a little bit. And the other important part of this slide is if you look at the lower left-hand corner, you'll see that Allegheny was accretive in its first full year although it was only accounted for 10 months. But it was accretive for the year. Let's look at the segment earnings. Last May was the first time we broke out the segments, and we continue to do so. You'll see that our regulated Distribution and our Transmission business more than support a solid dividend on the regulated side of the equation by itself, and our competitive business continues to grow and continues to be the underlying growth platform for the company. And again, I would remind you that Allegheny was only there for 10 months of the year. On the capital side of the equation, for the year, we spent about $2.4 billion, which is somewhat in line with 2 exceptions. First, we spent roughly $200 million on storms, principally related to Hurricane Irene and the October snowstorm. Chuck's going to give some perspective around the historic magnitude of those storms against some of the storms we had historically, and I think you will agree that these were well outside the norm. Also included in the capital is $257 million for the pension accounting change in terms of capitalizing overheads. And as I said, absent the storms and the pension accounting, we actually would have come in lower than what we've anticipated last May. We accomplished just about everything we set out to, in terms of 2011 financial initiatives. As Tony alluded to, synergy earnings were $270 million against our internal target of $210 million. So we're well ahead of where we thought we'd be. That's on the earnings basis. On a cash basis, it's $300 million. I know we talked about selling assets for quite a bit of time. We actually finally got that done. We sold the Fremont plant, we sold the Richland/Stryker peaking unit, and as Tony alluded to, we sold 1/3 interest in Signal Peak. Those 3 items alone contributed $800 million of cash to the company. More specific to Signal Peak, it resulted in a gain of $370 million, an equity increase of $50 million, and a deconsolidation of debt of $360 million. Signal Peak by itself, improved their balance sheet $1 billion. That's not bad for a project that started in 2008. In June, we successfully replaced our existing credit facilities with 2 separate facilities. We plan on beginning talks with our banks this year to extend those maturities to give us even more flexibility. So on a personal note, I'd like to thank all the bankers in the room for all their support, and I can assure you that both Jim and Steve [ph] will be contacting you shortly about the extensions. Similar to the financial initiatives, we made great progress with respect to the balance sheet. We eliminated $2.4 billion worth of debt, and importantly, and this is an important point, we aligned the regulated cap structures of the operating company with the regulated structure of which their rates are set. We continue to look for opportunities to strengthen the balance sheet that as I repeatedly said, we are not going to pay on economic premiums just simply to acquire debt. One reason the pension contribution made so much sense was that it reduced the liability, it was tax-deductible, and we didn't pay a premium. And we picked that number not for some unknown reason, the $600 million, but we believe when the discount rate goes back to 6%, we will be fully funded on the pension side. We expect that GAAP to be closed, and that takes nothing more than the 10-year treasury to get to 4%, which is more than reasonable. And we ended the year in a very strong liquidity position at $5.1 billion. Now probably 90% of you are in this room just to see this slide and how the hell we got to $3.30 to $3.60 and $3.10 to $3.40. And I'm going to start at the top of the slide and I want to specifically speak to 2012, but the same logic applies to 2013. Last May, we gave guidance of $3.20 to $3.50 per share. You know that in 2011, we've changed the pension accounting, which added $0.20 per share. So all things being equal, if nothing else changed, I'd be standing up here telling you the guidance was $3.40 to $3.70 per share. Unfortunately, some things do change. We have a sluggish economy, we have an unprecedented drop in natural gas prices, we have some pension cost changes and labor cost changes. The biggest item there is power prices. And that has the negative effect of changing our guidance by $0.20 per share. On the positive side, we've taken a number of actions to mitigate that drop. Tony just alluded to our announcement of closing 3,300 megawatts of unscrubbed coal-fired capacity. Donny is going to speak too, in greater detail, how we're moving customers around the retail channel to ensure greater margin, and we continue to look for opportunities to reduce O&M. I just want to give you one, very quick example, of what we're doing on the O&M side. We closed the transaction February 28 of last year. There are roughly 75 major applications that have to get integrated between the 2 companies. For some of the operating savings to occur, those systems have to be integrated. I'm pleased to say that our IT folks are basically going to integrate all of those applications in record time, and they'll make their cut-over shortly. They've had 5 test runs, so you'll see that some of the synergy has been accelerated and some of the synergies too, become, as we integrate our systems. And we're quite pleased with where we are. We'll continue to look for incremental costs. It's kind of our nature. But we're not going to do anything simply for a short-term benefit that puts the company at a longer-term risk. That's just not something we are going to do. Everything we are doing is to place FirstEnergy in the best possible forward position. We'll talk about segment earnings again. It's the same as what I talked about in 2011. The regulated side of the business produces significant, strong, solid earnings for the earnings -- for the dividend. We made one little change in the Transmission piece here. The regulated Distribution -- or excuse me, the regulated Transmission is now included in the regulated independent transition -- Transmission. Excuse me. That's roughly $0.24 a share. We think we've done that for the right reason. It brings out greater clarity in terms of what's truly Distribution and what's truly Transmission. And again, despite a very challenging environment, our competitive business unit continues to deliver positive earnings and Donny will speak about that a little bit. On capital. We're looking at capital completely differently than we looked at capital in the past. First, our baseline capital stays at around $2 billion. We broken out environmental spend, some of the Japanese nuclear spend and energy efficiency. Energy efficiency, as you know, is recovered to the regulatory process while nuclear cost associated with Japan are not that great. We used a plug figure last year and told you that we used a number of around $100 million, so we wanted to correct that and bring that up to current, and it's roughly more like $20 million. And this is the first time we're starting to include capital numbers for MACT. That number will grow, but that number is significantly below what our prior estimates were. And Jim Lash is going to get into that a little bit further. As I said, we're looking to capital completely differently. You'll take a power plant, we might look at it and say, if we put a Rapid rail unloader there, we might be able to bring western coal into that plant. That Rapid rail unloader's $20 million. Okay? Treasury gets $20,000, in investment income. The plant burns about 4 million to 5 million tons. I only need a $0.04 change in the price of that coal to offset what I would have done in the Rapid rail unloader. You have to look at capital differently in terms of how you deploy it. Maybe the fix for a power plant isn't to put the equipment on today. Maybe it's to coal fire it for a while and then decide where the market's going. But the point I want to make about capital and Jim's going to talk about that in greater depth, is that we're looking at capital completely differently than we would have been on a historical basis. Similar to 2011, we have financial initiatives that we have teed up for this year. Tony already alluded to the pension contribution. We're planning to restructure the $4.5 billion worth of credit facilities by extending their maturities from 2016 to 2017, and we're planning to replace the $450 million trail credit facility, with a $500 million facility at the Transmission holding company level. We think that will give us even more flexibility. Additionally, we intend to file an application with the PUCO, seeking an order pursuant to the new securitization legislation, which should also assist us in our planned debt reduction efforts at the Ohio utilities. Tony mentioned the possible early buyout to the Mansfield sale leaseback of 700-plus megawatts. We believe that this is the bright time to look at that and get that transaction done. In terms of cash flow, we're about where we thought we'd be for 2012 after you take out the pension and make an adjustment for the Mansfield sale leaseback purchase. For 2013, this is the first year that we're going to include the environmental spend and obviously we've updated for the sluggish economies so cash is going to be affected by both of those. When I look back at 2011, there was no question, we had some significant headwinds. But despite all that, we made significant success on the financial side of the equation. Going into 2012, we will stay focused on what's really important and what really matters. It's managing our capital program, maximizing the value of every single kilowatt hour we sell, strengthening the balance sheet and remain fully committed to a strong and stable dividend. Everything we're doing is to place FirstEnergy in the best position going forward. We accomplished a great deal in '11, and I expect us to accomplish a great deal in '12. And if you bear with me for a moment, I'd like to end on a personal note. Now back 2, 2.5 decades ago, when I was Treasurer of the company, one of the financial institutions ranked financial performance above the electric utilities in the industry. There were 104 on that list. You might remember 104 was Long Island Lighting that went bankrupt. We were listed 103, and the commentary was that this company was going to go bankrupt or be taken over. Well, as Tony alluded to today, we have the largest electric distribution system with over 6 million customers. We are one of the largest integrated independent transmission systems, and we're one of the largest and most diversified generation fleets. And why am I bringing this up now? Because I think FirstEnergy has a seasoned management team that's been through the fires. It's a management team that knows what's important. And most importantly, it's a management team that knows how to get things done. Thank you all very much, and I'd be happy I guess, to take some questions. Thanks. I'm like Tony, sitting down, I'm done. Mark T. Clark: Yes, Paul? [ph]

Can you talk about the implications of the sale leaseback, just from a financial perspective? Mark T. Clark: It would be accretive to earnings. We think with the power prices down, it's the right time to purchase it. We've made estimates that will affect our cash flow. It will affect that, but it should be accretive over the remaining term of it.

Can you quantify that? Mark T. Clark: It is roughly, Jimmy, what? $0.16 over the 3 or 4 years? Something in that range? Yes. When you add in, it's all net-net debt.

I wanted to start with your comment about the MACT spending, that it was below prior expectations of that $2 billion to $3 billion before? Mark T. Clark: Yes, we used the figure last May, and it was kind of a more of a swag estimate of $2 billion to $3 billion. Jim is going to talk about that a lot more but the estimate now is $1.3 billion to $1.7 billion, and we're still working on it. But I'll let Jim speak to that. I don't want to take his thunder. He's got a slide on that and gets into great detail on it.

Okay. And then, you said, it wasn't clear, the -- I guess, the cash flow slides on the Appendix, it was Bruce Mansfield and the 2012 cash flow guidance. The page that lays out your free cash flow for 2012, does that include the buyout of the Bruce? Mark T. Clark: Yes.

Okay, what bucket is that in or is that some kind of... Mark T. Clark: It's just inherent in the numbers.

Okay. So that's free cash flow of basically 0 where negative 100 includes that? Mark T. Clark: Right. The point was that the forecast that we gave last May would not have included the pension contribution and did not include the Mansfield. That's right.

And then lastly on the energy efficiency spending, because that steps up a lot in '13. Just what's the trend for that? Like how could we think about that, kind of, on a go-forward basis? Mark T. Clark: I think Chuck had alluded to that, but it's probably going to stay in that, slightly increase as we go forward. It's recovered to the regulatory process. I know the regulators are looking whether that's the most efficient use of capital, so I think that's a good number. I don't know Chuck, you want to change that? Charles E. Jones: No, Mark's correct. We have abilities to recover all of it through the regulatory process, so while we spend it, we get it right back.

Okay. Sorry, I had one more. What was it I was going to ask? I can't remember now. I'll come back to it.

You didn't comment about your dividend for this year going forward. What's the plan? Mark T. Clark: I think we have a solid dividend today, supported by the regulated side of the business. The Board looks at the dividend. I think we've said in the past, that we're going to have a policy that's consistent, understandable and sustainable. And I think that's where it is today. If the market changes and the prices change a little bit, we will look at it. But it's strong and stable today, and it's where it is. Steve? Steven I. Fleishman - BofA Merrill Lynch, Research Division: Yes, just a follow-up to that question. First, when you say we look at it, I assume you mean, we look at it upward? Mark T. Clark: That would be an understatement, yes. Steven I. Fleishman - BofA Merrill Lynch, Research Division: Okay. Just on balance sheet and cash flow metrics. Where did the balance sheet, maybe debt to capital end, at the end of '11? And where do you project it to be at the end of this period, and maybe same thing on the FFO metrics? Mark T. Clark: I think you have to look at it like we look at it, which is each individual component. The regulated side of the business on the Distribution side, we looked at to keep that at roughly 50-50, maybe a little bit higher debt. On the Transmission side, we look at keeping that 50-50, maybe a little bit higher on the equity side. On the holding company side, as much as we'd like to, the premium on that debt is too high, so we can't acquire it. We're not going to with those premiums. And so that leaves the FES side, and that is deleveraged. And one of the issues that we're dealing with for this year is we'll pay down the Allegheny Energy System-$503 million debt and we'll try to deleverage that business and strengthen that as we go forward. On the FFO, I think, Jimmy, we're at what? 18%, 19%? It takes roughly $1 billion to move it up, a percentage or so. We do have the $500 million, the $300 million, if we do some securitizations, some other things. We should significantly improve that over the -- for the course of the year. Steven I. Fleishman - BofA Merrill Lynch, Research Division: One last question on the mix of earnings. It looks like for 2011, if you go back to the May, the presentation last year, most of the -- you actually beat a lot on the regulated side, your old projection. And it seems to sustain into 2012, '13. Is that mainly the merger synergies doing better and we're seeing it there? Is that the pension adjustment or... Mark T. Clark: I think the pension, the merger synergies are in that mix, but I can just give you an example. We have a program called, work management initiative, where we're automating portions of the physical workforce and the utilities. Putting hard laptops in the trucks, allowing them to be -- GPS in the trucks, eliminating a lot of the paperwork that they have to do, and having the computer optimize their schedule rather than having a supervisor optimize their schedule. Some of the benefits that hasn't been rolled out across all of the opcos, but the benefits are 10%, 15%, 20%, 30% in increased efficiency in wrench time. So that's a big issue. We're becoming more efficient. Chuck's group has done a phenomenal job in holding their costs down. And I would expect he'd continue to do that. So I don't think you want to look at just one item. It's kind of a series of items. Chuck, you want to add anything to any of your successes? Charles E. Jones: Nope, you did well. Thank you. Mark T. Clark: Okay. I'll just turn it over to you. Charles E. Jones: Okay, good morning. Over the next 20 to 30 minutes or so, I'm going to update you on our regulated businesses. I'll first cover our 9 utilities, then spend some time on our Transmission business segment. And then following both of those, I'll take a few questions. For both business segments, I want to give you some highlights of our operating philosophy, review some of the highlights of the past year, and share some of our key financial metrics. As you can see from the map, and Tony already referred to this, last year's merger with Allegheny Energy has helped us put together a significant Utility business. We have over 6 million customers across 6 states, which makes us the largest at this time in the industry. And the fact that all 6 million customers are served in a contiguous service territory gives us operational benefits that can be easily shared across all of our utilities. Our customer profile has spread almost equally between residential, commercial and industrial customers, creating a well-balanced portfolio and strong, stable, regulated cash flow. Because we operate in 6 states, our footprint also provides us with regulatory diversity and minimizes exposure from any one jurisdiction. Our operating philosophy is pretty simple. Our goal is to operate reliably and efficiently. Operating reliably and meeting customer expectations ensures we remain in good stead with our regulators. Today, all of our utility operating companies except Mon Power, have reliability targets that are regulated by our state utility commissions. And in 2011, all of our companies except Penelec, were able to achieve those targets. Operating efficiently ensures we deliver on the financial commitments that we've made to our first energy parent and ultimately to all of you. Since 2008, we have significantly reduced O&M spending, and expect to hold it at current levels for the foreseeable future. In 2011, we delivered strong financial results that Mark's already talked about. The combination of our Utilities and Transmission business delivered 2/3 of our company's earnings, helping FirstEnergy meet its earnings commitments. We were also able to generate strong cash flow from our utilities that was adequate to cover the company's dividend payments. In 2011, we also made great progress on completing the merger of Potomac Edison, Mon Power and West Penn Power into FirstEnergy. We successfully implemented our regional model for how we like to run our utilities. This approach allows us to kind of deal with the company-by-company, state-by-state issues that are inherently different from operating company-to-operating company. We've used a sister company approach to help ensure we get up to speed quickly. We have assigned a legacy FirstEnergy Utility management team to work with each of the new management teams. Experienced managers work closely with their counterparts in the new companies to help them adapt to new FirstEnergy policies and business processes. This is the third merger that we've done, major merger since 1997, Tony referred to it. And I'd say by far, it's been the smoothest integration of the 3. Though culturally, Allegheny had a similar feel to the way we like to do business at FirstEnergy, and all the employees and leaders that have joined our company, have approached this merger with a very positive, can-do, attitude. We also achieved the merger synergy targets that we were assigned for FirstEnergy Utilities. In fact, we were able to double our assigned cash synergy in 2011. Mark said the final step to completing integration will occur in a few weeks, when we complete the cut-over of the Allegheny IT systems to our FirstEnergy platforms. This will allow us to finalize all the business processes and eliminate some temporary manual workarounds that we put in place over the past year. And no review of 2011 would be complete without talking a little bit about storms. It seems like that's all I've talked about for the past year. In August of 2011, we took a step back and we analyzed where we were at it with storm, SAIDI minutes at that time, and we were at 65% of our SAIDI minutes, were due to storm activity. On a normal year, we would have been at 35%. Through July, we dealt with ice storm in January, several significant thunderstorm events and 2 tornadoes. And it was at that point, the worst storm year we've ever seen. And just when you thought it couldn't get any worse. Hurricane Irene decided to plow right through our Eastern part of our territory. We barely gotten cleaned up from that one, when we had a severe winter storm hit in late October, which was unseasonable for that time of year for that area that we serve. Both of these storms allowed us to demonstrate one of the strengths I mentioned of a contiguous utility footprint. We were able to quickly deploy more than 4,000 FirstEnergy employees, including hundreds, and in one case, even into the thousands ahead of when the storms actually hit. Both of these storms were devastating in terms of magnitudes of customers that were impacted and as well of cost to repair the damage. And you can see some of the numbers here. Hurricane Irene was the first hurricane to make a direct hit on New Jersey and the mid-Atlantic regions since 2000 -- or since 1907. Not only was there significant wind damage throughout the territory but severe flooding hampered repairs. In the end, we employed a total of over 8,000 employees and contractors, and spent $89 million to complete repairs from the storm. I mentioned the October snowstorm was unseasonable for this part of the country. In fact, the areas that we serve that were impacted by the storm had seen less than 3 inches of snowfall in October in the last 100-plus years added together. For this storm, including the FirstEnergy employees that I've already mentioned, we had over 9,000 employees and contractors working to restore service and spent over $125 million. Snowfall, while the trees still hold their leaves, is by far the worst type of event we can have. And it's even more damaging as you can see than a hurricane rolling right through the middle of your territory. And mother nature normally takes care of that, gets the leaves down before we get to snow, but every now and then, she gets her signals crossed, I think. While I think we did a good job, both of these storms provided us great opportunities to learn. We've never dealt with storms of this magnitude in our history before. One key learning was the amount of communication necessary to keep our customers, safety forces, elected officials and regulators fully informed of the amount of damage and the status of repairs. Because we've never experienced a storm of this kind of magnitude, I don't have to say we underestimated what was needed from a communications perspective during Hurricane Irene. But immediately following Hurricane Irene, we are able to take these lessons learned and develop a more robust communications plan that served us well. And you can see some of the things we did. We used social media for the first time, got ahead of the storm in terms of some news conferences and really ramped up what we did from a communications perspective. And this is the slide Mark alluded to. I think it truly puts the magnitude of these 2 storms in perspective. You can see the repair costs for a dozen of our more recent events. Before Hurricane Irene, the worst storm in our history was Hurricane Ike in 2008. Hurricane Ike came up from the Gulf into Ohio, made a 90-degree turn and rolled right through pretty much all of our service territory and impacted about 1 million customers. Its repair costs though was only $42 million. Hurricane Irene more than doubled that cost and the October snowstorm trebled that cost. And then one final number on storms, in a normal year, we only budget about $65 million to $70 million for storm repairs for the entire year. So, it was a tough year, storm-wise. I'm tired of talking about it. You're probably wondering how we were able to deliver the strong financial results with all of these costs. And I'd say it has to do with the forward-looking view of some of our state regulators and the work of our regulatory affairs team. In New Jersey, Pennsylvania and Ohio we have mechanisms in place to deal with excess of costs from storms of this magnitude. And the 2011 income statement impact of both of these storms combined was less than $10 million. Clearly, they were terrible storms, I'm very proud of the efforts of all of our Utility employees who worked to restore service following these. But despite their efforts, we had a number of customers and communities that were understandably upset about how long it takes -- took us to restore all the customers. We continue to work to address some of the remaining issues from these 2 events. There's another perspective that I want to share with you and that has to do with a recent announcement by J.D. Power & Associates. For 13 years, J.D. Power & Associates has been conducting customer satisfaction surveys throughout the utility industry. One thing we've learned over those 13 years is that commercial customers are generally the most discerning in terms of reliability. And it's due to the fact that in many cases, if the power goes out, they lose revenue that they can never make up while the power is out. And you can see here from the results that in 2011, the 2 companies that were most impacted by both of these 2 storms Met-Ed and Jersey Central Power & Light, the 2011 results showed significant improvement for both of those companies. In fact, New Jersey, JCP&L, came in first place in the Eastern region and we're going to be collecting one of those J.D. Power trophies in the near future, and we're going to be proud of that. And I want to mention 50% of these surveys were taken after both of these storms hit. So while a small amount of customers can make a lot of noise following an event like this. I think this random survey by J.D. Power shows that when you get down into it, the bulk of our customers, who looked outside, who saw the damage, who saw the trees damaged by the snow, understood that this was a massive effort. And I think we really understood that these storms are -- I mean, I tell Tony, they are 100-year storms. So he's not going to have to worry about them again, hopefully. But they can't be prevented and you can't plan for them. And I've gotten questions at the Board several times about how we're going to increase our storm budget because of them and the answer is no. I mean, they are literally events that I don't think we should plan for. We plan for our normal operations. When they come, we will deal with them. All right, enough on storms. Take a few minutes to look to the future. On the sales front, we've talked about this. We're projecting a modest growth of 2% across our regulated utility footprint. I mentioned at the beginning, we've got good diversity of load. All 3 customer classes which helps bring balance to this picture. 2% shown here is also adjusted for any offset that comes from the energy efficiency mandates that we have to achieve. We're seeing some individual pockets of investment, Tony mentioned a few. You can see a few more on here. This is where the growth is coming from. While some of the industrial load that we had probably disappeared for good, following the 2008 onset of the recession, the ones that -- for the ones that have survived, the forecast is looking a little brighter. Steel and automotive is showing some pick up. There's lots of investment going on in Cleveland, which is the largest city that we serve, and the oil and gas drilling and refining industry is pretty much lined up with our Northern and Western PA service territory and then down on into West Virginia. When factoring that all in, we expect to continue to deliver strong financial results in '12 and '13. You can see our earnings projections on this slide. Earnings will be stable, and we are keeping our capital programs under control, so as to deliver strong cash flow back to the parent. To sum up my comments on the Utilities, I think we really have 5 things that we need to stay focused on. First, company by company, we need to make sure we maintain strong capital structures and earn our allowed rates of return for each one of these companies. We need to use our experiences from these 2 storms to build a more robust storm management process that incorporates all lessons learned from these 2 events. We need a successful completion of our IT integration for the former Allegheny companies, so we can finalize the operational processes and finally run this as one company. And we need to continue to drive more costs out of our business processes while at the same time meeting all of our regulatory commitments. This will ensure that we can deliver these financial results that we've talked about for both '12 and '13 and into the future. Mark mentioned to help accomplish this, we're implementing automated work management tools throughout our territory. All of our Ohio operating companies are complete. And we're in the process of implementing in New Jersey as we speak. These tools help us improve the planning and scheduling of the work, and ensure that we are using our crews as productively as possible and the improvements that we expect to get through that are going to help us control these costs into the future. Okay. That's it for our Utility operations. I'll shift to Transmission for a few minutes, and then I'll take some questions at the end. The completion of the merger last year has also brought a significant size and scope when it comes to Transmission. We're now the largest Transmission owner in PJM, and one of the largest in the United States. With more than 24,000 line miles reaching throughout the territory, the Transmission business segment represents a stable but also growing portion of our regulated portfolio. This is another area where the contiguous footprint gives us some operational strength, we can operate our Transmission system with little reliance on any other transmission owners being in the middle. Transmission reliability, remains a key to our strategy here, also. Like most of the industry, we benchmark Transmission reliability with a company called SGS. Each year, we set our targets at industry top-decile. And when you look at this chart, you can see that over the last 5 years, we achieved that goal in 2009, and we were in the range each of the other 4 years. Both '10 and '11 were significantly impacted by abnormally high storm years. Been a lot of significant accomplishments this past year in Transmission also. The TrAIL line was placed in service ahead of schedule when it began carrying load on May 17, 2011. This line represents a milestone not just for FirstEnergy but for the entire transmission industry to complete a 500 kV. 300 mile lines spanning multiple state jurisdictions within 5 years sets a new benchmark for projects of this type. And while I get the pleasure to stand up here and talk about it because it was completed on FirstEnergy's watch, I think it's only fair that I tip my hat to the former Allegheny executive and employees who were really responsible for this tremendous accomplishment. Along with the TrAIL completion, we moved into the new Transmission Control Center in Fairmont, West Virginia. This facility is a state-of-the-art facility as far as use of technology in the operation of the transmission system. We also completed the move of First Energy's ATSI assets into PJM this summer. While a lengthy process, as we believe this move positions us in an RTO that better fits our overall business objectives and ensures we operate our system in the most reliable fashion. In order to satisfy a NERC requirement, we decided to employ a laser surveying technology throughout our system to ensure that all load ratings of our transmission facilities were correct and achievable under peak load conditions. This newer technology called LiDAR has helped us identify and correct potential issues on a proactive basis. We also successfully completed 3 separate NERC Reliability Compliance Audits. One of the things we've worked hard on is to build a find-and-fix culture into our Transmission business with the help of our colleagues from FirstEnergy Nuclear. This questioning attitude, along with corrective action plans, has been extremely helpful in making sure we withstand the external scrutiny that comes with each of these Reliability Compliance Audits. We also used 2011 to make some structural changes in how we approach the Transmission business from a business perspective. In November, we successfully received FERC approval to use TrAILCo for transmission investments throughout the FirstEnergy footprint. This filing positions us such that any large transmission investments made going forward can be completed within ATSI or TrAILCo, including any PJM RTEP projects within the FirstEnergy footprint. Building these projects under one of our independent transmission companies ensures that we get clarity on returns and reduces any recovery lag because they will be handled under formula ratemaking. The skill sets acquired from Allegheny on transmission siting and construction will also be invaluable going forward as future projects are completed. We aren't sure on the reasons for investing in Transmission either. As the future unfolds, coal plant retirements will drive significant Transmission investment. While these units generate energy for end-use, they are also critical components of a reliable transmission network, providing both voltage support and reactive support to the transmission grid. Their retirements will require new electrical components to be added, either new generation or new transmission going forward. Okay, so what does this mean? We're likely to see increased transmission investment over the next 3 to 5 years. We'll work with PJM through the RTEP process to ensure any investment provides reinforcements well into the future. Some of this RTEP investment will further strengthen the ties between the former FirstEnergy GPU and Allegheny Transmission Systems in order to ensure we can operate the larger system in as most reliable fashion as possible. We may also look to make some investments to modernize some of the aging components of our transmission system. And one thing I don't see in our future is investing in large scale transmission projects outside of our utility footprint. We plan to stay close to home, make investments that have high certainty of completion and transparency as far as financial returns. Just like with our Utilities, earnings from our Transmission business segment should be stable over the next couple of years. We're also looking at relatively stable capital requirements in '12 and '13. Several of the Transmission projects that are included in our overall capital plan are shown on this slide. While we strive to invest as much of this capital -- we will strive to invest as much of this capital as possible under ATSI and TrAILCo. We believe we have positioned our Transmission business as a strong foundation for growth going forward, we've moved -- as we move forward, Mark talked about, we're going to do more structural change with the Transmission holding company to further strengthen how we do this business. Going forward, Transmission investment should provide strong transparent returns, as well as efficient recovery of operating expenses. And I'm sure you've already done the math, but if you add up the earnings from the Utilities and the Transmission, that puts us in the range of $2.45 to $2.55 in 2012, and we expect to build upon that in 2013. I think our entire Utilities team is focused on financial discipline and operational excellence, as Tony mentioned. So with that, we'd be happy to take any questions.

Is moving the transmission into the regulated company transmission into the transmission segment, is that a precursor or should we think of that as a precursor to a legal transfer of those assets? Or is that not something that you're contemplating? Charles E. Jones: I think it's something that we would obviously like to do at some point, but I don't think it's imminent. I think we'll get there at some point in the future. It's more just to kind of break the 2 business segments out so we could really see what's being driven from Distribution, what's being driven from Transmission.

Chuck, could you talk to what kind of economic growth assumption is underpinning the 2% sales growth forecast for 2013, and then maybe how weather and growth could interact to have a flattish pro forma sales in '12? Charles E. Jones: Okay, we'll take the weather one first. We plan for normal weather, we go to great pains to try to figure out what normal weather is, believe me, and I don't think there's any such thing as normal weather anymore. But in most years, you may have a warmer summer and a warmer winter that go together that offset. We haven't gotten off to a good start this year. In our footprint, it's been unseasonably warmer than you would expect in January and February. But over the year, the weather kind of tends to level out. Underpinning the rest, we've got about a 3% to 4% growth in the Industrial segment built in there, about a 1% growth in residential and commercial, that's offset by about a 2% reduction due to all the energy efficiency mandates.

I believe you have mentioned that you plan to earning your return on equity, so you don't expect any new rate cases filing in the future? And when do you expect any -- GAAP between earned and return? Charles E. Jones: I'd say right now, there are no rate cases imminent. We're earning right around our allowed rates of return in each of the jurisdictions and, I don't see any significant investments that's going to get us to that point in the near future. Our capital program kind of offsets the depreciation that's going on, so we kind of hang right around there with each one of the operating companies.

I noticed that CapEx for Transmission business has gone up in this year's plan versus last year's plan. Can you just talk a little bit about what's going into those numbers, and then what you think the right run rate is going to be for Transmission spending? Charles E. Jones: You asked Mark earlier, and the main thing that's going into it is the breaking out of the Transmission from the Utility segment. The CapEx that's underneath what was traditional capital is about half of what you see there. And about half of it is due to pulling the Transmission out of the Utilities and showing it within the Transmission business segment. Okay. Anthony J. Alexander: We are at a break time. It's 9:18. What time do you want us back, Irene? About what? Okay, about 9:32 or 3. Let's make a 15-minute break. Okay. Thank you. [Break] Anthony J. Alexander: All right. Why don't we grab our seats if we can. We'll get started again. All right. We're going to get back started here. And our next presenter is Jim Lash, the President of FirstEnergy Generation and our Chief Nuclear Officer. Jim? James H. Lash: Thank you, Tony. Well, it's a pleasure to have the opportunity to talk to you today. And first, I'm going to start out by giving you a brief overview of our fleet, as well as some of our key focus areas. Next, I'll talk about the impacts of some of the environmental regulations that you've heard about this morning, as well as the recent retirement announcement of some of our coal-fired units. And then finally, I'll discuss some of the capital projects and initiatives that we have to support our goal of optimizing our assets, positioning our generation fleet for growth, as well as upholding our commitment to safe and reliable operation. As you can see, we have a very large and diverse generation fleet, which is fueled by coal, wind, hydro, gas and oil and nuclear. This fleet is really comprised of 41 different stations and 109 units that are spread across the 6 states in which we operate. I believe this fleet is well positioned, and we believe this fleet is well positioned in the marketplace as a result of our transition to PJM in June of last year. It's clear to me that the synergies gained through the integration of our generation assets and the incorporation of best practices following the merger of last year has really positioned our fleet well for the competitive marketplace. And I believe this is reflected in our 2011 accomplishments. On the Fossil side, right after the merger we quickly assessed the performance of our new units, we scheduled maintenance outages and we made targeted investments in those units in order to address identified performance shortfalls. These steps enabled us to have this fleet run very strongly during the high-demand summer months as well as the rest of the year, for we're able to reduce our Effective Forced Outage Rate for the fleet by over 50% and to better our year-end target for this reliability indicator. On the nuclear side, we've also had a strong year in 2011. Davis-Besse was recognized for industry excellence. And the Davis-Besse unit achieved a 0.36% forced loss rate, which is really indicative of top quartile performance. Last year, Davis-Besse in the fall of last year replaced a reactor vessel head. And as you well know, it was during that outage that we discovered cracks in our containment shield building concrete. We performed a very thorough evaluation and assessment of that condition, and we concluded that the shield building was robustly designed, that it was a significantly reinforced structure that could continue to perform its safety function with significant margin. The Nuclear Regulatory Commission concurred with our conclusion, and that unit returned to service in early December last year. We have just completed the root cause, and that root cause has been provided to the Nuclear Regulatory Commission earlier this week and made public yesterday. What we discovered is that these cracks were caused by a significant weather-related event that occurred the year after Davis-Besse went into commercial operation. The report also outlines some actions that we'll take to make sure or to ensure that Davis-Besse shield building continues to function safely. And that will include a plan of weatherproofing coating to the exterior services of that building, as well as performing inspections to make sure that the cracks do not grow, and we will put in place a long-term monitoring plan for that structure going forward. Beaver Valley station also performed very well in 2011. Those units were also recognized for industry excellence, and the Beaver Valley units achieved a forced loss rate of 0.01%. That represents top decile performance. They were also recognized in 2011 and received the Utility Achievement Award for Best Performance given by the American Nuclear Society. That is the second time in the last 5 years that, that station has received that award. Last year, I discussed a common approach to safety, human performance and best practices. I'm here today to tell you that I'm very pleased with the progress that we've made in this area. We are leveraging safety and human performance from our nuclear experience across our entire fleet. We have also leveraged the expertise in our generating units to develop maintenance best practices that are now being deployed across the entire fleet. Some examples of that would be our transformer and turbine generator maintenance programs that are being used by both nuclear and fossil. Now we selected these programs because last year, quite honestly, early in the year we had challenges in performance with transformers and turbine generators, and I'm convinced that these programs will help us turn around that performance. We've also developed outage management guidelines that I consider best practices, and those guidelines focus on safe and efficient execution of our outages. They're particularly focused on determining the proper scope, making sure that we have detailed execution plans in place that we've resourced our outages correctly and that we safely execute them. These guidelines also complement our ability to share resources across our fleet. I spoke of the Davis-Besse outage earlier. We have fossil staff at that outage and that worked out very well for us. First off, it helps us defer the expenses of contract resources, and it actually results in higher quality work being performed because our personnel are vested in the units. Our integrated generation business plan establishes these focus areas as keys to our success. The actions I just described support the focus areas of safe -- safety, human performance and reliable operations. Another key focus area for us is the development of the management model, which will result in standardizing our approach and simplifying our daily operations. Examples of some areas covered by the management model are standardized corrective action program, common substation maintenance program and boiler tube failure programs. We have established in our fleet paired teams on both the nuclear and fossil side. These paired teams are charged with the responsibility to identify performance gaps and then close those gaps or use of the management model by employing standardized best practices to address those shortfalls. This management model should also benefit us as we look forward to other opportunities to improve the material condition of our units, as well as improve the reliability of those units. And moving forward, we will remain focused on the operational and financial targets and maintain a highly skilled and qualified workforce. As you all know, we recently announced the retirement of 9 units, 9 older coal-fired units as a result of the Environmental Protection Agency's, Mercury and Air Toxics Standards Rule, known as MATS. So let me make it perfectly clear. MATS put these units out of business. And the reason we're shutting them down now, as you've already heard, is that we intend to channel all of our resources towards ensuring that the remainder of our fleet is in compliance with that rule in the timeframe required. The breakdown of these 9 units, as you can see, is 6 on the competitive side in the states of Ohio, Pennsylvania and Maryland; and 3 units on the regulated side in West Virginia. Currently, we are in discussions with PJM as they review the reliability impacts of these retirements. You can see that through these retirements, we will see a capacity reduction of approximately 3,300 megawatts, which is about 14% of our generation. In 2011, our output was roughly 106 million megawatt hours, and these retiring units comprised about 10% of that output. By 2013, as you've heard before, we will be nearly 100% low- or non-emitting in terms of our generation fleet. And the breakdown of our fleet at that point will be on a capacity basis above 58% scrubbed coal, 21% nuclear, and 20% gas, hydro, wind and pumped storage. If we look closer at our competitive units, this slide shows that while our competitive capacity will decrease, we plan to make up for that following the retirements by expecting to make up for that with output from -- by improving the capacity on the remaining units in our fleet. In 2013, the first full year following those retirements, we expect this fleet to generate in an output of 100 million megawatt hours. And as I've stated previously, that will be from sources that are non -- or low- or non-emitting generation sources. I think this is a slide that I know is very busy, but I know that there's a great deal of interest in. This is -- this shows you what are the impacts and how we're going to deal with MATS on a unit-by-unit basis. First off, I know there's a lot of acronyms on this slide. Those acronyms, you can find them on Page 1 of your Appendix, but I will talk to a couple of them. The strategy that we're using in complying with the MATS rule involves a least capital approach model. What we're doing is using current emissions, and then stack data -- additional stack data that we will take in the first quarter of this year. And with that information, we plan to deploy numerous low-cost -- lower-cost technologies to ensure compliance. And we're viewing compliance on a plant basis versus a unit basis. We are also exploring co-firing some of our units with natural gas and coal. We'll consider additional dispatch approaches, and we'll even consider derating units considering this marketplace in order to ensure compliance. Now last year, I told you that our spend -- our capital spend was $2 billion to $3 billion to comply with this rule when it was MACT. Now that we understand the rule and we've dug into it and analyzed the situation more deeply, we are right now looking at a $1.3 billion to $1.7 billion spend to comply. And we continue to work further to reduce that cost. And we will be in compliance by the spring of 2015. To ensure that our plan holds up, we've engaged a well-known independent engineering contractor to validate our approach and make sure that we -- our plan is solid when we start its implementation later this year. The company is also well positioned regarding the EPA Cross-State Air Pollution Rule. Now as you all know that rule has been put on a stay, which does create some uncertainty. Now our plan for dealing with that rule is not yet fully developed, and it is largely dependent on what we finalize in terms of dealing with MATS later this spring. This slide should -- shows you that we are -- we will attempt to balance with our environmental spend, capital projects that will also look to improving, where we can, reliability in our units. On the fossil side, we'll change out a rotor at the Bath County's pumped storage -- a generator rotor at the Bath County pumped storage facility. We'll upgrade our turbine rotor at the Fort Martin unit 2 unit with a new turbine rotor, and we will do boiler work at Hatfield and Harrison. On the nuclear side, we'll replace rotors at Beaver Valley and Perry stations, which will result in roughly a 74-megawatt additional output. We'll replace -- continue to work on replacement of steam generators at Davis-Besse in 2014 and Beaver Valley in 2017. And finally, we'll work to continue license renewal, beginning with Davis-Besse and then wrapping up with the Perry station. As you can tell, our assets -- as you can tell, FirstEnergy's integration -- integrated fleet has much on its plate in the years ahead. I'm pleased with the progress we've made in solidifying our fleet approach and maximizing our use of best practices across our fleet. The work we've completed, I believe, positions us well to optimize our assets and achieve some growth. And it also improves the effectiveness of the remaining units in order to compensate for those units that we're retiring at the latter part of this year. In 2012, we will take market conditions into consideration, when we will make smart investments in our nuclear and fossil units. We plan to complete our outages, complete our environmental upgrades, our capacity improvements, and we'll work on license renewal at our nuclear stations. And finally, we will shut down those units that we plan to retire in a safe and orderly manner. I look forward to leading this integrated fleet to operational excellence, working through the challenges of new regulation and delivering the results that support our company in achieving its financial and operational objectives. Thank you. And with that, I'll take questions.

Can you give a little bit more color in terms of what were the changes in the new assumptions that you're making for the MATS CapEx. What has led to that significant decline? Does it mean more shutdowns or whatever? James H. Lash: Okay. If you look at that slide, you'll see that what we're really focusing on is improving the efficiency of our electrostatic precipitators and our scrubbers to achieve compliance rather than the use of fabric filters. The estimate I gave you last year made extensive use of fabric filters at all of our supercritical units. And those, as you know, are very expensive pieces of equipment. So what we're doing is upgrading the precipitators and using other technologies to improve their efficiencies, such as dry sorbent injection and activated carbon injection. And if you look at that slide, you'll see that there's now only 2 stations that have new fabric filters, and they are the Hatfield and Harrison stations. And they are not -- the number for those stations is actually 2 fabric filters for Hatfield and 1 for Harrison. So not every unit gets one. So that's what really led to the reduction in our estimates for achieving that.

Great. Follow-up question there. First, with regard to the finalization of the MATS rules, it seems like perhaps some of the particulates and sales went down, so I'm a bit curious maybe from your perspective, to what degree was the final rule different from the draft closing? Did that change this, or what was it more realizing we have an ability to tap our existing ESPs to meet these targets? James H. Lash: Well, that had -- that was an input of course. The rule was relaxed somewhat in terms of filter ball particulate. So that did help. But I think the greatest reductions were achieved through the technologies that I just talked about, but that was a contributor.

Great. And then maybe a follow-up, and you still talk about a pretty big billion dollar-plus number here. From a timing perspective, I know that's definitely a focus of the industry right now. When would you expect to see the bulk of this CapEx, excluding out '12 '13, is it a '14, '15, '16 that we really should be focusing on here? James H. Lash: Well, the bulk of the expenditure is in '14 and '15.

Great. And then just a final clarification, you talked derating the units just a little bit, is there an ability to fuel switch here, maybe bringing some PRV. You talked about that a little bit earlier, is that part of the plan? James H. Lash: Well actually, without getting too much into the details here, the technical details, by using these technologies the we're talking about, we're going to have to remain fairly stable in terms of our fuel mixes because there's -- it reduces some operating margins. And so we will establish a fuel design through [indiscernible]. And then based on that fuel design, we'll work with these technologies to achieve the reductions that we're looking for.

Yes, 2 questions. One, on MATS, can you believe that a plant that burns appellation coal has to install a wet scrubber to be able to comply with MATS, whether it's your plant or any plant? James H. Lash: I'm not sure I know the answer to that. I may have to call one of my fossil experts to that. But I don't know the answer to that. Charlie, do you have a...

[indiscernible] reductions, but that's not a direct side on that. But there is a corresponding substitution roles such as [indiscernible] in general [indiscernible] you have to have that or [indiscernible] injection.

And just follow-up on the fuel switching question. Have you seen, not just for your company but across the industry, a potential shift towards, as more plants get environmental controls, appellation coal plants may be shifting the burn at more Illinois basin. And are there any constraints like rail or other transport constraint that could keep that from happening? James H. Lash: Well yes, I think from a sulfur standpoint, there is a migration -- or folks are moving to fuel, coal, away from appellation coal. However, the transportation of that coal almost offset some of that. It's a -- the costs are very high. So I really -- I think Donny's going to talk to that. He's going to talk about what our outlook is on fuel cost. Hopefully that will address your question further.

I wanted to sort of touch base on the capacity factor increase in 2012. I know that when you guys were dealing with the merger, you expected to see a substantial increase in the supercritical capacity factor due to dispatch arrangements with PJM. I'm wondering how those went, and how they're being projected in 2012. And also just in general, just -- is it just -- why is the dispatch, why is the capacity factor rising so much in 2012 versus 2011 for scrubbed coal because the capacities if I'm looking at these look about the same. The total megawatt looked about the same. So why is the capacity factor, if I understand this correctly, moving up so much. I'm sorry if I missed that. James H. Lash: Well the capacity factor in 2011 for some of our units was impacted again, by market prices, and they were placed in reserve. So we ran some -- a number of times we ran with our supercriticals in reserve. We're now looking at hopefully that will not be and replicated this year and that capacity exists there. And we can run those units to achieve that output.

What caused it to do that? I mean just -- I'm sorry to be slow on this, but what is it that changed in terms of 2011 versus 2012 versus this reserve versus it not being that way? James H. Lash: Market prices were lower, considerably lower.

Okay. So that's -- basically it's a dispatch factor. And the arrangement with Allegheny and the supercriticals, has that got anything -- because I know that you guys had thought previously that if you had a must run dispatch agreement that you guys might be able to boost that capacity back to with Allegheny. How did that work that? How is that going so far? James H. Lash: Donny, do you have a... Yes, I think that's probably -- Donny's here. Donny, why don't you take care of that? Donald R. Schneider: It's working out quite well. We have now started to dispatch all of the Allegheny units. In fact, we really did it within a week of the completion of the merger. We started dispatching all of the Allegheny units from our West Akron Campus. And it's amazing me. Within a week, you would do a morning meeting and if you didn't know, you couldn't tell which units were Allegheny units, traditional Allegheny units and which ones were traditional FirstEnergy units. And so we started to implement that same kind of a strategy that we had in our supercritical units. Those units responded quite nicely, and that's fully implemented today.

Could you talk about the PJM process, and in terms of the timing of their reliability determination? And if they do determine that some of the plants that you've proposed to shut down are needed for reliability reasons, what does that imply? Does that imply an RMR contract or does that imply them just imploring you not to shut them what -- sort of what happens then? James H. Lash: Well as I've already said, we are very early in that process. We have sent in our deactivation letter on the 26th of January of this year. And the PJM has responded with what they see as some reliability challenges, but it has -- but they made no reference to generation assets and what units would be designated as RMR units. So we're very early into that process. We expect to get more clarification in that regard over the next 60 days. And so I really can't answer that anymore specifically today.

Yes. Just one question on the MATS compliance. A lot of the things that you mentioned for some of the plants may have some impact on your O&M cost potentially. Could you give us a sense on what the MATS could do to O&M cost of the overall fleet? James H. Lash: Actually, I don't have a quantified number for increased O&M cost. There will be some additional O&M cost because there's additional equipment that has to be operated and maintained and monitored. So there is some of that, but I can't tell you what that number would look like today. We have one more. Irene M. Prezelj: This will be the last question then.

To the extent that you bid a coal plant with environmental upgrade into the upcoming auction, what are the rules with respect to qualifying to get that to accept whatever price you get in this year's auction for a 3-year period? In other words, should we assume that any of your plants that bid would be entitled to receive the current year auction price for 3 years, or how does that work? James H. Lash: Well, I'm not the auction expert. I'll refer to Donny on that one. Donald R. Schneider: The 3-year payment that you're referring to would only be for a new unit going into service, not a unit that you're retrofitting. Donald R. Schneider: Good morning. I'm Donny Schneider, President of FirstEnergy Solutions. I have responsibility for retail sales, commercial operations, fuel procurement and unit dispatch. Here are the topics that I'll be covering today. FES's target markets remain the same. We continue to focus on these 6 states. However, let me point out one item that has changed since last May. Back then, this map was segmented into 3 categories: home, close to home and market sourced. As a result of our fully implemented and very successful asset-backed sales approach, we now view our sales territory as only 2 categories: generation sourced, which is the majority of our sales; and to a much smaller degree, market sourced. FirstEnergy Solutions now serves nearly $2 million residential, commercial and industrial customers in these 6 states. According to the most recent industry data, FirstEnergy Solutions now ranks #2 in both nonresidential retail sales and in domestic electric-only residential sales. You'll note this slide looks a lot like the one I presented last year. That's because our strategy has not changed. We continue to leverage our generation assets selling the power that we produce in our power plants to our end-use retail customers. Through a multi-channel approach, we have significantly grown our customer base in a truly organic fashion, which we have found to be extremely cost effective. Let me explain what I mean by organic fashion. While other competitors increase their customer count by acquiring retail sales companies, FirstEnergy Solutions has been able to achieve the same level of growth by utilizing internal resources at a fraction of the cost. As part of our strategy, we continue to focus on reducing our fuel expense to achieve world-class procurement. And we maintain and enhance the efficiency of our plant operations. Let me take a moment to highlight an item that Jim mentioned in his presentation. While retiring these 6 older coal-fired plants in our competitive fleet was a very difficult decision, the loss of these plants will not negatively impact our channel sales. In fact, it simply means we will utilize the wholesale market to a very minor degree in order to serve our customers when our big machines are on scheduled outages in the spring and in the fall. I'll come back to this point in a few slides. Our multichannel marketing approach means we go deep and wide in the territories we target. In other words, we pursue every customer class in those markets. We strongly believe that this multichannel approach is far less risky and more profitable than simply relying on one part of the business. This chart lists the 6 states where FirstEnergy Solutions does business and the 5 customer channels that we target: POLR, governmental aggregation, mass market, large C&I, and medium C&I. You can see we have fully implemented our multichannel approach to securing customers in every channel that's available to us to gain market share and increase our profitability. When it comes to POLR, we continue to be selective. Looking at POLR in Illinois, Amron [ph] procures electricity for customers through the Illinois Power Authority and that is currently not an interesting opportunity to FES. Lastly, in some cases, we are limited by the level of market development. For example, regulators in Pennsylvania and in Maryland have not yet embraced governmental aggregation, which continues to be the most cost-effective method of bringing savings to residential customers. I want to touch on this very quickly. One of the main reasons behind our multichannel approach is to ensure we maintain a balanced customer portfolio to reduce risk. I mean a high proportion of residential customers can result in increased risk with a very spiky load profile. On the other hand, having only industrial load is precarious in a weak economy. The key takeaway is that having a fairly balanced portfolio, such as the one we've achieved, provides greater stability over the long term and diversifies our risk. It's interesting to note that our current customer portfolio looks a lot like the customer portfolio of a Midwestern utility. That's by design. That's what our machines were built to serve. This slide indicates our updated 2012 sales position. As you can see, we've included the past 10 months to show that FirstEnergy Solutions does not try to time the market. Instead, we strive to sell and renew our book in a ratable fashion to minimize risk. There are 3 points on this chart that are highlighted. The first, which is at the bottom left indicates our position at last May's analyst meeting. The second large point shows where we are today, and the point at the top right of the chart indicates our goal for the year. Today, we have closed 89% of our channel sales position. I'd also like to point out that we have increased our total expected channel sales for 2012. Last May, the total was 95.7 terawatt hours. Today, we have set a target of 104 terawatt hours. This slide shows what our 2013 sales position looks like. Similar to the previous slide, it also shows the previous 10 months positions. Today, we've closed 56% of our total channel sales position. As in previous years, our strategy is to have about 90% of our 2013 sales under contract by the end of this year. Now that we've covered our current state, let's focus on where we expect to be in the next few years. This chart clearly shows that we have successfully held the line on our fuel expense. And we did in fact achieve our targeted fuel cost for 2011. Last May, we projected fossil fuel cost of $28 and $29 for 2012 and 2013. As you can see, our expectations have not changed. Also, nuclear fuel continues to remain relatively flat. By being able to fully leverage our sales channels mix and placing a greater focus on selling to higher-margin customers, we will hold our 2012 rate at $57. And although the wholesale market has dropped over $10 a megawatt hour since May of 2011, our sales forecast for 2013 has only decreased $4 from $59 to $55 a megawatt hour. Continuing to be successful in a recessed economy is a result of holding fast to our strategy, which has allowed us to effectively mitigate the effects of a weak electric market. I mentioned earlier that the retirement of our older plants was a very difficult decision. I also said that it would not negatively impact our channel sales. To explain my point, I'm going to illustrate our 2013 projections. In 2013, we plan to sell about 112 terawatt hours, while Jim will only produce about 100 terawatt hours from the fleet. To accomplish this level of sales, we will need to purchase a very modest amount of power, 12 terawatt hours. While this volume represents less than 11% of our portfolio, it's important to understand when we buy the power and who we buy the power from. First, we'll need to purchase only 2 terawatt hours on peak throughout the year. Let me remind you that prior to the last merger, our organization was responsible for purchasing 30 terawatt hours per year to serve POLR load, which has given us a wealth of experience in this area. Next, our long-term purchase contracts make up about 3 terawatt hours. These are legacy contracts such as our wind and OVEC agreements that have been in place for many years and will continue into the future. And lastly, in the past when our supercritical and nuclear units were in outage, our older units were brought online to replace the generation. With the retirement of these older units, we will need to purchase about 7 terawatt hours to cover the scheduled outages. These purchases will occur in the shoulder months, in the spring and in the fall when the price of power is very low. Essentially, we'll take 7 terawatt hours from a weak wholesale market in the shoulder months. And through our retail strategy, we'll sell it profitably to end-use customers. As I mentioned earlier, being able to fully leverage our channel mix allows us to pull different levers and ultimately improve our profitability. Here, I'm illustrating our capabilities at a high level. But I should also point out that our team has developed the expertise that allows us to analyze our sales channels to pinpoint the most profitable customers. This sophisticated modeling gives us the ability to examine and then target the highest margin customers at the channel level in each utility for every product type and even down to the individual customer. Our enhanced capability to optimize almost profitable channels will be key to our continued success. I'd like to point out government aggregation, which we expect to increase almost 40%. FirstEnergy Solutions is the most experienced governmental aggregation supplier in the marketplace, and we have a proven track record of delivering results. We look forward to continuing to bring that expertise to the rest of Ohio and Illinois. We also look forward to continuing our mass-market effort to build our residential customer base. Consistent with the strategy we laid out in 2009, we've continued to reduce our dependence on POLR sales. You've all heard me say although POLR sales quite frankly are the easiest to participate in, the volumetric swings in that channel make it extremely risky. Over the last several years, the volumetric risk has been primarily a result of customers shopping away from POLR suppliers. This can leave the supplier long in a very soft wholesale market. However, when electric markets recover and I do believe they will recover, companies providing POLR service could experience dramatic volume increases as customers return at very low POLR prices. Here's a real-life example of this situation. In 2006, FirstEnergy Solutions was under contract to serve all of the FE Ohio utility load. When wholesale electric prices increased, one competitive supplier saw an opportunity and dumped about 5 terawatt hours back on the utility. At that time, natural gas was trading at about $10 a decatherm. The electric market was seeing on peak prices approaching $100 per megawatt hour. FirstEnergy solutions contract with those utilities was a full requirements contract and it was at $42 a megawatt hour. Sounds a lot like a POLR contract today in Ohio. When all is said and done relative to the market, we served that load at times at a loss of $58 per megawatt hour. It was a big hit to our margin back in 2006, which makes me wonder if the participants in today's POLR markets are properly hedging and pricing that risk. Before I wrap up, I want to touch briefly on a few of our major initiatives that will enable us to continue to drive our strategy. In the retail arena, we will maintain our focus on leveraging the flexibility of our various sales channels, so that we are continually able to obtain the highest margins possible at any given time. FirstEnergy Solutions also understands the significant competitive advantages to introducing new and innovative products. And although I have not talked about our next generation of products, we believe that this capability is important to building our book of business. To maintain our level of success in the retail arena, requires that we sustain a highly effective back-office, which means that we will keep enhancing this area of the business to ensure our competitive edge. Moving now to our major initiatives regarding fuel. One of our major initiatives involves strategic investments to improve our fuel logistics. For example, our rapid rail delivery system at our Harrison plant, which will greatly improved our flexibility, is expected to be operational in November of this year. In addition, we plan to further leverage our market position and utilize our fuel switching capabilities. I think Jim also mentioned that we're pursuing gas co-firing. Not only will gas co-firing will help improve our environmental compliance but will also introduce competition into the coal supply market. Finally, on the heels of our successful mission allowance auction that we held back in December, FirstEnergy Solutions is interested in a second auction when the Casper rules become clearer. Let me close by saying FirstEnergy Solutions continues to be well positioned, to grow our earnings contribution. We have a proven sales team that will maximize our margins, our seasoned fuel and unit dispatch teams have a strong track record of leveraging our position to achieve savings. And as always, our low risk strategic approach will ensure steady, predictable results year after year. Thank you, and now I'll take questions.

Yes, I'm just not sure I'm understanding going back to your Slide 11, where you're purchasing only 2 million megawatt hours on peak. I mean, if you're essentially selling half of your intermediate or low following units in Ohio, what assets essentially are you making up for in terms of providing on peak power?

That's a great question. I think Jim pointed out, that we look for higher capacity factors out of the supercritical units. He has shown that it will generate about 100 terawatt hours. If you look in the appendix, let me get the appendix, Page 43, you'll see our total sales come up to 112 terawatt hours. So it's simply the difference.

Right. But I mean, if you're going to be under any scenario, you're running your supercritical flat out during peak demand periods. So in theory, I don't see how that would change and give you extra megawatt hours at peak -- on peak. In other words, I could see how it would give you additional megawatt hours to sell, but I don't understand how that adds to your peak portfolio.

Well, it really gets into the wholesale sales. If you think about what we've historically done, summer of 2011, July, I think it was the 17th or the 27th was the hottest day in PJM. That was an all-time peak demand. In the peak hour, we were only about 500 megawatts short at that point, but that was only the peak hour. If you looked 2 days later, in that same peak hour, we were long. So when we model 8,760 hours, we look at our portfolio of sales, we compare that out against the generation. And so with great certainty, I can tell you it's only 2 terawatt hours on peak. Any other questions?

You obviously -- you're taking a lot of share away from wholesale and the other pieces of the business in the retail channel. You would the uncertain in AAP's territory and potential maybe to shop more there or at least on an interim basis until there's clarity. How could this mix shift and what customer classes are going to more actively pursue, maybe to further high-grade the mix from once you get these numbers?

So Dan, are you asking, is there more beyond the 112?

Well, maybe more about 112 or maybe the mix within these customer classes shifts even further to capture more margin from where you are right now.

Yes, that's a great question. Yes, one of the things that we're working really hard on is to understand the most profitable customers and pursue those most profitable customers. You can see how we've achieved some of that channel movement already in one of the slides I've presented. We will obviously continue to do that and we'll pursue those more profitable channels. We're probably capped out at about 112 terawatt hours, but movement within will continue to deliver profitability to the corporation.

Yes. Slide 9, when you were talking about your, I guess it's projections for your fuel cost basically being the same. I was just kind of wondering, what -- is that being driven by hedges and things you'd already put in? Or is that you're kind of looking at the way fuel prices in general have been moving in the last year and that's kind of kept to protection there? Sort of what's I mean the big thing that keep that flat for you?

So, we've been working hard, I laid out last May, that we would hold the same kinds of numbers and that we would use our size to leverage the coal suppliers. We've been successful with that. I had a question at the break, with the falloff now in coal prices, is there opportunity to go even lower. And there may be some, but right now we're about 80% hedged for 2013. One more question.

Could you just talk about 2014 and where you would be hedged right now under your strategy and just anything else that you would provide color on for '14 and when you'll provide that guidance?

So I'm not going to touch the one about providing guidance but I can tell you from a hedge position, if you just simply look at how we achieved a ratable hedge, and the fact that today, as we look at 2013, we're about 56% hedged, you can take that same kind of extrapolation and you're going to find out that for '14, we would be right on a straight line to be able to get to where we need to be, 90% completely hedged by December of '13. Leila L. Vespoli: Okay. Now that we got that squared away, I'm Leila Vespoli, Executive Vice President and General Counsel, here today to provide you with the regulatory update. I am truly proud of the regulatory adeptness demonstrated by my team, and I use the term "team" for a particular purpose. And that's because at FirstEnergy, we employ a true team strategy when dealing with regulatory issues. I think that's something that differentiates us from our peers. Legal, rates, governmental affairs, communications, all of which report up to me, really work in a coordinated hand-in-glove manner that allows us to achieve the results we have and in the timeframes we have. For example, the merger with Allegheny, we are able to complete that within a year's timeframe. For our industry, that's near record timing. As alluded to earlier in some of our other successes, we completed the integration of ATSI into PJM. In Ohio, we were very active in the Duke ESP case. All right, I will get this coordinated yet. We played a very involved role with getting Duke into a position where are now from both a retailer and a wholesale perspective. They are totally competitive, allowing our competitive arm to come in and serve those customers. We think that was an excellent result in that case. With respect to AAP, we were one of the very few non-signatory parties. We did not believe that, that settlement and that case was good for customers or good for competition, and that is a settlement that the commission recently rejected. But I'll speak more to the AAP, ESP and the continuing sagas in a moment. In West Virginia, in the E&E seat case, we were successful, that's essentially their fuel case and that there were no disallowances in that case. In Ohio, Mark mentioned the securities legislation that was passed, that legislation was passed, in fairly short order. It will allow us to -- in all parties actually that avail themselves of the legislation to securitize regulatory assets. Now when I talk about securitization legislation, some of you may recall, Senate Bill 221 actually had provisions for securitization. I call that securitization light, if you will. This is the more robust, full securitization that -- which should allow a AAA rating at some point. We would expect, sometime in March or April, to file an application taking financing authority under that legislation. Also in Ohio, we had our all-electric case and whether it bumps along the way, I'm pleased to say that there were no write-offs and we are now collecting the $110 million of past deferrals. And finally, some of you may recall, that in Ohio, late last fall, the governor held an energy summit that Tony and I presented at. I would expect some time in the first half of this year the governor would come out with his report and I would expect that report to focus heavily on the shale gas situation. So you can see from this, we had a full regulatory plate of issues in front of us, and the team delivered results. Okay, now we're coordinated. All right, moving onto what's ahead of us for the next couple of years, what's on the horizon in Ohio. You can expect our utilities, Ohio utilities, to be filing an SSO, that's a standard service offer. It can take the form of either an ESP or an MRO. You can expect to see that filing some time in the fourth quarter, for service of June of 2014. That would mean that we would be expecting a commission PECO decision some time in 2013. The utilities will also be making an energy efficiency filing. That's a 3-year filing commencing in 2013. We are also currently undergoing a renewable energy audit. The commission is going to be hiring an auditor to look at our rec purchases. But given that we've followed both our ESP and the law, I'm expecting a good outcome with respect to that. DPNL, sometime, I guess it is next month, March, should be coming in with their own SSO filing and you'd expect FES to be very active in that case, and to ensure that the Ohio policy of competition is further through that filing. Now dealing with the AAP ESP, again the commission threw out the stipulation and I think as the chairman said they pressed the restart button with respect to that. It's actually restarted a little bit sooner than anticipated. On Monday, AAP made a filing, basically requesting that the commission resync certain portions of that decision, and especially with respect to capacity. What they've effectively asked the commission to do is reinstitute the very high capacity prices that they chose or were seeking to charge CRES suppliers, CRES suppliers, FES being one of them. If you think what that does, if you charge your POLR customers a very low price for capacity and charge CRES suppliers a very high price, it makes shopping very difficult because it's very difficult for Donny to come in and compete. That is what essentially led to in that APE ESP the 21%, 31%, 41% shopping levels. It was a variability to charge those very high capacity rates. So obviously, FES will be responding to AAP's filing on Monday. If you think about the dynamics, the likelihood of a success, essentially they're asking the commission to resurrect a portion of the stipulation, a portion of the stipulation that is anticompetitive, that is not good for customers and the rest of the stipulation is null and void, and has been all over the press. So I would say AAPs certainly have a challenging road in front of them in commencing the commission that they should pull back on that aspect of their decision. But on a going forward basis, if you look at it, I will say that there is almost a consensus among all the constituents, that they would like to see AAP get to a place of competitive markets and are willing to work with them through a transition period. I think it's unfortunate that the Duke stipulation came later in time than the AAP situation -- stipulation. I say that because I think that represents a reasonable path forward. I don't know whether that's something that all the parties would be interested in. But if you look at the success that Duke had and the auctions and lowering their customer boost prices by 17%. I think that's something that could serve as a good roadmap going forward. Moving on to Pennsylvania. The Pennsylvania Utilities filed default service case for power flow in June of 2013 through May of 2015. The commission also has ongoing -- its Phase 2 investigation seeking to increase participation in retail markets. We actually took pieces and parts from that Phase 2 and embedded them within our default service plan. Those pieces being a 2-year timeframe, and opt-in options, somewhere to an aggregation group, if you would, and a customer referral program. So given that we were somewhat ahead of the curve, we are hopeful that our default service plan will be well received. The marginal transmission line lost case if you recall this came out of Pennsylvania. This was a decision by the commission to transform, if you would, transmission line losses, that's what considers them as transmission. The Pennsylvania commission changed them into generation in attempt to get them under the cap. That represents $250 million of pre-tax earnings somewhat less in cash because we started to flow it back. We've obviously appealed that. We appeal that to the Pennsylvania Supreme Court which actually last night just denied cert. If you're familiar with the Ohio process, in Ohio, you go up to the Ohio Supreme Court as a matter of right. But in Pennsylvania, you have to be asked -- you have to ask the court to hear the case. They actually denied cert -- but this was on a 2-track path. We also filed in federal district court for that case to be looked at. I think we are at very solid ground. The basis of the case, one of the bases of the case is a file background, that something upon which there is substantial precedent, including at the Supreme Court level. So I'm very comfortable with our position, and that federal court case will go forward so that's not the end of the story with respect to that particular issue. And finally in Pennsylvania, with respect to smart meters, we'll be making a filing by June of 2012. You will recall that the Pennsylvania legislation requires for our FirstEnergy in any event 2 million meters to be installed by 2025. And as Chuck alluded to, that's something that we would expect full cost recovery for. I should -- I guess mention one more thing, recently in Pennsylvania, the commission published a code of conduct and there's one troubling aspect with respect to that. The rules would contemplate that certain functions can't be shared between the utilities on one hand and the competitive supplier in the other. Those principally being IT, legal and governmental affairs. Now if you think about what that means from a customer standpoint, a utility customer standpoint right now, because they're sharing those costs, they're paying less. So if the commission were to do something where they're essentially going to require duplication, utility customers would end up paying more. We haven't really heard a good reason of why one would want to force this kind of duplication. So I'm thinking this is something that is right for review, and that is going to mean additional costs for utility customers. Moving on onto New Jersey. Chuck talked a little bit about the Moorestown investigation, the special master had 25 recommendations. JCP&L has accepted all of them. So I think that is something that as we go forward working with the commission to make sure that we're implementing those and I think that's something that is manageable going forward. We also alluded to Hurricane Irene and that freak October snowstorm. The BPU is going to be hiring an auditor to look at all utilities, not just JCP&L, to look at their response time and to see what lessons learned there can be so we go forward and we have another yet one in a 100-year event that all the utilities will be able to share the best practices among themselves. The rate counsel have filed a rate challenge, essentially claiming that JCP&L was over-earning to the tune of roughly $90 million. We filed a response to that. The commission set up a process where the board president will be presiding over, what do I call it, kind of an interim proceeding if you would. He will be looking to see whether a rate case is actually necessary. So we're not in a rate case. This is the process whereby we are going to determine whether a rate case is necessary. We're confident that we can demonstrate that it is not and there is no need to drain the resources of both the BPU staff and the company's. With respect to the light camp generation situation, just to kind of refresh everybody as to where we are, 3 bids were awarded roughly 1,950 megawatts. That BPU orders establishing that has been challenged by all the EDUs. Certain of the winning bidders are also troubled. They filed notices of dispute. So that process, I have to say, is anything but unclear, as is the light cap 2 situation. Also adding additional complexity, if you would, to the situation, LS Power, the company that was behind the original LCAP legislation, has recently announced that they plan to build generation in New Jersey over 700 megawatts natural powered -- natural gas plants without a subsidy. So the notion of going forward with the LCAP generation thinking it's needed because nobody else is going to come in. It's certainly called into question by LS Power's decision. In West Virginia, it's been mentioned, we announced the closure of roughly 660 megawatts of regulated generation actually as part of our ENEC case. We had committed to come in for a resource planning filing sometime before September 1. We will actually be coming in, in fairly short order and possibly in the next couple of weeks to explain the plant closure. It will be an informational filing, but to go through with that commission our rationale behind the closure of those particular units. You may recall, as part of the merger conditions in West Virginia, we agreed to establish an energy efficiency component. We agreed to 0.5% reduction over a 5-year period and we will be permitted cost recovery of those cost of those programs. And then finally, with respect to the states in Maryland, their version of light cap is a new generation RFP bids one out, they've come back in. And actually this morning, the commission announced they've taken it down to a shortlist for 1,500 megawatts. My understanding that a lot detail more than that, but apparently that process has moved forward such as that there is now a shortlist of potential winning bidders in that process. In Maryland, we had hearings on the reliability standards. Those hearings were completed in December of '11. If they come out in the form that we believe they will, that was kind of handled through a working group looking at these issues, we think they will be manageable and workable for our utility in Maryland. And finally, dealing with FERC, there are always transmission cost to allocation issues out there. Recently, the FERCs decided the MVP case from an ATSI perspective that was the case whereby right before we left MISO, MISO approved the wind some project in Michigan. Because we had previously notified MISO that we wanted to exit MISO, we didn't believe it appropriate that those caution apply to us since they were clearly not planning for us. Unfortunately, FERCs disagreed with that and indicated that we would have an obligation, but it's something that was curious to me they set for a hearing whether the MISO tariff actually provided a provision to charge ATSI for that. So in my view, there's a little bit of tension there but I don't believe that's even the end of the story because if you think about it, while we don't believe we're responsible. We were proactive in our ESP in Ohio, that ESP actually allows for the recovery of these costs, so ultimately should it be determined that ATSI is going to be responsible for those costs, we would change -- seek to change the ATSI tariff so as to flow those costs on to customers. FERC has also an issue with respect to generation asset deployment. MISO is floating a concept called capacity portability. I think that's a euphemism for double counting of capacity. They seek to take the MISO capacity, move it to PJM under very favorable terms. I also think it's on the ironic side, since with MACT, MISO has indicated that they are going to be capacity short and PJM has indicated that they will be just fine. So obviously more to come on that particular issue. And the final thing I'd like to mention, with respect to FERC, is the Seneca relicensing process. Seneca is a roughly a 450-megawatt pump storage facility. Its license expires in 2015. We are at FERC seeking relicensing of that plant. The Seneca nation has come into and intervened in that case, claiming that they should have that license and it should be transferred to them. While we take their challenge seriously, they have a very high hurdle in order to overcome to have that license to transfer to them, and we are very confident in the process with respect to that. So in conclusion, I would say again, in 2012 and going forward, we have a full plate in front of us. But I'm confident that the regulatory team can deliver the favorable results for you that we have in the past. And with that, I'd be happy to take any questions.

Pennsylvania, just passed a pretty constructive regulatory, legislative package that gives the PUC sort of a mandate, broad mandate to be more proactive and now they allow returns to compound on capital investments. Is that a regulatory regime and sort of more potentially profitable regulatory regime given the timeliness that you could get. Is that baked into your capital allocation strategy in this plan or is it fair to say that we might see you guys look more regulated infrastructure investment in Pennsylvania given how that regime has improved relative to other states that you're in? Leila L. Vespoli: Okay. I want to handle that one way and then maybe defer to Mark or Jim to handle that in another way. As we go through the different jurisdictions and we look at the regulatory structures that are present, we try and anticipate what is on the horizon and try and build that into whatever plan it might be, so be it a typical rate case or an ESP. For example, Chuck, when he was up here early, mentioned the storm riders that we have implemented. So we seek to do that kind of thing, specifically with respect to the particular question in Pennsylvania and whether we are trying to avail ourselves an additional return with respect to, I'm not sure exactly what you're getting at.

Other companies who are operating in the state have said previously that they were not investing the maximum extent they could relative to what they felt was necessary because of regulatory lag, and thus they were promoting the passage of this legislation. Now that, that regulatory lag issue has ostensibly been resolved because of this legislation, is there an opportunity for you to sort of catch-up on spending that you otherwise would've done over a longer period of time, in a better way? Leila L. Vespoli: I see. Okay, I apologize. I missed your question originally. Because you were talking about the new legislation kind of the disc [ph] legislation, if you would, that would allow for a more immediate recovery of investment. There is a provision within that, that in order to avail yourself of it, you have to go through a rate proceeding. So that's something that as we look going forward, when it is time for us to go through a rate proceeding, after that point in time, we might be availing ourselves of that. I'm sorry, I missed your original question.

Yes. I'm sorry, I just wanted to follow-up, just an Ohio follow-up. I'm surprised there wasn't greater pushback by you in the Duke plan, regarding the $5 or $5.50 a megawatt hour stability charge and just what that means for the dynamic of competitive markets relative to what your positions were in the various AAP dockets? Leila L. Vespoli: In the Duke case, if you think about it, Duke agreed to retail and wholesale competition immediately. Yes, the charge you were referring to, the stability charge, if you would, that's what people speak to when they're talking about allowing utility to transition. It's essentially an earnings profit, if you would, in the meantime. We don't view that as anticompetitive. There are no shopping caps. Donnie can go down and effectively -- in effect, was the winning bidder. In the auction, the wholesale auction, and he's down there seeking customers on a retail level. So yes, one might want to swallow hard and they're receiving some transition dollars that one could argue whether they are due. I don't think that it's all anticompetitive. If you look at the AP stipulation, there were shopping caps. There was not wholesale competition. There was a promise of wholesale competition sometime in the future. If they possibly are able to undo their full arrangement. I view the 2 cases as dramatically different. Mark T. Clark: Very good, Leila, thank you. And everyone here, thanks for joining us again. In case you didn't realize it, I have an immense pride in this team that I have here with us, not only the presenters that you were able to see today, but much of my management team is here today from financial, from sales, from generation, I hope you've had a chance to meet them. They have consistently delivered on their commitments through good times and challenging ones. And as a result, they have helped transformed this company. We are well positioned on every front to deliver on the strategy we have outlined today and to create even greater value for our investors, and I'm confident that we will do exactly that, through our focus on our core business, operational excellence, retail sales growth and financial discipline. We have the right strategy and the right assets to take advantage of the opportunities that lie ahead. Thank you. Now let's take some questions. What's on your minds?

This might be a bit more oriented towards Mark. The AE transmission line of credit, what boxes does that essentially represent. Is it trail, the path that it's been suspended, what assets would that entail? Mark T. Clark: The trail, it's primarily trail at this point. There might be some ancillary costs in there with respect to PATH, and if there's anything else probably with respect to the transmission building itself that we put there, so those would be the 3 kind of primary areas where the bulk of the dollars being represented with the trail line itself and the substations added along that system.

Okay, so there's no intent to put in the bond indenture for potential intermediate transmission hold gold type debt? Mark T. Clark: They're shaking their heads no, so no.

With regards to ATSI and potentially seeing higher capacity prices, I'm just very curious to hear broader thoughts about receiving RMR and at what point you might receive RMR for some of your units, and also with regards to transmission planning, and when we might see those processes outlined in detail? I know that you guys received a letter from PJM. Mark T. Clark: Yes, I think Jim kind of outlined that already but we'll work closely with PJM. It's got a letter indicating that they believe that there are significant reliability issues that we're going to have to address. We'll sit down and work with them to try to figure out exactly what are the best ways to go about dealing with the issues PJM has. Remember, we have a responsibility from a reliability standpoint in this region and we will going to -- and we will satisfy that. So we'll work closely with them, work through this. It's going to take time, we all know that. Nothing in our business can be done tomorrow. It takes time, whenever there's capital and whenever there's investment that's likely to be required, like Chuck said in terms of perhaps, some additional transmission into that area. All of that will be factored in and the key to this is enough time for the company to react and to deal with the type of construction issues and citing issues that we may face in order to assure reliable service to our customers.

Tony or Mark, we just looked at the 2012 guidance numbers you've given. The utility should be reasonably well pinned down. You've got 89% of your generation or committed sales already in place. What do you see as kind of driving the variability or potential variability and results this year relative to the $0.30 guidance range right now? Anthony J. Alexander: The kind of things we always face in this industry, things I don't know. Weather would be one that's obvious. In our space, whether it's good, whether it's bad, it's never normal. So we'll see how that shakes out over the year. Obviously, when I play golf in Akron, Ohio, in February, it's not a good thing. That doesn't happen very often. And so this has been a pretty mild winter thus far for us. Like Chuck said, hopefully it gets made up in the summer. You have weather risks always factoring in, I tell you, assuming in the business like ours, like any business. You have some operational risk with respect to performance of your plants, when do they run, when do -- when are forced off. Those are kind of the larger space things that we look at in terms of, okay, these are things that out there, we know they're there. Our job is to try to manage against it or manage too whatever cards we're faced with. At this point, I'd like to see much more than that. There could be other things out there, there always are, and there's always seems to be something that pops up along the way, but I'd keep my eye on weather and I keep my eye on the operation of the plants. Sales team's doing great right now, they're locking in the sales. The plants are operating well. So we'll see how the rest of it goes.

If you did decide to make Eastlake environmentally compliant, what would the cost be to do that? And then separately, the Ohio securitization of deferred charges, what's the ballpark magnitude to that, that the legislation now allows you to file for? Anthony J. Alexander: With respect to Eastlake, the decision's been made. It's too much. That's probably the easiest way to put it. With respect to the other one, I don't think we have a handle yet on the magnitude of what we have on our books that will in fact qualify for those securitization. We intend to file I think Leila said, some time in the next several months, I guess, the application, then we'll complete everything that we have to do to make sure that we meet the commission's rules and the intent of the new legislation.

This is probably for Donny. Just a quick question on the hedging. I think in last year's presentation, you had a little more detail around what sort of volumes were contracted but not priced. That slide is absent this year. When we look at the targets you give, how much of those percentages are actually still price-sensitive? Donald R. Schneider: Yes, for 2013, I mentioned we're about 80% hedged out on coal. About 7% of that is price reopeners. The other 13% is open, open.

On the actual power side? Donald R. Schneider: On the power side, so what's the question on the power side?

Just on the sales channels, I think in last year's presentation, there was a slug of terawatt hours that were contracted but not were indexed priced or still floating with pricing. So when we look at that, close business, I think that may include some pricing volatility and just a quick color on how much that is. Donald R. Schneider: Yes, very little. The pricing volatility that you saw last year is around our gov bag [ph] contracts that tie to PTC, in the main -- those PTCs have been established, therefore, the gov bag [ph] rates have been established.

Maybe just to play devil's advocate, the comments Leila made on the AAP case, with respect to their filings on capacity not being customer friendly, or competitor friendly, I guess they would probably argue that they had committed their capacity under this FRR, on PJM and thus, they're owed this money. What's the legal, beside the customer and competitive argument, what's the legal argument against that position? Anthony J. Alexander: I don't want to go there. Steve, come on. I'm not a lawyer anymore and I don't think Leila needs to answer legally what our position is going to be. I think she pretty well highlighted for you that we have a problem with the idea of charging capacity prices that are substantially in excess of market because they inhibit the ability of customers to choose and take effective use of the competitive markets to lower their prices and become more competitive and to grow their own businesses. Now that's the fundamental position of the company. And while, like Leila said, with respect to the Duke settlement, we're very comfortable with the fact that customers have the opportunity to shop. That it was the other parts of the transaction were not anticompetitive from the standpoint of customers. That's all we're seeking. To the extent that people try to do things that in fact inhibit the ability of competitive markets to run effectively, then we would oppose that. And we would think capacity charges of $200 plus in a market that's $20, is a tad bit over-the-top.

And one other unrelated question, just on the upcoming RPM auction, of the capacity that you are closing, how much of those cleared in last year's auction? In other words, how much less capacity might you have available that cleared last time for Tony into this auction? Anthony J. Alexander: I don't know. That's getting pretty detailed into the works. I'll let somebody get that to you later, Steve. All right, it looks like that's all the questions. I want to finish on a very high note for you and tell you that this company is focused on operational excellence. It's focused on our investors. It's focused on maintaining our dividend. Now there have been questions today about when we're going to grow it. Well, I think that time is, as the economy improves, as this thing settles down. Otherwise, this dividend is stable. We're working very hard to assure that we can maintain it. We're working very hard to make sure that this -- that we can take advantage of for our investors, for our company and for customers, improvements in the economy, and improvements overall in the competitive market for electricity. Thank you for your support. FirstEnergy is a great company. Have a great year.