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

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.

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…

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,…

Yes, Paul? [ph]

Can you talk about the implications of the sale leaseback, just from a financial perspective?

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?

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?

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?

Yes.

Okay, what bucket is that in or is that some kind of...

It's just inherent in the numbers.

Okay. So that's free cash flow of basically 0 where negative 100 includes that?

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?

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?

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?

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?

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?

That would be an understatement, yes.

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?

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.

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...

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?

Nope, you did well. Thank you.

Okay. I'll just turn it over to you.

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…

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?

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?

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?

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?

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.

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]

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?

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…

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?

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?

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?

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?

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?

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?

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.

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?

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?

Donny, do you have a... Yes, I think that's probably -- Donny's here. Donny, why don't you take care of that?

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?

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?

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.

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?

Well, I'm not the auction expert. I'll refer to Donny on that one.

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.

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…

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.

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…

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?

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?

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?

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.

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?

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?

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.

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?

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?

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?

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?

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.

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?

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?

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.