第一能源 (FE) 2010 Q3 法說會逐字稿

Greetings, and welcome to the FirstEnergy Corp. third-quarter 2010 earnings conference call. At this time, all participants are in listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions). As a reminder this conference is being recorded. It is now my pleasure to introduce your host, Ms. Irene Fizzell, director of investor relations for FirstEnergy Corp. Thank you. Ms. Fizzell, you may begin.

Thank you, Jackie, and good afternoon. During this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategy, prospects, and other aspects of the business of FirstEnergy Corp. are based on current expectations that are subject to risks and uncertainties.

A number of factors could cause actual results or outcomes to differ materially from those indicated by such forward-looking statements. Please read the Safe Harbor statement contained in the consolidated report to the financial community, which was released earlier today and is also available on our website under the earnings release link. Reconciliations to GAAP for the non-GAAP earnings measures we will be referring to today are also contained in that report, as well as on the investor information section on our website at www.firstenergycorp.com/IR.

Participating in today's call are Tony Alexander, President and Chief Executive Officer; Mark Clark, Executive Vice President and Chief Financial Officer; Harvey Wagner, Vice President and Controller; Jim Pearson, Vice President and Treasurer; Bill Byrd, Vice President of Corporate Risk; and Ron Seeholzer, Vice President of Investor Relations.

I'll now turn the call over to Mark.

Thanks, Irene, and good afternoon, everyone. This morning we reported strong third-quarter results that, on a non-GAAP basis, represented an increase over the third quarter of 2009. Like many of our peers in the region, unusually warm weather and the corresponding higher distribution deliveries had a positive impact on third-quarter results.

However, as we reviewed the numbers, the biggest driver of our strong quarter was the success of our retail strategy, as we continued to move competitive customers away from polar and into direct sales and government aggregation channels. We are not just selling more megawatt hours, but reducing shopping risk, as well as enhancing our flexibility to structure favorable contracts and our opportunity to maximize our margins.

As I walk through our results, it may be helpful for you to refer to the consolidated report to the financial community we issued this morning. Later, Tony will update you on the merger, the status of the recent polar auction in Ohio, and outline information on some of the factors that we expect to impact earnings in 2011.

Excluding special items, normalized non-GAAP earnings for the quarter were $1.28 per share compared to $1.11 per share in the third quarter of 2009. On a GAAP basis, this quarter's earnings were $0.59 per share compared to $0.70 per share -- $0.77 per share last year. As detailed on Page 16 of the consolidated report, four special items decreased this quarter's GAAP earnings by a total of $0.69 per share. By comparison, special items reduced GAAP earnings by $0.34 per share in the third quarter of 2009.

The first of the 2010 special items was $0.60 per share impairment as a result of the operational changes we recently announced regarding several of our smaller coal-fired plants. These changes will provide us with operational flexibility and cost savings that we expect to bring long-term benefits. The second special item was $0.04 per share charge related to merger transaction costs. As in prior quarter, these costs will continue to be expensed as incurred.

Third was a $0.03 per share charge related to power contract mark-to-market adjustments of certain wholesale power contracts. And finally, $0.02 per share related to charges resulting from our new stipulated Electric Security Plan in Ohio.

I'd like to quickly outline the key drivers of our third-quarter non-GAAP results, starting with the positives. First, a 12% increase in overall distribution deliveries benefited earnings by $0.17 per share. Residential usage was at its highest level in nearly a decade, and a 19% above the third quarter of 2009, a quarter with record low usage dating back to 2002. This significant increase was largely related to warmer-than-normal summer temperatures across our service area and the resulting higher air conditioning usage.

Industrial deliveries were up 11%, primarily related to higher usage by steel and automotive manufacturers, many of which had idle facilities for some portion of the third quarter last year. With this result, our industrial customer sector has recorded year-to-date double-digit sales increases for the entire nine-month period of 2010. Commercial deliveries were 5% higher than the previous period.

Year to date we remain slightly ahead of our 2010 forecast of 106 million-megawatt hours. While these results are an encouraging sign that the economy continues to recover, we expect overall distribution deliveries to remain below 2007 and 2008 levels, at least through next year.

The second positive earnings driver this quarter was commodity margin, which increased earnings by $0.19 per share. A detailed summary of this item appears on the first three pages of the consolidated report, including additional information on megawatt hour volumes and prices. As I mentioned, our competitive sales strategy focuses on direct sales and government aggregation, and our efforts in these areas continue to drive our success.

For the quarter, sales by our FirstEnergy Solutions subsidiary were 6.3 million-megawatt hours above last year's period, a 45% increase. About one-third of our growth in the quarter came from sales outside our utility service territories, and nearly half of our direct sales came from outside our Ohio franchise area. We are encouraged by these signs, their continued positive direction, and the overall strong performance of our retail group.

FES also has been successfully adding retail generation customers inside FirstEnergy's utility service territories, which resulted in a corresponding decrease in wholesale sales. Again, we want to put less emphasis on polar sales and focus more on direct and government aggregation channels, where there is lower risk, flexibility to stagger contracts, and greater potential to maximize our margins. We're continuing to expand into new markets outside our traditional utility service territories and have acquired customers in southern Ohio, as well as markets opening up in Pennsylvania.

For the quarter, wholesale business was down one million-megawatt hours, or 26%. Generation output for the quarter was 19% above the prior-year quarter, or 3.4 million-megawatt hours. The majority of this increase came from our fossil units. With increased generation output and higher sales levels we also incurred higher fuel and purchase power expense.

The third key driver to earnings this quarter was $0.12 per share shift in benefit related to lower operation and maintenance costs. This reflects changes in employee benefit costs, including additional cost recognized for incentive compensation and salary restoration in the third quarter of 2009, collectively resulting in a $0.10 per share increase to earnings.

It is important to note that while there was an earnings benefit related to timing differences for incentive compensation accruals this quarter compared with 2009, on a year-to-date basis these costs are not significantly different. Similar to 2009, these accruals will be reversed if incentive targets are not met.

Reduced operating expenses, primarily at our utilities, contributed an additional $0.02 per share to earnings in the third quarter of 2010. Finally, net financing cost reductions increased earnings by $0.03 per share.

Moving to the items that had a negative impact on the third-quarter earnings comparison, lower investment income from nuclear decommissioning trusts reduced earnings by $0.25 per share compared with the prior-year quarter. When we realized the significant gain from the sale of securities held in trust these sales facilitated our strategy to reposition our assets to limit volatility risk. A higher effective income tax rate decreased earnings by $0.06 per share, and higher kilowatt hour excise and gross receipts taxes this year reduced earnings by $0.03 per share.

As you can see, while weather certainly benefited our earnings for the third quarter of 2010 this positive was more than offset by reductions related to nonoperational items, such as nuclear decommissioning trust and taxes. As I mentioned at the start, our strong third-quarter results reflect the gains we've seen from our competitive retail sales efforts, with their continued expansion into non-franchise areas, as well as the shift of their customers from polar to direct sales and aggregation.

Finally, our available liquidity of $2.8 billion is approximately $500 million higher than this time last year. Taken together, our results continue to track our expectations. As a result, we are affirming our 2010 non-GAAP earnings guidance of $3.60 to $3.70 per share.

Now I'll turn it over to Tony.

Thanks, Mark, and good afternoon, everyone. Thank you for joining us today. I'd like to provide an update on the progress of our proposed merger with Allegheny Energy and some of the auction activity we've seen over the past few weeks. Because we expect our merger to close in the first half of 2011, we will not be providing earnings guidance in December, as has been our past practice.

To help in your analysis in the meantime, we have included a list of key earning drivers for 2011, beginning on page 17 of today's consolidated report, and I will also discuss those, as well. We will have additional information at next week's EEI financial conference. Once the merger closes, we will schedule a meeting to discuss 2011, as well as more details on projected merger synergies and initial expectations for 2012.

Let's start with a merger update. We continue to be encouraged by the progress we are making towards completion of the merger. Since our last call, we reached a settlement agreement with 18 parties to our Pennsylvania proceeding. This agreement provides additional benefits related to jobs, competition, service reliability, and renewable energy. We are pleased to have addressed all of the issues raised by these intervenors, and as a result, have their support for our transaction.

The settlement is subject to approval by the Pennsylvania Commission, which continues its review of the case. Maryland begins its merger hearings next week and West Virginia, the following week. While these are the only states where regulatory approval is required, Ohio has agreed, as a part of our ESP order, that it will not assert jurisdiction over the merger process, and we continue to provide information to the New Jersey Board of Public Utilities to keep them updated.

On the federal side, we provided the Federal Energy Regulatory Commission with additional information for their review and continue to provide information to the Department of Justice. We expect these reviews to be complete in sufficient time to meet the anticipated merger closing schedule. As you know, the merger has received overwhelming support of both companies' shareholders, and we believe our progress in securing the necessary approvals underscores the value this merger can deliver to our shareholders and other stakeholders.

As we work through the merger approval process, teams of employees from both companies continue working to outline how our two organizations will come together. Through this integration progress -- process we will identify best practices for the new organization and develop the implementation plans to capture the benefits of the merger. Some examples include consolidation of contractor services and material purchases, operating a single IT infrastructure and data center, and other economies of scale, particularly in our generating fleet, that could produce new revenue opportunities, as well. The merger process remains on track, and we continue to expect to close in the first half of 2011.

As I mentioned, we received approval in August from the Public Utilities Commission of Ohio for our stipulated electric security plan. The plan was supported by more than 20 different parties representing customers and communities in our service territory. We're pleased to have the ESP finalized and are working to implement its terms, including the competitive bidding process.

Last week, our Ohio utilities conducted the first in a series of auctions to secure generation for the 2011 through 2014 timeframe. As you may know, the PUCO released the results on Friday. FirstEnergy Solutions was one of four successful bidders for a total of 20 out of 50 tranches across the three different auction products. FES won 10 one-year tranches, seven two-year tranches, and three three-year tranches. Overall, we're pleased with these results.

Another auction will be held in January, and the results of that auction will be blended with those from last week's auction to determine retail generation service prices for June 1, 2011 through May 31, 2012.

From a competitive generation standpoint, we are on a very different situation today than we were in the spring of 2009, when our generation position was fully open beginning June 1st. We won 51% of the tranches in that auction and today serve directly or indirectly an additional 26% of the auction load. Since then, we have continued executing our competitive strategy and lining up customers for our generation -- generating capacity.

Currently, FirstEnergy Solutions has 1.2 million retail customers. Going into last week's procurement, we had more than 76% of our 2011 generation output committed to direct sales, government aggregation and polar auctions. Also, as Mark outlined, we continue to make progress securing customers in non-franchise areas, and importantly, moving customers from polar service to direct sales. As a result, FirstEnergy Solutions is considerably less sensitive to the Ohio polar procurement process and continues to participate in other auctions taking place in the region, further increasing opportunities to sell its power.

Most importantly, with the Ohio transition completed, we will build a strong foundation for our competitive retail business, and this includes our focus on direct sales and government aggregation. Last week we also completed the default service process to establish prices for MetEd and Penelec customers for the first five months of next year. Prices from the final bidding process will be blended with the results of previous auctions, and establish a default service price beginning January 1st of 2011.

As I mentioned earlier, we will not be providing 2011 earnings guidance until after the merger with Allegheny Energy closes. However, I'd like to provide some thoughts on several key earnings drivers for next year. It may be helpful to refer to pages 17 through 19 in the consolidated report as I go through these.

As I look at 2011 it's important to recognize that the Company is still in the transition to competitive markets and building its retail platform. And while there are a lot of moving parts, there is a major change in our business next year as a result of the polar obligation in Pennsylvania being replaced with the competitive market.

So in order to get a baseline, we started by isolating the Pennsylvania polar sales of about 29 million megawatt hours in 2010 and the PJM purchases made to support those sales, about 20 million megawatt hours, which will no longer be a part of our cost structure starting in 2011. Then we looked at the drivers of 2011 performance without those sales and costs.

As you can see, we expect our retail sales to improve as a result of expected continued growth in this part of our business and somewhat-higher pricing in 2011. This will be offset by expected higher RTO costs and higher retail expenses, which are primarily related to increases at our sales force and back office expenditures.

Additionally, we expect higher purchase power costs in 2011, primarily for balancing and to cover a portion of the reduced generation from our own fleet. Fuel costs are expected to be slightly positive, again, due to the reduced generation, even though we will experience some price adjustments. We also expect that signal peak may provide some uplift in 2011 to offset what otherwise would be additional costs.

Our plans for next year, as I've indicated, assume that generation output will be about 70.2 million megawatt hours, which is down about 6% from our 2010 forecast of 74.6 million megawatt hours. This reduction is partly driven by the outage schedule at Davis-Besse, as well as changes to the in-service date at Fremont and the operations of our older coal-fired fleet, which we anticipate to be in a seasonal, or idled status during the year.

This drop in production essentially impacts each of the drivers I've mentioned. These are either positively through lower fuel costs, or negatively through lower sales. However, since we have the ability to increase production if economic conditions or additional sales warrant, we are positioned to take advantage of those opportunities should they arise.

On the distribution side of our business, we are forecasting 2011 distribution deliveries at about 107 million-megawatt hours. This takes into account normal weather, but we've also provided a range that reflects different levels of economic recovery.

Capital expenditures are expected to be between $1.4 billion and $1.5 billion, which is significantly below the current year, as we wind down our large construction projects at Sammis and Fremont. Because we already have incurred most of the capital costs for the Fremont project, the extended completion is not expected to add significantly to the capital budget.

The capital plan reflects about $100 million for mandatory transmission and energy efficiency projects, and costs related to the accelerated replacement of the Davis-Besse reactor head, which will add approximately $90 million to the budget. Based on our current estimates for 2011, we expect to deliver free cash flow of more than $500 million.

As you know, our Board of Directors reviews the dividend on a quarterly basis. It is our expectation and goal to maintain the dividend at its current level. Following closing of the merger, we plan to develop a more formal dividend policy that will provide stability, sustainability, and growth for shareholders in all market conditions.

I look forward to seeing many of you next week at the EEI financial conference. Now we'll be happy to take your questions.

Thank you. (Operator Instructions). Thank you. Our first question's coming from Daniel Eggers of Credit Suisse.

Good afternoon.

Hi, Dan.

Just -- Tony, on a couple of the driver comments you had today, can you shed a little more light on where the cash flow from operations is improving from the run-rate level in 2010 to 2011, given the fact it looks like you've got some earnings headwinds where you expect to recoup some cash?

Well, a large driver of it, obviously, is the reduction of the capital budget. That will be the significant component of it. And I think maybe Jim can give you a little more clarity with respect to how the rest of it falls together.

Dan, this is Jim Pearson. Tony hit on it primarily, but if you think about it this year, we're going to be in the $500 million range, that's where we'd expect to be. If you look at some of those drivers from the earnings standpoint, those are noncash, the depreciation and the AFUDC, so I would say from a cash standpoint our earnings will go down $60 million to $70 million. We don't expect to have the interest rate swaps and we had a little bit of gains in this year. So when you back that out and then you add back in the $300 million to $350 million reduced capital expenditures, you -- it's in the same line as where we are this year.

Okay. And then on the CapEx's lower level, is this a more sustainable level of CapEx as you look out and what would cause those numbers to move around in 2012 and beyond?

Dan, this is Mark. One of the reasons we put it in what I'll call the three buckets there is that, first is we think going forward on a stand-alone basis we'd be somewhere between $1 billion and $1.2 billion and then that's what it shows for 2011. And then you've got that second piece, which are things that either are [RTEP] or the energy efficiency-type programs, which are mandated by various authorities, and then, of course, you've got Attachment O and recovery mechanisms for the energy efficiency. So that's a piece we have less control over.

And then, of course, the third piece is where we may have a particular large project come into play and as you know, we elected to move the Davis-Besse head replacement forward, we think that was a prudent thing to do. So on a core basis, it's somewhere between $1 billion and $1.2 billion, and then depending on what the states want to do, depends on what we might do with a particular project, you could be a little plus or minus around that. But certainly going forward I think $1.4 billion, $1.5 billion would certainly be at the high end with the base period about $1 billion to $1.2 billion.

Okay, and we should be assuming that the guidance driver -- I guess on the 2010 guidance, the fact that you held the range today is that because there's some pressure in the fourth quarter year over year that we should be thinking about, or is it you just didn't want to update the year at this point in time in the year?

I don't know if we're looking at anything of a specific nature regarding the fourth quarter. Certainly we had a very strong third quarter with the weather, but this is -- as I stated earlier, that was completely offset by some of the nonoperational comparisons, the big driver being the retail sales.

But just like in the third quarter, we could have items -- just by way of example we could have taxes reverse back around like they did in the third quarter. Another example would be the acceleration at Davis-Besse O&M, which was not included in prior estimates, and we're working through that with our engineers. So we think it's appropriate to stay within that earnings guidance range and we still have 2.5 months left in the year. And so that's -- it's not that we didn't look at it, we're just comfortable with it being in that range.

Okay, and then I guess one last question. Tony, on the dividend comment, when you plan to evaluate after the merger closes, does that mean the absolute level is under consideration, or just a strategic payout ratio and thought process as to how you address the dividend?

Yes, Dan, I think I've mentioned this several times. The absolute level, obviously, is determined by the Board, but I'm comfortable with the level we're at. I'm comfortable that it is sustainable following the merger with Allegheny. And it's more related to -- as a combined company and as we face volatility and other things in the market we begin to design a dividend policy going forward that better reflects that type of operation.

Dan, this is Mark. I would only add that even at the current dividend payout ratio next year, even after paying it we're projecting to be over $500 million of free cash. So the absolute level, as Tony alluded to, is not something we discuss.

Okay, thank you.

Thank you.

Thank you. Our next question's coming from Jonathan Arnold of Deutsche Bank.

Hi, good afternoon.

Good morning or afternoon, I guess.

Hi, Jon.

Hi, I had a couple of questions, firstly on the disclosure you gave on what you won in the recent Ohio auction. You seem to be more successful in the shorter-dated product than the longer-dated tranches. Was that a reflection of it being more competitive in the longer pieces, or a conscious decision to leave more of your longer position open? And I guess as a follow to that, in the past you filled in through serving some other participants in the auction, what should we be thinking on those lines on the back of this one?

Well, I'll let Bill Byrd answer the question for you, but from my own perspective I'm very comfortable allowing for the upside to materialize which I truly believe is going to happen as the economy recovers and as additional actions are going to have to be taken with respect to the older coal-fired fleet. So in this timeframe, I'm not uncomfortable with being more aggressive towards the front end as opposed to the tail end.

As to your second question, at this point we do not contemplate taking any action to acquire tranches from any third -- any of the other third-party winners. Bill, do you have any color you want to add? I wasn't at the auction itself, so I don't really have any sense for how the moving parts went and played out, but the overall result, quite frankly, is pretty consistent with where I believe the Company's best interests are served.

And what Tony described in terms of solutions, winning the different products is the strategic orientation going into the auction and then the auction process itself. You bid on all three products at the same time. It's a simultaneous auction, so it was just a call of value versus risk, and basically where the different products were priced versus the risk and we ended up with more of the shorter-term products.

Okay, thank you. And on another topic, you obviously identified capitalized interests as an earnings driver for 2011. How much interest are you expecting to still be capitalizing in 2011 with that $85-odd million delta?

It's probably in -- this is Harvey Wagner. It's probably in the $80 million to $85 million range.

Of continuing capitalized interest that at some point will --

Yes.

Yes, okay. And just one -- another small thing I had, on the distribution driver for next year, you have the sales expected to be down. You identified deliveries as sort of could be a bit negative, could be a bit positive. How do we reconcile the actual financial number with the volume decline?

Well, let me just -- this is Mark, let me step back into 2010. In the third quarter we're almost coming off a record residential sales with the preceding year, 2009, being almost at a decade low. We forecast based on a normalized basis, so we would smooth out those kinds of offsets. So I think that the answer is simply that we normalize our forecast and you will see that that benefit that we get from the residential side gets stripped out and that has an effect on the overall forecast. We don't take the residential increase of 19% and then add another 2% or 3% or some percent to it. So we're very comfortable with the forecast. We think it's more than achievable, and we think it aligns with our overall strategy.

So what you're saying, though, I don't get why that forecast wouldn't be skewed negative year over year?

What was that, Jon -- Jonathan?

I don't understand why given that the sales are down -- because of the very strong 2010, why there wouldn't be just a negative skew to that forecast, why it's a flat number?

Well, I think one very clear reason is that we're not a regulated utility, and our FES sales group can increase or decrease that number. I don't know, Bill, do you have the --

Well, I think on the -- Mark should -- let me go back to the distribution side of it. I think what we're looking at, Jonathan, is that we predict normal conditions, we're predicting some improvement in the economy. That improvement could accelerate and have positive benefits to us, or the economy can turn more negative us on, like it has over the last several years.

And what we wanted to try to capture as we look at drivers for next year is that I still think we're in a fairly uncertain economic environment as to whether or not industrial sales will continue to grow at the pace they are, or whether or not the economy will suffer some retraction. That's all -- that's what we've tried to reflect there, that while we're comfortable at a normal basis, there's still a lot of uncertainty with respect to what the impact the economy can have on our sales.

Thanks for the clarification.

Thank you. Our next question comes from Paul Patterson of Glenrock Associates.

Good afternoon.

Hi, Paul.

With respect to the merger and the change in power prices, do you still -- what's the accretion/dilution outlook that you have for the next couple of years?

Now, Paul, come on, you're going to have to wait on that until next year.

Okay. And then just to circle back here with Dan's question on the dividend, if I understood you correctly, basically there's really no question about the dividend getting cut, it's the question of the growth format going forward. Is that how we should think about it?

That's how I'm looking at it. I think I am very comfortable with where we're at, the amount of cash the Company generates and its ability to cover that dividend, not only in its current form, but after the merger with Allegheny. So I'm looking more towards a policy as to how we can grow that dividend going forward.

Okay. And then just any change in the tax rate that we're thinking about in terms of 2011?

Paul, this is Harvey Wagner. There's nothing specific at this point. We'll be able to give you more color on that when we give you 2011 guidance.

Okay, thanks so much.

Thank you. Our next question comes from Ashar Khan of Vision Management.

Good afternoon. I was just trying to get a better sense. You provided the prices -- the hedged prices. If I'm right, 2011, looking at the page $60.54 and then I guess estimated between $52 and $65. Can I ask you why the range is so wide, the $52 to $65? Is it because of different prices are for the direct government aggregated and the polar, is that why the ranges?

This is Bill Byrd. It's more of a reflection of the different geographies involved. If we're selling power in [Amorin], for example, that's a much, much, much different price than a retail sale of power in New Jersey and that's basically the reason for that spread. It's the different geography.

Okay, but when we put into -- when you're giving the outlook, should we take an average of the $52 and $65 in our modeling to apply to the remaining unhedged megawatt? Is that a good way to do it, or is it biased towards one way or the other?

I would say given the absence of any other direction doing what you said is a reasonable approach.

Okay. And then could you just tell us based on this hedge price of $60.54, is that -- as we look out, I guess, to -- the curve is pretty much going along -- I guess gas prices are much higher in 2012 versus 2011, but is that -- was that something which is maintainable going forward in 2012, or is there -- as we look beyond that?

Essentially that number reflects the market. This number for 2011 is as we've reflected and our retail contracts will roll over at a ratable pace about 10% a quarter roughly. The polar contracts expire at predetermined dates. They're more lumpy, but in the long term look four or five years down the road that average revenue will reflect the market price as the contracts roll over.

Okay. If I could just -- or repeat that question another way, is the $60.54 above market right now, or is it pretty close to market if you were to recontract it currently?

It's a fair reflection of the current market for the products involved in the contracts.

Okay, thank you so much.

Thank you. Our next question's coming from Greg Gordon of Morgan Stanley.

Thanks, good afternoon.

Hi, Greg.

A couple questions as it relates to cash flow. You clearly have a pretty strong cash flow position, notwithstanding the soft power market outlook. How much of that is coming from things like regulatory asset balances and how long do you have to benefit from those before they run off? And is there also a benefit from bonus depreciation or any other things rolling into 2011? Then I have another question after that.

I'm going to let Harvey deal with the bonus depreciation question, but I think you'll see that we have been extraordinarily aggressive in holding down our O&M expenses. We continue to do that. We continue to expect that to be the case next year, and by holding that down, reducing our capital program, we'll continue to drive the free cash flow that we need to have. And I'll let Harvey deal with the bonus depreciation.

And, Greg, just finishing up on the regulatory assets, we would expect that to continue for several more years. We still have the distribution deferrals in Ohio and some other things that are being collected from our rate surch group -- surcharges. I'm sorry, the question on bonus depreciation?

Did you benefit from it this year, by how much, and is there an assumption for any benefit next year?

Yes, roughly about $180 million this year and next year. Whenever the Fremont plant is completed we would expect somewhere in the $75 million to $80 million range.

Great. My second question goes to credit metrics. As you talk to the rating agencies around credit, what are your target FFO-to-debt metrics and where do you feel you are relative to those? And this is a question that I think is becoming -- something people are asking, a lot of adverse findings, so just wanted to know how you feel about your credit metrics relative to the current power market outlook?

Well, we don't think our credit metrics are where they need to be. We're working to improve them. Obviously generating free cash flow and the level of liquidity we have gives us near-term benefit. We've articulated in the past our desire to sell some non-core assets. The merger with AYE is driven with equity. But you're correct, our game plan is to improve those metrics and we've been improving them on a quarterly basis and we expect to continue to do so. Jim speaks with the agencies quite often, so I think he can give you a little bit more one-on-one flavor.

Yes, Greg, I would agree with what Mark said there. Our goal is to incrementally keep improving those metrics on a quarterly basis and if we do sell some of these non-core assets we'll use those proceeds to pay down debt. So we would expect to continue to see those improvements.

Thank you, gentlemen.

One other point is when you look over at the utility side of the business we try to keep their capital structure very closely aligned with the regulatory rate structure.

Yes. Okay, thank you.

Thank you. Our next question's coming from David Frank of Catapult.

Hi, good afternoon.

Hi, David.

Two quick questions. One, could you give us an outlook on the retail electric market in Ohio. What are your shopping expectations -- or what are your expectations for shopping and opportunities, both in your service territory and those of your neighbors? Are you seeing any new areas emerge, or give us an update there?

Well, without getting into the details, we're seeing opportunities not only within the traditional franchise areas, but throughout the state of Ohio, and we're aggressively pursuing sales, not only here in Ohio, but elsewhere.

And I think if you go back --

There's -- there isn't a -- I haven't seen the top to the market yet.

Okay.

I think you can see that in some of my comments. We were a 6.3 megawatt hours above last year's period, a 45% increase, and half of those came from customers outside our traditional service territory and about a third outside the utility service territory, so we're very pleased. It's all about margin, where we can get the highest margin, and if we can get that in a location outside of what would be deemed our traditional franchise territory, that's where we will try to push it.

But right now we're very pleased with what they're doing. They're structuring contracts, they're staggering them, they're giving us higher margin, and we would expect that to continue. We don't see any reason why it would not.

Right. And I guess, Tony, just your pick for who's going to win the governor election and thoughts on what it's going to mean longer term to the commission there?

Well, I think either Mr. Strickland or Mr. Kasich will win, and I assume you were only talking about Ohio, because there's multiple states that we're involved in.

No, Ohio.

It's -- I think it's going to be a very close race. The numbers have it different ways, depending on what polls you look at, so we will have a winner next Tuesday.

Going out on a limb. Thanks, thanks.

Thank you. Our next question's coming from Carrie St. Louis of Fidelity.

Hi, good afternoon.

Hi, Carrie.

So I just wanted to turn and follow up on some topics. First of all, with respect to the non-core asset sales, any update on timing?

Yes, that's a good question, Carrie. We think we're going to sell a portion of the Fremont asset, hopefully -- oh, excuse me, [Obec] --

Obec asset.

-- Obec by the end of the year, that's fairly prolonged. On the Signal Peak asset we've always articulated that as its production gets up to the 100% level, we'll accelerate that sale. They had a very strong third quarter. I think I've articulated in the past we brought in a new Chief Operating Officer who spends all of his time inside the mine.

We've seen a dramatic increase in the production from Signal Peak, so on that asset I would say sooner rather than later. Probably we hope maybe in the first quarter of next year, not too much beyond that. But, again, it depends on their production schedule. We just don't want to get into a debate with a potential buyer as to what the actual production level is. And some of the other assets might be not as far along, but we're making progress.

Okay, and I saw on the press release, I believe --

But, Carrie --

Yes.

-- I want to make clear one thing that Signal Peak is a very valuable asset --

Yes.

-- and we are not exiting that business prematurely.

Yes, no, I understand. I was just going to say based on the press release that I believe some debt financing has been put there or structured there, and so when you think about an asset sale there, does that -- that debt would move off with the asset, correct?

Yes, there's -- we financed the original development of the mine. It was never our intent to be the permanent financing source. The market was attractive to do something. The production is far enough along that it's no longer considered a start-up development. Jim's team was able to execute that. While the debt is still on our books, the cash now sits on our books. So, Jim, do you want to add anything?

Yes, Carrie, this is Jim. We put in place a revolving credit facility down at Signal Peak. No matter what debt's outstanding at Signal peak, we have to consolidate that on our balance sheet. We had been funding that operation with about $250 million from our revolving credit facility, so essentially it freed up some of our liquidity. But once we sell the asset, if and when we do, it's really like three years it'll help us.

One, you will not consolidate that debt. It's on the balance sheet right now, which is about $325 million. The excess cash over that debt that we get we'll be able to use that to further pay down debt, and as Tony said, it's a very valuable asset. We would expect that we would generate a gain on our investment that would enhance our retained earnings.

Okay, fabulous, thank you for that thorough answer. Okay. Then turning to the disclosure that you'd be giving more information at EEI, what information is that and specifically, do you think it would include like the hedging outlook for 2012?

Yes, I think -- Carrie, this is Mark. We're going to just take the questions we've gotten today, sit around the table, try to get a sense of what additional information people want, and then provide it, and I'm certain that Ron and Irene are going to get a lot of questions as soon as the call is over. Our intent is to try to address as much of that as possible.

Okay. Well, then -- here, I'll just throw something out then, too. Obviously, with respect to credit metrics, which have come into focus, and you mentioned your regulated op cos are capitalized in agreement with your regulatory structure. I think investors tend to quickly look at the consolidated metric versus focusing on the different parts, which are capitalized differently.

Yes.

So what is the outlook at Solutions, when in terms of a metric, and what is your commitment there? My sense is that you have been very firm about maintaining investment grade metrics at Solutions, if not better, and I just wanted to get reiteration of that view from you?

I think you stated it right on the button. We expect to maintain investment grade ratings, if not better, and our target is to move them to the better category and I think that was well stated.

Okay, thanks.

Thank you. Our next question's coming from Hugh Wynne of Sanford Bernstein.

Good afternoon.

Hi. I was looking at your consolidated income -- or consolidating income statement, I guess it is on page nine, where you compare earnings energy delivery services to --

Hugh, could you speak up just a little?

Sure. I was looking at page nine and at the consolidating income statement there, noticed that energy delivery services this year looks like it's going to contribute almost three-quarters of earnings. Now, my question really related to dividend policy post merger. Some companies with a similar composition of earnings will link the dividend to the regulated earnings of the Company, so I guess my question is this.

How do you see the composition of earnings across delivery services and energy services developing post merger? And then second, what would be the guiding factors in your advice to the Board regarding a dividend policy? Is this one of the considerations, or others have a greater weight in your thinking?

Well, Hugh, I think we're looking long term probably closer to 50% out of the wire side of the business and 50% out of the generation side of the business, so we'll just see how that plays out. My own sense is everything you just talked about will be something that we think about and consider as we try to design an appropriate policy and communicate that policy to the -- to our investors at some point. At this point, I'm not really prepared to discuss any of the specific things that we would look to, but obviously the proportion of regulated versus competitive would be part of what we would look at.

Hugh, I would only add that when you get to the consolidated company of FirstEnergy and AYE, you're going to have a transmission piece in the middle that will be also throwing off substantial earnings and so that all has to get placed into the mix. Until we get all of that finalized with the transition teams we're still a little bit ahead of the curve.

Hugh, this is Harvey Wagner. I'd also just remind you that the impairment charges associated with the late plants distorted that comparative impact among the segments of nine months.

Right. Okay, thank you very much.

Thank you.

Thank you. Our next question's coming from Jeff Coviello of Duquesne Capital.

Good afternoon, Tony, Mark.

Jeff.

It's John actually.

Hi, John.

Hi. I just wanted to go back to your comments that -- you made a couple comments, I guess earlier on the call, one that sounded like there was no risk of a dividend cut and then you also mentioned the need that you saw for credit metric improvement, and then finally, you talked a little bit about -- or you alluded to a more formal dividend policy that accounts for volatility after the Allegheny deal. So my first question is, have the rating agencies commented on the level of dividend payout over the next several years and in combination with the pace at which you need to delever to maintain that investment grade rating or that low BBB rating at FirstEnergy Solutions. Can you talk a little bit about how you balance the two?

John, I don't believe so and Jim's shaking his head no.

We haven't had any specific conversations about the dividend policy, John.

I don't want to speculate, but I assume that if our cash flow wasn't as strong as it was we might have that question, but not with the cash flow we're now generating.

Got it. And what did you mean by a more formal dividend policy that accounts for volatility? What does volatility mean?

Well, I guess the easiest way to explain that, John, is when you think about a competitive business in which the market price, just even here, couple years ago, was, pick a number, 50 now it's 30. When you have that type of movement, if you had a policy that just said you're going to send a percentage of earnings out, then when the market is very, very good, the dividend is high, but when the market is not as good, then the dividend has to be cut to reflect that.

I don't think that's the policy that we would endorse. We would be looking for something that would be able to be sustainable and be maintained in whatever economic environment we face for the long term. So that's what we would be looking at and that's what I mean by it.

Okay. And then so that consistent with your earlier comment means that at the current level of dividend and paid out in cents per share, I guess effectively, your dollars per share, that you're very confident that that is sustainable based on the amount of delevering you need to do and the target to maintain an investment grade rating at FirstEnergy Solutions? I'm trying to understand what exactly you meant there, please.

The answer would be yes.

Okay.

Thanks, John.

Thank you.

Thank you. Our next question's coming from Steve Fleishman of Banc of America.

Hi, Steve.

Yes, hi. END AUDIT -- AUDIO AT 1 HOUR

Hi. Just -- this was really Greg Gordon's question just asked again. The amount of the 2011 operating cash flow that is for recovery of deferrals, how much is that?

We don't have those numbers with us here at the moment, Steve.

Okay. So I guess to ask another way, would you be free cash flow positive without deferral recovery?

Yes.

Yes, it's certainly below $500 million.

Okay, because it looks like year to date the amortization's been about $550 million from page 13, for the nine months, the slide that you have with deferrals and amortization?

Yes.

Is that $550 million all being recovered with cash flow? Is that all being recovered in revenue?

Yes, don't forget that CEI's transition cost recovery will be ending in 2010.

Okay. So that number will be -- full-year number this year might be $700 million, but it'll be dramatically lower next year?

Right.

Okay, great. Thank you.

Thank you. Jackie, we'll take one more call. Thank you.

Thank you. Our last question's coming from Paul Fremont of Jefferies and Co.

Thank you very much. Looking at the capital spending, should I assume that you have made a decision not to scrub any of the coal plants that currently don't have either scrubbers or SCRs, or is that a potential future call on your spending?

I don't think we've made any decision related to that. We have transition teams working now, looking at the generation of AYE, what it would cost to increase their capacity factors and reduce down their forced outage rates, and when that team makes a recommendation we'll be in a great position to answer that. But right now they're looking at both systems and where would be the best place to deploy the least amount of capital, or get the most bang for your dollar.

Okay. So the capital spending could go up if you decide to scrub any or all of the unscrubbed units, right?

Yes, it also could go down. As we elect not to spend money on our units because their unit is in a cost range and dispatching range where we wouldn't spend it on our side, so it could go either way. Our game plan is not to, again, spend money where we can't get more immediate benefit than either of us could get independently.

On your second quarter call you had talked at Signal Peak about targeting a production level of 600,000 tons per month. Is that where you currently are in the third quarter, or can you give us a sense of what the production level is?

I think the production level's a touch below that, but it was -- it's on a ramp up. I think the raw tonnage in September was 900,000, but that's got to be washed, so that was probably down 650,000, 700,000. The more important feature to me is it's increasing dramatically every month now that we have someone that's rela -- a mine expert, sitting in a mine every day and we just decided that we had the CEO, John DeMichiei, maybe spread a little too thin. He did a fabulous job developing the mine, but he can't get in the mine every day. The new gentleman is and he's doing great and you're seeing that in the production levels.

And, Paul, one of the production issues I think we need to at least highlight for you is that we are now in the first long wall panel. That'll be moved in April -- March-April timeframe into the second panel. The second panel is a much more -- much higher seam and therefore if you get those types of production numbers, you get a much better clean product coming out, because you're not taking as much ancillary product along with you. So it really is part of this overall development as you move through the initial panel into the panels that will, in fact, be the long-term future of that mine.

That could delay --

No, it doesn't delay, it's all in the plans. It does not delay, it's all part of the --

That could delay your decision to sell because you might not be at the run rate that you expect the mine to be until you get to that second --

No, no, that's just a -- again, we're talking we're very sophisticated people, Paul.

Okay.

They understand the difference between seam and the seam you're going. As you ramp up that production that's capable of delivering, once you move it through the wash facility to higher recovery rate, your numbers come naturally.

And my last question is, I guess Mark had talked about being comfortable with the payout level on a 2011 earnings. Should we assume that there's no further potential deterioration in earnings beyond 2011, or if, in fact, the earnings level were to go lower in some of the out years, would that not result in a significantly or potentially higher payout level than what you could see in 2011?

I think we'll give 2012 guidance when -- as Tony alluded to, in that timeframe, but my only response to the prior question was we've got $500 million-plus projected cash flow after paying the dividend. I know we've been -- I think the question was related specifically to 2011 and we responded specifically, but we'll give 2012 in the timeframe that Tony alluded to.

Okay. Thank you, appreciate it. Thank you.

I'd like to thank everyone for joining us on the call today. As always, we appreciate your continued support and interest in FirstEnergy. Thank you, and have a great afternoon.

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