第一能源 (FE) 2005 Q3 法說會逐字稿

Good afternoon. My name is Corey, and I will be your conference facilitator today. At this time I would like to welcome everyone to the FirstEnergy Corp third-quarter earnings conference call. (OPERATOR INSTRUCTIONS). It is now my pleasure to turn the floor over to your host, Mr. Kurt Turosky, Director of Investor Relations. Sir, you may begin your conference.

Thank you, Corey. During this conference call, we will make various forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of FirstEnergy Corp are based on current expectations 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 a consolidated report to the financial community, which was released earlier today and is also available on our website under the earnings release link.

Participating in today's call are Tony Alexander, President and Chief Executive Officer; Rich Marsh, Senior Vice President and Chief Financial Officer; Harvey Wagner, Vice President and Controller, and Jim Pearson, Treasurer. I will now turn the call over to Rich Marsh.

Thank you, Kurt. Good afternoon, everybody. We appreciate you being with us today.

I will start our call this afternoon by providing an overview of our earnings results and operational performance, and then Tony Alexander will discuss some of our regulatory initiatives. Information regarding our third-quarter results was provided earlier today in our consolidated report to the financial community, and it might be helpful to refer to that document during the call.

Let's start with the review of our third-quarter financial results. Please note that we will refer to earnings and cash flow results on a non-GAAP basis and that reconciliations to results on a GAAP basis are available in the consolidated report, as well as on the Investor Relations section of our website.

Earnings on a GAAP basis in the third quarter were $1.01 per share compared to $0.91 per share during the same quarter in 2004. Normalized non-GAAP earnings were $1.04 per share, excluding an unusual charge of $16 million or $0.03 per share. This related to a labor arbitration decision associated with Jersey Central Power and Light's callout response policy from December 2002 through May 2004. The Company has filed a motion in federal court to vacate the arbitrator's ruling, and although no amounts are payable until all our legal challenges are exhausted, we did record this reserve to reflect the arbitrator's decision.

Normalized non-GAAP earnings of $1.04 per share in the third quarter compared favorably to normalized non-GAAP earnings of $0.97 per share in the same period last year. This improvement was driven primarily by the higher electric gross margin resulting from increased distribution deliveries and the continued strong performance of our generation fleet.

Electric distribution sales increased 10% primarily as a result of the unusually warm weather during the quarter. Cooling degree days were 40% higher than during the same period last year and 32% above normal. The residential segment, which is our most weather sensitive sector, experienced a sales increase of 15%. Commercial and industrial deliveries increased 8% and 5% respectively.

The other major driver of our electric gross margin improvement was the continued strong performance of our generation fleet. Despite the demands imposed by the warm weather and high customer demand, our fossil base load plants operated at a 91.5% capacity factor and our nuclear units achieved a capacity factor of 99.6% during the period. This performance resulted in a new quarterly generation output record of 21.7 million megawatt hours, bringing our year-to-date total to 59.5 million megawatt hours. We remain on track to establish a new generation output record this year following last year's record performance.

Partially offsetting the positive contributions to electric gross margin was a reduction in our higher margin wholesale sales since most of our generation was used to serve the significant increase in our native retail load. Higher fuel expenses and purchase power prices also reduced the electric gross margin contribution to earnings.

Other drivers for our improved financial performance included a $0.03 per share increase in earnings resulting from the Jersey Central Power & Light settlement of the Phase I and Phase II rate proceedings during the second quarter, a $0.05 per share benefit from lower pension and other employee benefit costs resulting in part from the voluntary contribution to the pension plan in September of last year, as well as changes in health care benefits, and a $0.07 per share net benefit from investing, financing and other activities. Positive contributions resulted from gains realized in our nuclear decommissioning trust, investment performance associated with our corporate owned life insurance portfolio and income from noncore businesses. These were partially offset by higher general taxes and a slight increase in financing costs driven by higher short-term interest rates.

Other factors that partially offset our earnings improvement included a $0.05 per share increase in net PJM and MISO transmission costs after the deferral of MISO costs, primarily due to higher congestion expenses experienced this summer. A $0.03 per share increase in energy delivery expenses due to increased spending on reliability initiatives. And a $0.06 per share increase in depreciation and amortization expense due to a higher aisle transition cost amortization and increased depreciation expense.

During the quarter, we completed net redemptions of debt preferred securities of $406 million, as well as $103 million of refinancings and repricings. These actions will reduce financing costs by $9 million this year. Net debt preferred redemptions now total $675 million, a principal value year-to-date, and we remain on track to achieve our adjusted debt to total cap ratio target of about 55% by year-end.

Our continued improvement in both financial and operational performance was recently recognized by Standard & Poor's when they raised our corporate credit rating to BBB from BBB-. They also raised the rating on our holding company's senior unsecured debt to BBB- from BB+, meaning that all of our debt is now investment-grade. This action allowed us to recapture $109 million of cash collateral that was posted with counterparties at the time of the upgrade.

In September our Board declared the second dividend increase this year, raising the quarterly dividend payable on December 1 to $0.43 per share versus the previous rate of $0.4125 per share, for an increase of 4.2%. On an annualized basis, that brings the dividend rate to $1.72 per share, which will service the base against which the board is expected to apply the targeted annual growth rate of 4 to 5% for dividends to be paid next year.

Through the end of September, our normalized non-GAAP earnings are $2.22 per share. Our 2005 annual earnings guidance remains at $2.85 to $3.00 per share exclusive of unusual items.

Year-to-date our non-GAAP cash -- non-GAAP cash generation was approximately $700 million. And although we may exceed our cash generation guidance of $620 million at year-end, we will not change our annual guidance at this point.

For 2006 our earnings guidance remains at $3.40 to $3.60 per share exclusive of unusual items. Our cash generation guidance also remains unchanged 300 to $400 million, including projected capital expenditures of 1 to $1.1 billion.

I appreciate your attention, and I will now turn the call over to Tony who will give us an update on our generation asset transfer initiative, as well as some of our regulatory activities. Tony?

Thanks, Rich, and good afternoon, everyone. First, I would like to provide an update on our generation asset transfer initiative. Yesterday we completed the transfer of our fossil and hydro generation assets from our Ohio utilities and Penn Power to FirstEnergy Generation Corp. These assets were transferred to align the ownership with our competitive business units which already have operational responsibilities. Also, our Ohio and Pennsylvania transition plans required these transfers.

Our fossil generation company purchased the utility's interest in these fossil and hydro properties for an aggregate price of approximately $1.6 billion. The transfer does not include the interest of CEI and Toledo Edison and certain fossil units under existing sale and leaseback arrangements. We anticipate completing the transfer of our nuclear generation assets by year-end following the NRC approval of that transfer.

When it comes to regulatory matters, on September 28 the Public Utilities Commission of Ohio approved the schedule for the competitive bid process for our Ohio regulated retail load. This option will be to provide firm generation service for the 2007 and 2008 period and is scheduled to begin on March 21, 2006. The commission has indicated they will accept or reject the bids within two business days after the close of the auction.

On September 9 in an effort to address customer concerns regarding rising energy prices, our Ohio utilities filed a rate certainty plan to supplement the existing rate stabilization plan. Under the existing plan, customer rates would be expected to change several times through 2008 as a result of increased fuel costs and a distribution rate case, and completion of the transition cost recovery. If approved, the rate certainty plan will result in customer rates being maintained at current levels through 2008.

In addition to providing stability in customer rates, the proposed plan also provides the companies with a more stable and consistent earnings pattern. The plan has the support of our Industrial Energy Users of Ohio, that group; the Ohio Energy Group, where both of which are made up of industrial customers, and also the cities of Cleveland, Akron and Parma. The PUCO is scheduled in evidentiary hearing to begin on November 29 on our rate certainty plan.

Finally, on October 11, Penn Power filed a plan with the Pennsylvania PUC to secure electricity for its customers at set rates following the end of the transition period established under the state's electric competition law. Penn Power is recommending that a request for proposal process be used to source electricity from competitive suppliers for nonshopping customers over the period January 1, 2007 through May 31, 2008.

The RFP process would be managed by an independent consultant and seek bids of approximately 900 megawatts of electricity in increments of 50 megawatts. No supplier would be permitted to provide more than 600 megawatts of the total supply.

In closing, I remain pleased with our performance. Though the year has not been without its challenges, the Company remains on track to achieve the objectives that will position us for continued success. Our generation fleet continues to perform exceptionally well and is on track to set another annual output record this year. Our consistent operational performance enabled us to regain our investment-grade credit rating for senior unsecured debt from Standard & Poor's, and we have enhanced our financial strength by paying down about $700 million of debt, and our shareholder value by increasing the dividend rate by 14.7% this year.

We filed a rate certainty plan that would provide stability in customer rates and also completed the fossil generation asset transfer, and expect to complete the nuclear plant transfer by year-end, both of which actions will further position the company for competitive generation markets. I am confident that we will continue to produce consistent operating and financial results that meet or exceed the expectations of our customers and investors.

I appreciate your time and your support, and thank you for joining us this afternoon. I will ask the operator now to open the call to questions.

(OPERATOR INSTRUCTIONS). Kit Konolige, Morgan Stanley.

A question for you on the cost of fuel and purchased power during the quarter. Your narrative discusses does the higher fuel expense of purchased power prices also negatively affect the electric gross margin. I may be adding this wrong, but it looks to me like when I add up fuel and purchased power and compare it to the year ago, it is virtually the same. I get 1 billion 287 versus 1 billion 285, and you ended up with more megawatt hours so that the cost per unit looked slower. And I getting this right, or maybe you can give us some color on your cost of fuel and purchased power?

This is Kurt Trosky. I just want to make mention when you look at the income statement specifically in terms of some of the fuel and purchase power line items, there are various adjustments that are necessary because of some of the deferred cost accounting associated with the former GPU companies. And when you make those adjustments out, because there are certain revenues up in the revenue line, it has no impact on the bottom line net income for the quarter. But it does adjust some of the fuel and purchase power line items in the expenses. If you look -- I mean, some of the information that we could share to give you a little bit of color --

I can give you some numbers in terms of specifically what was included in that generation margin calculation that we talked about. Fuel expenses versus the same period last year were about $120 million higher. There's obviously both a volume and a price component to that and similar situation with purchased power which was about $62 million higher this year than in the same period last year. And that is reflective of those adjustments that Kurt mentioned.

Right. Are you seeing any impact from higher PRB prices? Is that something that is a focus of yours now now? They have jumped dramatically in the third quarter, and I guess were creeping up before that. But I guess until recently it was Eastern call that was your issue and PRB was kind of the stuff you put in that make it average lower price -- lower cost.

A couple of components to that. We had originally planned to burn roughly 40% PRB this year, but because of transportation constraints coming out of the basin, which I think everybody is facing it here on the East Coast, that is going to be lower by about 30%. So there is a volume impact. We are not earnings much PRB as we thought we were going to because of those transportation constraints.

And also there has been a price increase, although a lot of our coal price exposure is hedged for normal customer load, normal customer demand. But certainly in periods like the third quarter where we did generate more than we thought we would, we burned more coal and had to use more PRB, so there was some impact.

Right. And can you remind us of your hedged position looking forward over the next few years?

Sure. It is essentially fully hedged for the next several years.

Right.

To give you an idea, the average price per fuel in the third quarter this year per megawatt hour was about $6.00 higher than it was in the third quarter of last year.

Can you give us what those numbers were?

About 22 this quarter versus 16 last year.

And can you break that down into nuclear and fossil?

That was essentially all fossil. Nuclear was about flat year-over-year.

Right. Okay. Yes, fuel that would be fossil. Okay. Let's see, yes, okay. Good enough. Okay. I have asked my quota.

Paul Ridzon, Key McDonald.

I had two questions. One was the magnitude of the growth of industrial sales was kind of surprising. Kind of what is driving that?

And secondly, we see in some of the trade press that Green Mountain looks to be leaving Ohio, and just kind of what are the implications there? Is it a year-round better margin associated with that retail load, and what are the rules that they come back under? Do they come back under the fixed bullet pricing?

Yes, yes to answer that part of your question first off. Going back to the industrial sales, I don't know that I have a really good explanation. I mean our sales have been a little bit to industrial customers sporadic this year. You know, obviously a lot of our industrial load is concentrated up in the Cleveland electric Penn Power territory, heavy exposure to steel, glass, automotive-related industries. I don't know if there is any underlying trend there. Hopefully there is. Obviously we're pleased with their performance, but I'm not sure that I can give you much better color on that specifically.

As far as returning customers, I think our expectation going into 2006 is that we will have more customers returning to us from various sources. And as I mention, they do come back to us at the polar rate, and that is a reflection of the high market prices out there. That is what our anticipation is for.

Would you rather have those megawatt hours for sale in the wholesale market given what we are seeing out there with natural gas pricing, or would you rather have stable retail load?

We want higher prices and stable retail load. But you cannot always get that. I mean this quarter if those kind of market prices persist, there were many times where we probably could have made more money had we had some excess generation to sell wholesale as opposed to retail. But that changes from period to period obviously.

Steve Fleishman, Merrill Lynch.

A couple of specific questions on the quarter. The $0.07 benefit from investment financing and other activities, could you be a little more specific on that because interest costs actually looked like they were up in the quarter?

Sure. As I mentioned, Steve, there are a couple of parts to that, one of which is the investment results of our corporate owned life insurance policy. Every quarter there is some relatively minor impact positive or negative from that. This quarter was up contributed a couple of cents worth.

Incremental income from MYR, one of our subsidiary companies, was included in this item. That was about a penny to the positive. Some other miscellaneous items added about a penny. Nuclear decommissioning trust we have about 1 billion 7 portfolio in our nuclear decommissioning trust. Every quarter for the last several years there has been some element of realized gains that flow through that -- flow through the income statement, some quarters more, some quarters less. So that was a contributor to that $0.07 net impact this quarter as well. And then the offsets are a slight impact for a higher short-term interest rates on our floating rate portfolio and higher general taxes.

So those are the pieces that went into it. The largest component of the positive $0.07 was the realized gains on the NDT, which I say are there to one degree or another every quarter but sometimes larger, sometimes smaller.

Okay. And then on the MISO PJM transmission expenses, could you just give us a little more flavor on -- is this just the impact of a hot summer high-priced market, thus more congestion and that is it, or is it somewhat related to inefficiencies in how these things are running? I think you were benefiting from MISO in the first half of the year, so is this kind of a reversal of that?

The big driver during the third quarter, Steve, was what you mentioned, high sales, high throughput and higher congestion costs as a result. So that was the big driver of the incremental transmission expense in the third quarter.

Okay and then one last question on your 2006 guidance. Two things. One, does that include an assumption that the RCP plan is approved? And then secondly, does that include any use of your free cash or what are you using that for?

You know, when we put the guidance together, obviously we ended up with a guidance range. And when we tried to set that range, we made our best informed guess based on what we thought '06 was going to look like in terms of potential regulatory outcomes and uses of cash. So to sum general degree, those things are incorporated, and those are items that could help drive us from one end of the range to the other. So that is really how we arrived at that specific guidance range.

Okay. So some of those things were already considered?

You know, like I say, those are things that could drive us within that range. So that -- (multiple speakers).

Paul Patterson, Glenrock Associates.

Could you give us a feeling for year-to-date what the nuclear decommissioning trust fund has given you so far?

So far this year, for the first three quarters of this year, it is about 4 or 5 million higher than it was for 2004 for the year. And I think it was about 59 million over last year.

Okay. And in 2006 and the 2006 guidance, what are we looking at with respect to that?

I don't know that we made a specific assumption in that guidance for that. Like I say, that's -- it is part of the normal investment management routine, and these trusts are all managed externally by independent investment managers. And as you would expect with a portfolio approaching $2 billion, there is always going to be some level of activity so we don't make a specific assumption for that.

But the influence of some market security price impact I would assume as well, correct, guys?

Yes.

That would that as well. So it depends in large part what happens with respect to the securities market?

Yes, that is right.

Okay. Thanks a lot, guys.

Paul Fremont, Jefferies.

Two questions. First, a follow-up to Steve Fleishman's question, when you provided the drivers for the change '05 to '06 when you initially provided your '06 guidance, I think you mentioned $0.50 for the Ohio rate stabilization plan, $0.10 for T&D growth, $0.06 for the JCP&L settlement, $0.03 for lower financing and higher generation margins and play benefit, depreciation, etc. But clearly there was nothing specifically there to talk to the rate certainty plan. So I just want to make sure that understand the rate certainty plan is a part of that 340 to 360?

Yes, the numbers you quoted there are all correct. Those were all parts of our guidance, Paul. We are not viewing the rate plan as incremental. It is included in that 340 to 360 guidance, and it serves as one of many components that go into moving us from one end of the range to the other. So your assumption is correct.

Paul, this is Harvey Wagner. There is one element, too, with the rate stabilization plan, there was an assumption for recovery of increased fuel costs, and you will recall that our rate certainty plan changed the mechanism for how that would be recovered. So there really are some elements there that are explicit in the original guidance.

Okay. The second question that I have is, if I strip out the 27 million of MISO cost and the 15 million of system reliability costs and make the adjustments to O&M for the nonrecurring items, it still looks like there was an 8% increase in operating and maintenance expense in the quarter. Can you give us a sense of what the drivers for those cost increases might have been?

Hang on for a second, Paul. Let us switch to the income statement. Hang on, we are still working with Paul here.

Paul, part of the difficulty is when you're looking at the MISO cost, those are net of the deferrals in Ohio, and that was about $31 million. And on the income statement, if you're looking at that, the deferral of the MISO costs were included with the deferral of new regulatory assets. So you would have to add that in.

So it is like 31 million of the variance is related to deferral?

Right.

Yes. We can give you -- instead of flipping through our pages, it might be better if we just give you a call back and we can step you through it.

Thank you very much.

Thank you for your report this morning as well, Paul.

Hugh Wynne, Sanford Bernstein.

I was wondering if I could ask you to comment a little bit more about how you are positioning yourselves for 2009? I guess I'm really interested specifically in perhaps three aspects of that. One is, what remains to be done to transfer the remainder of your generation assets out of the retailing subsidiaries? I recall that the remaining generation assets were already sort to sale/leaseback arrangements, so I was curious what remains to be done there.

Secondly, I'm interested in learning about the progress of your suit or your brief to the PUCO regarding AEP's suggestion that it be allowed to recover in T&D rates the cost of its IGCC.

And then finally, any comment you might make about market conditions. I noticed you say that the wholesale margins seem to be better on generation than your retail margins and that some of your retailing competitors like Green Mountain Power were withdrawing from the market. I was wondering if you might comment on those things, and maybe give a little bit better feel for what you see as the outlook post-2008?

Okay. Let me deal with the first thought dealing with the asset transfers. You know, basically we have transferred all of the fossil and hydro at this point, except some parts of I think the Mansfield's plant that CEI has a sale/leaseback on.

Now, with respect to those assets, they are essentially -- the kilowatt-hours are essentially transferred by contract to FVS (ph).

Now with respect to the nuclear, we're waiting on the NRC approval. I believe that is the last thing that needs to be done. And then we will transfer all the owned assets -- I guess maybe we have a couple of other approvals that need to get in place -- but assuming we get all the regulatory approvals, I think maybe it is NRC that we need (multiple speakers) -- I guess we need FERC and SEC also.

Assuming all that takes place, the nuclear assets that we owned, which would be all of Davis-Besse, all of Beaver Valley One, the vast majority of Perry, and the vast majority of Beaver Valley Two would all be transferred into FirstEnergy Nuclear Operating Company. The remaining interest, those that are held by sale/leaseback, again that sale/leaseback, the kilowatt-hours associated with that leasehold interest have been transferred and managed by the FirstEnergy solutions organizations or outside of the utility organization.

So if all that occurs, we should have -- if everything stays on track, we should have all of that done by the end of this year. And at this point, we don't see any benefit in dealing with the sale/leaseback assets in a different way than we have contemplated through this transaction.

When it comes to AEP's suggestion to build at IGCC's plant, you know I think our legal position, although I don't want to get into it into much detail -- I mean it is pretty straightforward -- we don't believe that Ohio law allows that to occur. We believe that Ohio law requires a separation, that it does not allow an individual unit to be effectively rate based in the future, which is what AEP as I understand it is attempting to do. We would see that we believe that is again inconsistent with the competitive deregulation law in the state of Ohio.

Pretty straightforward I think our position. If you read the pleadings, you probably can see where we are coming from on that.

When it comes to market conditions, I think it might be still a little early to tell, but there does not appear to be much happening in the market that would tend to hold down the price. All the commodities seemed to be moving in a direction of either higher than what we have been used to for stabilizing, but stabilizing at a higher price than where we might have been three years ago or five years ago. Where that is coal or natural gas, there will probably be some pullback. But the fact of the matter is there is going to be higher price commodities going in. There is going to be a significant amount of environmental investment that is made on the fossil fleets across the Midwest footprint anyways, and those costs will ultimately have to be reflected in the price on a commodity basis. There's no new generation being added to effectively hold down those potential increases, and the natural gas that has been added basically just puts more natural gas on the pricing model, more hours in the natural gas base, as opposed to coal or nuclear space.

So my sense is that wholesale prices that ultimately what gets reflected on a retail basis, is going to reflect that kind of market conditions in the future.

That is great. That is very helpful. Just one quick follow-up. What percentage of your generation sales are in Ohio I guess are still the subject of the sale leaseback arrangements? And what risk, if any, does that create for you in terms of not being able to isolate those sales from state regulation?

I don't think we run the risk that we cannot isolate them, but the fact of the matter is I would think and somebody can ballpark this for me if they are here. My guess is it is maybe less than 500 megawatts in total. (multiple speakers). Now Kurt can verify that, but it --

Less than 10% I would say.

Maybe less than 10% might be the better number. So it is fairly small overall component of our generation fleet.

Ashar Khan, SAC Capital.

Rich, could you tell us what the realized wholesale margin was for the quarter?

I'm sorry. Could you repeat that, please?

The realized wholesale margin for the quarter.

Not off the top of my head. I think we can probably come up with a number for you and get back to you on that.

Okay, I appreciate it. And then could you just give an update on the New Jersey securitization, what is happening there?

Still nothing definitive at this point. We're still hoping that can be a 2006 event for us. We are continuing to work with the board and try to move towards that objective, but we don't have anything finalized or locked in at this point.

And any update, Rich, from the Merrill conference? You had mentioned that some product contribution to the pension plan, any update as to the amount that might be and the timing?

What we had talked about I think was potential uses for our free cash and how we look at the different economic alternatives of say, using that for a contribution to the pension plan versus using that for a share buyback and so forth. And certainly contributions to the pension plan produce an attractive economic return in addition to reducing net debt like liability and improving the funded status of the plan.

So that is something that we still are considering. We have not come to any final decision on that. We have not presented anything to the board for their approval at this point. But as the year progresses, we will keep that analysis going and looking at possible uses for our cash.

Okay. I appreciate it. Thank you.

Stephen Huang, Citigroup.

I had a question here related to the securitization again. Did you say that you guys are still on plan for 2006, or did you mean that 2005 you hope you can get it?

No, we're hoping now it is 2006. I don't think -- it is not going to happen in 2005. Just not enough time left.

Okay. You think in the first half of '06?

That is our expectation. Yes.

Okay. And then following back on the question on the MISO transmission costs here and PJM costs, if we return back to more normalized weather, should I be able to expect that ultimately 7 million sort of disappears?

I would not think the whole amount disappears, Steven. I don't know exactly how much. I mean it would be meaningfully less, but I'm not sure if I can estimate how much less it would be, but it would be less.

Okay. And then on the S&P upgrade, you guys then freed up about -- sold 120 million. Is that still a correct forecast?

In terms of cash recovered, that amount obviously changed periodically based on market conditions and so forth. We actually ended up recovering in cash about $109 million, and we also extinguished some LLCs that I think totaled about $20 million.

Okay. So combined about 129 then relieved of capital?

Yes.

Okay. And then just I guess on the last thing I had here just to follow-up on the question related to the wholesale sale, if we returned back to normalized weather, we should then -- because I'm just thinking off the top of my head when I look at it, you guys should have made maybe $0.05 more or so in the quarter. But because the weather was so much warmer, you guys were taking the lower retail margin. If I'm looking at 2006 and we return to normal weather, we should see a decent size jump up in -- I guess in the gross margins there?

I mean -- you know, I guess it all depends on what market prices are which have some relation to weather but certainly not totally. You know, just to use a -- and this is probably a gross generalization -- but looking at our regulated generation rate during the third quarter versus what we might have been able to capture on the wholesale market, there is probably a $20 delta on the average during the period.

So that is in part influenced by weather, customer demand, a whole bunch of other factors, so it is hard to say how that would carry out in the future. But certainly there was an impact to us because of the very high load and the need to deploy virtually all of our megawatt hours to our retail native load.

Okay, and the last question I have was, because of the hot weather though, what other items on your could be impacted next year when we return back to normalized? You've got the margin spread. You have got the transmission. Is there anything else?

Those are certainly the two biggest. Those are the two biggest.

Other than normal wires revenue.

Gregg Orrill, Lehman Brothers.

I just wanted to follow-up on Paul Ridzon's question about the industrial sales being strong. I was just wondering if there was any color on the 5% improvement?

I don't have anything specific I can give you on that. Like you say, it tends to fluctuate from quarter to quarter. We can pull some information together and get it to you off-line, but I don't have much more to offer at this point. I don't think any of us do. But let us get some color and get back to you on that.

David Reynolds, Tribeca Global Management.

Just trying to square off some of the EPS numbers. Can you just tell me in total what the combination of contributions from the nuclear decommissioning and the pension was in this quarter and the prior year quarter?

And I guess just on a going forward basis, I'm assuming these are like -- they are just trust funds. Is there any reason that -- to believe that these things continue contributing, or is it just as likely that they would reverse going forward? I assume you fund them as close to par as possible.

Yes, I mean for the NDT for the last eight quarters there has been a positive impact every quarter. Now will that continue going forward? It depends on (a), what the markets do, and (b), what the managers of those funds choose to realize versus not. So it is kind of unpredictable.

But much like postretirement benefits, I mean you fund this up to as close to par as you expect it should be to be properly funded on a going forward basis. If you have deltas around performance, then you get some addition or subtraction. But so there -- are you in a situation where you know you are overfunded or this is associated with extending the lives of the plants? Is there any secular going on here, or does this just happen to be around the total portfolio returns from the fund?

There is nothing secular, David. I mean the nuclear decommissioning funds are essentially fully funded at this point. Our contributions have got to the point where it is from an actuarial basis pretty much fully funded.

Okay. And could we just go back to the first part of my question. Can you tell me -- I think when we levelized everything out from an operating ongoing basis, we are 104 versus 97. How much of the 104 and the 97 was nuclear decommissioning and pension contribution?

Yes, $0.07 or $0.08, something like that probably.

In both quarters?

No, that was the delta. This quarter over last year's third quarter.

Okay. So the delta is plus $0.07 or $0.08 this quarter from last year. How about in total in terms of the total amount out of '04, the 104 and the 97? Do you have those?

We don't have them at our fingertips, but we can back to you with that.

That would be great. I would appreciate it.

As I said earlier, David, you know for the NDT realized gains, year-to-date through the third quarter '05 it is a few million higher than for calendar year '04.

Okay. And if I could just ask a quick totally unrelated question, Tony, you mentioned that you are looking at a RFP for Penn Power. I know at one point that you had discussed or hope that Pennsylvania might embrace some form of an auction concept. Could you just tell us kind of how we got to this spot, and are we essentially going out to like '09 when the bigger blocks of retail load come up before we end up at an auction in Pennsylvania or at least what your general view on that is?

Well, we suggested the RFP mechanism, and that is largely, David, a result of just the size of the load. You know we used -- suggested a mechanism similar to what Ducane did, and we just thought that would be a more efficient way to source this power than going through an auction mechanism for Penn Power. It was really the only driving factor there. We could have suggested either, but we thought this was the best approach.

David Frank (ph), Peacock Capital.

Good afternoon. Hey, Rich, I was just a little confused, I guess as Paul Fremont was, about your guidance and what was included in it for '06. You gave out your original '06 guidance, when was the date again?

July.

July. And you were anticipating the RCP at that time. And then there was another person on the call who said that the RSP I think had anticipated fuel recovery in it. But I thought that the RCP essentially sacrificed cash earnings for higher reported earnings, and you would be deferring fuel, so that should not really impact earnings, would it?

No, right. The point was the part of the features of the RCP were captured already with the rate stabilization plan with the assumption of a fuel clause increase.

I see. So the aspect that was already captured in your guidance, was it principally related to the fuel?

Yes.

Okay. And as far as assumptions for changes in amortization schedules, was that also assumed initially in your '06 guidance?

You know, not specifically. Once again, it is one of those factors where when we set that guidance in July looking forward to '06 and some idea of things that we would be requesting and trying to do and so forth, that was I guess one of the factors that ended up in the range being what it was and (multiple speakers) move us up and down.

The other thing, David, if you look back to the exhibit that we filed with our 8-K when we filed the rate certainty plan, the impact on amortizations in 2006 was actuated negligible. I think it was a difference of about $6 or $7 million.

Okay. My other question was regarding just the generation output for this year. Do you have a target for what you think you will generate, and could you tell us again what you have done through the first nine months of the year?

Yes, last year what did we regenerate last year?

76.4 million megawatt hours last year. The target this year in the neighborhood of around 80 million megawatt hours. There will be another record increase, and through nine months, we have generated about 59.5 million megawatt hours.

Okay. So you're on target to hit that 80, and 80, I think as you had previously said, that is what you are assuming for next year as well?

Something very similar to that.

Okay. All right. Great. Well, congratulations on turning around those plants and getting up the output so much.

I appreciate it, David. Those guys have done a great job. Thank you.

In the interest of everybody's time, why don't we take two more calls, and then we will wrap up this afternoon. Go ahead, please.

Daniele Seitz, Maxcor Financial.

Actually most of my questions have been answered. The fourth quarter, could you remind me how many refuelings do you have to do relative to last year so that we can assume that the official same sales will be higher or lower?

Yes, in the fourth quarter of this year, there is no refuelings outages.

Okay, and last year?

Last year.

We're checking. Hang on.

We had Beaver Valley unit one out in the fourth quarter of last year. It was a 28 day outage, and it was completed on November 14. So it was all in the fourth quarter.

Great. And could you also remind me when is the decision on the rate stabilization or rate certainty is coming out?

Well, the hearings are scheduled for November 28, and the process will begin. We don't know how long it's going to take following that.

Okay. So there is no date yet?

There is no firm date for the commission to make a decision. As I say, the evidentiary hearings are on November 28.

Great. And just one last question. MYR seems to be doing better? Is this like a trend, or was there something special happening there?

We do not know if it is a trend. (multiple speakers) -- nothing special.

And it is no -- it is not on the sale block? I mean you don't have any intention to sell it anymore?

You know, what we said is we will continue to look at or not the assets and continue to monitor market conditions and make our decision based on those factors.

(multiple speakers). Terran Miller, UBS Investment Bank.

Yesterday your 8-K with reference to the asset transfer did not necessarily specify how much of the pollution control revenue bonds were transferred over, and I was trying to figure out what the refresh numbers for that were, or is it the same as what was in the E1A?

Zero is the answer. The pollution control bonds will transfer over time. We will do that opportunistically based on market conditions and when it is advantageous for us to do that. So nothing transferred over initially.

Okay, but they will. Those amounts will transfer over time as they are refinanced at FirstEnergy Generation?

Yes, that is our expectation, but there is no specific time scheduled that we have established for that. Like I say, we will just do it opportunistically.

Well, I appreciate everybody's time and interest today. If there were any people in the queue that did not have any questions or did not get a chance to get their questions answered or anybody with follow-up questions, please feel free to give Kurt a call, and we appreciate your time today and we appreciate your continued interest in FirstEnergy. Thank you.

Thank you. This does conclude today's FirstEnergy Corp third-quarter earnings conference call. You may now disconnect.