第一能源 (FE) 2005 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen. And welcome to the FirstEnergy Corp. second quarter earnings conference call. [OPERATOR INSTRUCTIONS.] It is now my pleasure to turn the floor over to your host, to Mr. Kurt Turosky, the Director of Investor Relations. Sir, you may begin.

Thanks, Holly. 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 expectation 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 issued 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; Jim Pearson, Treasurer; and Terry Howson, Vice President, Investor Relations.

I'll now turn the call over to Rich Marsh.

Thanks, Kurt, and good afternoon, everybody. Thanks for being with us today. I'll start the call with overview of our financial and operational results in the second quarter. I will also provide an update on several regulatory initiatives. I'll then turn the call over to our CEO, Tony Alexander, to discuss our revised 2005 earnings and cash flow guidance, as well as our newly-introduced guidance for 2006. Information regarding both second quarter results and information on our new guidance was released to the investment community today in both a consolidated report to the financial community, and a separate letter to the investment community detailing our guidance information. If you have those handy is may be helpful to refer to both of those during today's call.

Let's get started with our second quarter results. Please note that we'll refer to earnings and cash flow basis results on both a -- on a non-GAAP basis and that reconciliations to results on a GAAP basis are available in the consolidated report. Additionally, the investor information page of our website contains non-GAAP to GAAP reconciliations for both earnings and cash flow measures.

Earnings on a GAAP basis in the second quarter of 2005 were $0.54 per share compared to $0.62 per share during the same quarter of 2004. Normalized non-GAAP earnings during the second quarter were $0.71 per share, excluding $0.17 per share of unusual items. These included a one-time charge of $72 million, or $0.22 per share resulting from the write off of deferred tax benefits that are not expected to be realized due to changes in Ohio's tax system that were enacted on June 30th. This charge was partially offset by a one-time benefit of $28 million, or $0.05 per share from the creation of a new regulatory asset associated with the JCP&L Phase 2 rate settlement. The normalized non-GAAP earnings of $0.71 per share compare very favorably to earnings on a normalized basis of $0.67 per share in the second quarter of last year.

The results for this quarter were at the top end of the Company's earnings guidance range and exceeded the analyst consensus estimate. The improvement in normalized earnings was in part driven by the continued strong performance of our generation fleet. Even though there were two nuclear outages in the second quarter of this year, versus none last year in the second quarter, we were still able to set a generation output record of 19.1 million megawatt hours for the quarter, bringing our year-to-date output to a record 37.9 million megawatt hours. While both the fossil and nuclear generating fleets are performing well, special notice should be given to our largest coal unit, the 2,360 megawatt Bruce Mansfield facility, which operated at an outstanding 97.4% capacity factor in the first half of this year.

Also, I wanted to mention that our famous Unit 2 recorded a special achieved during the quarter when it became the longest-running, single-turbine, steam-generating unit in history, surpassing the previous record of 819 days of continuous operation. And as of today, I believe that record run is up to 908 days.

So, truly, an outstanding performance. Other drivers for the positive financial performance during the quarter included a $0.07 per share increase in other electric gross margin resulting from higher generation sales and prices, as well as higher distribution deliveries; a $0.05 per share reduction in pension and other employee benefit costs; and part resulting from our voluntary $500 million contribution to the pension plan last year; a $0.04 per share benefit from lower financing costs, as a result of our continued debt reduction and the refinancing activities; a $0.02 per share increase in investment income from our corporate-owned life insurance; and a $0.01 per share reduction in fossil operating expenses, as a result of fewer planned outages.

Offsetting factors included a $0.09 per share increase in replacement power costs and a $0.06 per share increase in nuclear operating expenses, both attributable to the refueling outages at the Beaver Valley Unit 2 and Perry plants; and a $0.02 per share increase in depreciation and amortization expense, due to a higher Ohio transition cost to amortization and increased base depreciation. During the quarter we completed net redemptions of debt and preferred securities of $136 million, as well as $310 million of refinancings and repricings. These actions will reduce financing costs by $19 million this year.

Year-to-date, our net debt and preferred securities redemptions totaled $269 million, with mandatory redemptions of $332 million occurring in the second half of the year. We remain on track to achieve our targeted debt reduction of $600 million and an adjusted debt to total cap ratio of about 55% by year end. We're gratified that our continued improvement, both operationally and financially, was recently recognized by the rating agencies with both Standard & Poor's and Moody's recently changing their rating outlooks on FirstEnergy from stable to positive.

Finally, let me give you an update on our recent regulatory developments. On May 18th, the Public Utilities Commission of Ohio granted our request to defer for future recovery incremental transmission and ancillary service-related charges incurred as a participant in MISO. The PUCO's order applies to charges incurred from December 30th, 2004 to January 1st of 2006. The amount to be deferred will reflect actual incremental expenses including line losses and carrying charges. In a separate case pending before the PUCO, the Company has requested that these costs be recovered through a tariff rider that would be effective on January 1st, 2006 and adjusted each July 1st thereafter.

On July 22nd we filed a settlement stipulation with the various parties, including the Ohio Consumers' Council and the PUCO staff that provides for the requested recovery. And if the stipulation's approved by the PUCO, the amounts to be recovered in 2006 will be submitted to the PUCO on or before November 1st of this year. On May 25th, the New Jersey Board of Public Utilities approved stipulated settlements of two regulatory proceedings at our Jersey Central Power and Light subsidiary. These are expected to increase annual revenues by $51 million in annual earnings by $0.12 per share. For 2005 the impact is estimated at $0.11 per share, which includes the second quarter's one-time benefit of $0.05 per share that I mentioned previously.

On May 27th, our Ohio utility companies filed a request with the PUCO to recover increased fuel costs beginning January 1st of 2006, as permitted under the Rate Stabilization Plan. If approved, this request will increase 2006 revenues by about $93 million. The PUCO has established a procedural schedule with Company testimony due by September 8th and evidentiary hearings scheduled to begin on October 4th.

Also in May, our Ohio utilities companies and Penn Power, as required under their approved restructuring plans, entered into agreement to transfer their generating assets to FirstEnergy Nuclear Generation Corp, and FirstEnergy Generation Corp. These planned interests being transferred, exclude interests of the utilities in certain of the plants, subject to sale lease-back arrangements with unaffiliated third parties. The Companies are seeking various regulatory authorizations, and expect to transfer -- expect to finalize the transfers by year-end.

I'll now turn the call over to Tony Alexander for the pleasant task of discussing our revised earnings and cash flow guidance for 2005, as well as our newly-established guidance for 2006. Tony?

Thanks, Rich. And good afternoon, everyone. I'm glad you could join us today. Given our strong operational and financial performance in the first half of the year, as well as our ability to resolve certain regulatory issues that Rich described, we're in a position today to increase our 2005 earnings guidance from $2.70 to $2.85 per share to the range of $2.85 to $3.00 per share, or about a 5% increase, excluding unusual items. Our initial 2005 earnings guidance reflected the impact of the three planned nuclear outages scheduled for the first two quarters of this year. However, the Perry plant experienced a forced outage in January, and its refueling outage was extended beyond our plan. These two outages resulted in a $0.13 per share earnings deficiency that we had to overcome just to stay on track with our initial earnings guidance. While we're able to offset that negative variance and are now also increasing our guidance by $0.15 per share.

There are four main reasons why we're able to accomplish this. First, the outstanding performance of our generation fleet was a major factor in mitigating the impact of the Perry outage. Second, we received regulatory orders in Ohio and New Jersey that are providing us with more timely recovery of our costs. Third, we've successfully reduced our operating expenses, as we looked hard at all available opportunities to offset the impact of the planned outages. And, finally, our expense for employee benefits and fossil depreciation have been lower than anticipated when our guidance was initially set.

Our ability to increase our earnings guidance in the face of these significant plant outages speaks well for our Company. I'm pleased with the efforts of management and employees to step up and find ways to improve our original earnings outlook. And I'm pleased with the performance of the Perry plant since it returned to service. We're also increasing our 2005 cash generation guidance from 560 million to 620 million. This continues to reflect non-cash from operating activities -- or, excuse me, net cash from operating activities, the GAAP measure, at a level in excess of $2 billion.

Our increase in cash guidance is largely driven by a prepayment program called Energy For Education. Certain school districts that are members of the Ohio Schools Council prepaid their electric bills in return for discounts on their service over the next three years. We completed a similar program several years ago. This program will have a net positive cash impact of $220 million this year. Our revised cash guidance continues to support our targeted debt retirement of $600 million this year. And we remain on track to accomplish that.

We're also establishing earnings and cash flow guidance for 2006. Our earnings guidance is $3.40 to $3.60 per share, excluding unusual items. This increase over our revised 2005 guidance reflects the positive impact of various regulatory and operating items. On the regulatory front, the Ohio Rate Stabilization Plan will benefit 2006 earnings through a reduction in transition cost amortization of $0.76 per share, which is offset in part by the loss of shopping credit deferrals estimated at $0.26 per share. We also have the full impact -- the full-year impact of the recent Jersey Central rate settlements incorporated into our 2006 guidance.

In terms of operations, we expect continued T&D delivery growth and continued improvement in our generation margin. Our financing costs will also continued to reflect the benefit of our debt retirement and refinancing activities. These cost reductions will be partially offset by increases in employee benefit costs, higher depreciation expenses, and other O&M increases. Our guidance for cash generation in 2006 is 300 to $400 million. This reflects 2.1 billion of net cash from operating activities, up slightly from our 2005 guidance level. Our guidance incorporates projected capital expenditures of between 1 billion and $1.1 billion in 2006. We will refine and finalize our capital program during the fall and provide you with more information at that later this year.

Additionally, cash generation in excess of our 2005 or 2006 guidance could result from the release of approximately $120 million of collateral when we regain our investment grade rating for senior unsecured debt from Standard & Poor's, and also through the anticipated securitization of JCP&L of up to $275 million. The timing of these events, however, is uncertain. With the completion of our debt reduction program this year, we plan to deploy our free cash to achieve equity returns through stock repurchases or reinvestment in our business. Additional details on our earnings and cash flow guidance is available in our letter to the investment community that we issued earlier today. And I urge you -- to refer to this.

Now in closing, let me say that I'm very pleased with our operational and financial performance in the first half of the year. I remain excited about our prospects for going forward. We significantly improved our financial strength and flexibility, through the retirement of more than $3 billion of debt over the past few years. We've also continued to demonstrate favorable levels of performance in both our generation and wires businesses. This trend is consistent with our vision of FirstEnergy as a top performer that consistently meets or exceeds the expectations of our customers and our investors.

We remain focused on our five key objectives this year. That are to -- that are, one, maximize the contribution from our generation business; two, further improve our reliability and customer service; three, enhance our financial strength and flexibility; four, restore our investment grade credit rating for senior unsecured debt at Standard & Poor's; and, five, deliver consistent financial and operational results. We've made significant progress in all of these objectives this year, and I'm confident that we will continue to attain even higher levels of performance to drive additional values for our investors.

I appreciate your time. And thank you for joining us this afternoon. I'll now ask the operator to open the call to questions from analysts.

Thank you, sir. [OPERATOR INSTRUCTIONS.] Our first question is coming from Kit Konolige of Morgan Stanley.

Good afternoon. Congratulations.

Thank you, Kit.

Just a couple of specific questions about, I guess, the '06 guidance. It looks like from the footnote here that you are including essentially all of the requested fuel recovery through the RSP. Is that a fair way to look at this?

It is fair. We don't know whether that will be the exact outcome. But it's -- if we are successful this would establish deferral treatment for our fuel costs next year. So those would be able to be deferred for future recovery.

And -- so the -- wait. Now, I'm sorry. Say that again. So you -- you expect just a deferral order?

Yes. I did not say that clearly, Kit. I'm going to ask Harvey to give a better explanation, a more clear explanation on that.

Kit, we made a filing for a rider and, of course, the rider would be a cash increase, to the extent our fuel costs that incurred by the utilities are different than what we're recovering in the rider.

That difference would get deferred.

Right.

Then, recovered in subsequent year.

I have to have Harvey speak for me, Kit, to make sure I don't get things wrong. But that's --

Fair enough. So, as opposed to a -- in other words, you're thinking this would not be an outcome like, quote, unquote, normal rate case, where there would typically be a contest over what to include, and you feel comfortable including the full amount of what you've requested?

As you know this isn't a -- a traditional rate case. I mean, the rate plan does call for us to have the ability to recover these costs and the increased fuel costs basically are what they are. I mean, and we've filed evidence to that amount.

Yes, this is Tony. This -- we have a pretty straight-forward calculation that we embedded inside the Rate Stabilization Plan. And it truly is just a comparison of actual costs incurred in the estimated period to the -- to the real cost that we incurred as of 2002. I'm not anticipating any significant deviation from the filing that we made. Not unlike, for years under fuel adjustment clauses we anticipated and basically received 100% of the increased costs.

Now, does this filing get a staff recommendation? Do you have an ALJ? And is it subject to a settlement, as you've been able to achieve in the other -- in these other recent cases?

Kit, I'm not sure whether or not we will see a staff recommendation or not. Matter of fact, if I recall the fuel adjustment proceedings, I'm not sure there was one in those. This doesn't even follow that pattern. The way the stipulation was originally set up and the plan itself, I'm not even sure that we'll have hearings. But they could be -- they could be required, just for verification of the numbers.

Fair enough. Okay. I'll pass the baton at this point. Thank you.

Thank you, Kit.

Thank you. Our next question is coming from Greg Gordon of Smith Barney.

Thank you. One question on earnings and one on cash flow. On the earnings slide, there's no explicit accounting for the potential for share buy backs in the '06 guidance, is there?

No, there is not. You're right, Greg.

Thanks. And, then, another issue, your -- the operating leverage you guys have been exhibiting since the fourth quarter of '04 has been quite good, even taking into account, as you observed in your presentation, the extended outage you've had at Perry?

Yes.

There also doesn't seem to be anything factored into in 2006 for the potential for you guys to see a significant reduction in nuclear outage days. Is that something that you have the potential for in '06?

As you know, there will also be three nuclear outages next year, same as there were in 2005. If you look at the total, I guess, megawatt hour outage days next year, we'll be slightly less than -- it's expected to be slightly less next year, even though we have the extended outage at Beaver Valley 1 to replace the steam generator and the vessel head, itself. But our estimations for the benefit of the difference in the refuelings are -- is incorporated in the guidance we gave you today.

Okay. Then on cash flow, did you explain this prepayment program? Because it looks like you assume it increases your cash by a net 220 this year. But then flip-flops to a -- reduces your cash flow next year by 260. So what are the -- how are the economics of that plan work? Just looking at that map, it looks like it's pretty uneconomic for you guys.

Well, first, let me tell you what it is. And we have done this -- a similar prepayment program in the past. The Ohio Schools Council has the ability to issue very low cost, tax-exempt debt, so an ability for them to gather their member school districts together and offer us a program to prepay their electric bills, in return for a discount is a win-win situation for them. That they get a little lower rates and our ability -- and given ability to use their tax-except financing. And it is a plus for us because we get, obviously, the prepayment and the cash up front. So it's a similar program we've done that we think is beneficial for us and offers a service to schools who are participating in the program. So that's the first part of your question.

The second part of your question was really -- What's the difference between the $220 -- sorry, the $220 million number and the $260 million number? Let me try to walk you through that quickly here, hopefully won't confuse the issue. If you look at our 2005 initial cash flow guidance versus our 2005 revised cash flow guidance that we're giving today, the Ohio schools program impact there is $220 million. And that's really comprised of about, roughly, $240 million of cash that we received at closing, less about $20 million of foregone revenues during the second half of '05. So that explains that number.

The second number really jumps us from '05 to '06 guidance and that's that $260 million number that you mentioned. That's really the cash received at closing plus about $18 million of revenues from those participating schools that we had collected during the first half of '05. So it's the delta between those. Does that make sense, Greg?

Yes, I think so. And, then, one last question. Nuclear fabrication costs.

Yes.

Look like they roughly -- they're doubling from '04 to '06. Can you tell us, is that -- are you just getting -- paying significantly higher prices for uranium? What's the key driver there?

That number bounces around from year to year based -- it really follows the fuel fabrication schedule which is ultimately tied to the refueling outages and so forth. So that kind of swing year-over-year. If you look back in past years, you'll see that's not an atypical delta year-over-year. It just tends to go up and down, up and down.

Okay. Thanks, guys.

Thank you, Greg.

Thank you. Our next question is coming from Steve Fleishman from Merrill Lynch.

Hello, Steve.

Hi, guys. First question is on the transfer filing for the FirstEnergy generation.

Okay.

What -- what approvals are required to finalize that?

Various approvals. I don't know if I can detail all of them, but there will be various approvals. And, for instance, we will also be transferring the pollutions [inaudible] that out of the operating companies over to the non-regulated generation affiliates. So that requires approval of the various authority, so forth. So there are a number of approvals [inaudible].

Have you had indication from other parties that they will oppose this?

No. Not that I'm aware of.

None that I'm aware of, Steve. This is Tony. None that I'm aware of, but I'm not in that case on a day-to-day basis. But I haven't heard of any significant opposition from the outside parties.

Okay. Secondly, on the question of use of cash in the 2006 guidance you provided, what did you do with the free cash? I know some of that's got to go with this prepayment, I guess. But what are you assuming the rest of the cash is used to do?

The free cash in 2006, Steve? Are you saying the 280 to 380 we're talking about as free cash flow?

That's correct.

How did we reflect that in our earnings guidance? Is that your question?

That's correct.

Well, as we mentioned before, we did not reflect any sort of share purchases. As Tony's mentioned, that's one of the things we're continue to -- going to continue to consider for free cash flow next year, as well as reinvestment in the business to earn an equity-like return. So we did not make any specific assumptions along those lines in terms of how that free cash would impact earnings in 2006. So those are things we will continue to look at as we go through this year and into '06.

Okay. And just on the topic of the '06 guidance, I'm curious, for many years you guys have given the full-year guidance at your meeting late in the year, ahead of the year.

Yes.

And just curious on the timing of changing that and doing it now.

Why did we do it now? You're right. That's been, I guess, our tradition, if you will, to give guidance at the December, or end of the year analyst meeting. We've been aware that, certainly, other companies have done that earlier in the year, and as part of our efforts to just help improve transparency and help people understand year-over-year drivers we thought it made sense to do it earlier this year. So that's really the genesis behind that change. Certainly, we heard a lot from folks that they were looking for guidance earlier than we had been giving it, and we're trying to be responsive to that.

Okay. No, That's great. Okay. Thank you.

Thanks, Steve.

Thank you. Our next question is coming from Ashar Khan of SAC Capital.

Good afternoon.

How are you?

I'm pretty good. Congratulations.

Thank you.

Rich, as I look at another part in the press release said 3 to 4% growth beyond '06, so I guess '06 sets a new benchmark from which future growth is factored in. Is that 3 to 4% pretty much each year, or is there -- could there be a changing that could be higher one year versus the other?

Yes, we really express that as more of an intermediate- to long-term, sort of annualized earnings growth rate. So could there be years where it's somewhat lower or higher? There could be. We think that's a fair representation over the foreseeable future of how our earnings growth will trend as well, though.

What have you assumed for the '09 scenario in that? Is there any upside built in that, or no, as to what happens in '09?

If you can tell me what happens in '09 I can tell you what the upside could be. Obviously, that's an issue that remains to be debated, I guess, here in Ohio when the market development period ends and as the law is written, now currently, stated that customers would go to market at that point in time. So it depends what happens with that and what the market prices are and so forth. But we are comfortable going out with that earnings guidance over the intermediate-term as being appropriate.

Okay. And, then, just going to this year's earnings guidance, as you mentioned in your press release, the generation the fossil plant units have been having an exceptional, I guess, the first half. Why isn't there any positive shown for that in the updated guidance for this year? I mean, I don't see it as any one of the factors for the better performance at the fossil facilities from your old guidance to the new guidance.

For '05, if you happen to have that box that's in the released handy, Ashar, there's an item in there that's actually the second item that says operating expenses. It's $0.05 positive benefit. And that does reflect some -- the continued good performance of our generation fleet. We didn't specifically note it as such, but that is recognized in that item.

Okay. And if I'm correct, you guys are pretty much, as you look forward, the cost of credit, submission credits, and things like that, you're pretty much hedged. And those things are not going to have much influence going forward in your generation cost. Is that a fair point?

I mean, we're well hedged for emission allowances and for our fuel costs. We've explained there are cost increase that will occur under our fuel contracts under the reopeners. They are bounded, obviously, those costs get reflected in what we filed for the fuel case in Ohio, and so forth.

So it's a pass through, correct?

Yes.

And if I can end up, I might have missed this somewhere, as part of your JCP&L settlement, you are allowed to secure ties and other trench. Where does that flow in in the cash flow statement?

It's not included in the guidance. That would -- if we do that, that would be incremental to the guidance, Ashar.

Okay. How much is that?

Because the timing -- because the timing is uncertain on that, we didn't want to include it in the guidance.

But you are allowed to do it, right? That was a part of the settlement. You get that -- if I'm right, it's about another 200 million or so?

Yes -- yes, more like 270, 280. But the timing of that, is still, from our perspective, a little uncertain. So that's why we didn't carve it in.

Okay. But, Rich, if I understand it, could it be either this year or early next year, right?

Yes.

So those are 270 million of extra cash which is not in the guidance.

Yes. Right around that.

Up to.

Up to.

Thank you.

It's up to that amount.

Thank you.

Thanks, Ashar.

Thank you. Our next question is coming from Paul Ridzon from Key/McDonald.

Hello, Paul.

Afternoon. You -- you realizing 220 net from this school program, but that full amount, it doesn't seem to be reflected in the new cash flow guidance. Was there slippage somewhere? Was that Perry?

In terms of the cash flow guidance? We can -- if you have a sheet handy, the box that shows that reconciliation, that might be handy to look at. We're starting off our 2005 revised estimated free cash flow of 535. And you look -- we said our capital program will be between 1 billion and 1.1 billion. Nuclear fuel fabrication costs that we referred to in an earlier question, that has an $80 million negative impact.

Talking about '05.

Oh, '05, I'm sorry, Paul. I'm sorry. Okay. Let's go through '05 then. There is a couple things, the Ohio School Council, as you mentioned $220 million positive increase. The Perry extended outage earlier this year had a negative impact of about $50 million. Capital is probably going to come in around $20 million higher than we had previously estimated for various reasons. We have a trust draw down on a Penelec NUG non-utility generator trust that we expect it to get that's going to be delayed until 2006. That's another $20 million. And then there is about $20 million of miscellaneous costs as well, which put us at about the 535. So not 100% of the benefit of the school's prepayment flows through because of those items.

What were the facilities that had life extensions?

I'm sorry?

Which facilities had life extensions.

Oh, are you talking about the fossil plants?

Yes, Paul, we did a study of our entire fossil fleet and that's the end result of a composite of all of our units.

And it sounded like -- I'm not sure if I detected a slight difference, but use of capital seems, maybe, to be directed less towards buy back? It sounds like more emphasis on utility like investment. Or am I just reading too much into your statements?

Yes, I think you are. You may be reading too much into our statements, Paul.

Okay. Thank you.

Thank you.

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

Hello, Paul.

Good morning, guys -- or good afternoon, how are you?

Good, how are you doing?

All right. Listen, the pension and other employee benefits you guys raised your guidance or your expectations on that. I was wondering what caused you guys to do that? What was the driver there?

Are you talking about the impact in '05?

Yes, the impact in '05. From 270 to 285, you guys -- I mean, a lot of these numbers I sort of -- I expected, but the $0.05 from pension and other employee benefits, the increase from that. I was just wondering what's made that get better?

Well, primarily it's just a delta from what we'd included in our original guidance at the analyst meeting last December versus where those numbers for pension and OPEB landed this year. That's the primary driver. And, also, some of our employee health costs have been slightly less than our anticipation when we gave that guidance. So that's what's really driving that, Paul.

Right. But in other words, so it's basically the healthcare costs are a lot less than what you guys had expected when you guys gave the guidance at the end of '04?

Healthcare costs are less. And FAS 86, FAS 106 expenses are lower than what we had thought they were going to be when we gave the guidance in December.

Okay.

You have to wait until year end to find out what your actual asset returns and what your actual discount rate is. So we made up some progress since we gave that guidance.

Okay. And then the fossil fleet, the fossil fleet depreciation, how much does that help you guys out, again?

Year-to-date it's been about $0.03. It was a penny in the second quarter. And we expect it will probably be around a nickel for the year.

Okay. And what drove you guys to do -- what was the impetus to -- behind having the accountants look at that?

Well, just making sure that the depreciation lines accurately reflected the operating lines of those units.

Okay. So there wasn't any -- ?

[Indiscernible] an independent engineering firm come in and confirm that for us.

Okay. But there wasn't any extension, or life extension or anything that was done, any mechanical extension. It was just a -- an accounting change, is that correct?

That's correct, Paul. Yes, it is.

Okay. Okay. And, just, finally, with this Energy in Education II you guys outlined the cash flow impact. Is there any net income impact associated with this or is it purely a cash flow element, other than, of course, the use of cash in the near term?

That's really it, Paul. That's really the earnings impact from it.

Okay. Thanks a lot.

Thank you.

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

Hi, Hugh.

Hi. How are you?

Good. How are you doing?

Good quarter here. I just had two quick questions. First, the transfer of your generation assets to FirstEnergy Nuclear Generation and FirstEnergy Generation Corp., will that materially change the regulatory authority of the PUCO? Will the transfer policies ask us to be treated as exempt wholesale generators under FERC authority, or does the PUCO still maintain some say so over their rates?

Well, we have approval on the fossil assets to move those over and -- to an unregulated affiliate and become and accept -- an exempt wholesale generator. So for the fossil units, that's the path. The nuclear units at this point in time it appears may not be and EWG, but will, more likely, remain a utility, if you will. So a little bit of a differentiation between the two fleets.

Yes, but, Hugh you need -- you need to think of this in terms of when -- when we went to put in place the transition plans back in 2000, all of the kilowatt hours belong to the competitive side of the business -- FirstEnergy Solutions. They no longer belong to the utility. And Solutions is the one that's financing the improvements and -- of investment and everything else. So the -- while the assets still sit on the books of the utilities, the output from the plant is basically owned by the competitive side of the house. Now, all we're doing is lining up the asset with who owns the kilowatt hours.

Okay. So what you're saying, I guess, is the fact that the legal ownership of the nuclear assets remains with the utilities is not material. The sales from those assets are unregulated because they belong to FirstEnergy Solutions?

That's kind of how I'd look at it.

Okay. Thank you.

I'm not going to tell you exactly what everybody else looks at it, but that's kind of how I look at it.

Okay. The second question I had, there's a statement on the first page of the release that the replacement power costs for refueling outages at Beaver Valley and Perry reduced electric gross margin by $0.09 per share. When I flip to the consolidated statement of income, I notice that purchased power is actually $250 million lower this year than last, whereas, fuel consumption is $89 million higher. Can you explain to me what caused the decline in purchased power and the increase in fuel consumption?

Hugh, this is Harvey Wagner. We had disclosed previously about the way we're recording the purchase and sale transactions in the PJM market. Beginning in 2005, whenever Beaver Valley's -- the Beaver Valley plant was devoted to the PJM marketplace we changed the method of recording every discrete transaction to recording every transaction on a net position basis hour by hour. So there was a -- you'll also notice a similar reduction in wholesale sales. And I think the number was probably around $250 million. I'd have to check for the first half of the year. So that reduced purchased power expenses, and it reduced wholesale sales revenues, comparatively when you're looking at last year.

Okay. So that is just a -- an accounting change. That doesn't represent an increase in purchased power.

That's correct.

And you guys don't disclose the megawatts, I don't believe, until the 10-Q comes out, is that right? You don't disclose the megawatt hour purchases and generations and stuff like that?

That's correct.

That's true.

Okay. Thank you, very much. I appreciate it.

Thank you, Hugh.

Thank you. Our next question is coming from David Frank of Pequot Capital.

Yes, hi. Good afternoon.

Hey, David.

Hi. Rich, does your '06 guidance -- maybe I missed this -- does that assume continued deferral of MISO expenses going forward?

Yes. No?

No.

No.

David, we're going to have new transmission tariffs that would go into effect on January of '06, and it's similar to a fuel clause. It's going to be a rider mechanism. So to the extent that the transmission expenses are higher or lower, they would be deferred.

Okay. That's automatic?

Yes.

Yes.

Okay.

[Inaudible.]

Right.

Yes.

Right.

All right. How many megawatt hours are you assuming FE generates in the 2006 earnings forecast, roughly?

Megawatt hours? We're expecting that it would be ahead of this year's record performance. I don't know exactly how many.

About 80.

80 million? Something on that magnitude.

Okay. Around 80?

Yes.

And are you currently assuming that shopping stays relatively level in Pennsylvania and Ohio with current levels among customer classes for '06?

We're -- at this point, David, we're assuming that it's going to be somewhat lower than it is in '05.

So a slight decrease in shopping?

That's our assumption.

In Ohio, Pennsylvania is so small now it's diminimus anyway.

It doesn't matter.

Okay. And are you assuming today's forward power curves for PJM and MISO when you make your 2006 earnings guidance for wholesale sales and purchased power expense?

Yes. Yes.

Okay. And excluding Beaver Valley and the NUG, how much of your open short in Pennsylvania have you hedged out beyond 2006, say 2007 to 2010?

Well, there's two answers. One is through 2008 and one is 2009 and 2010. The reason that differentiation is important is, of course, because that's when the transition period in Ohio and the power obligation is scheduled to go away. Through the 2008 period, I don't know the most recent number, but our position is largely covered in Pennsylvania through 2008, much less so after 2008 because, at that point in time, the Ohio generating assets are expected to be freed up to be serve load wherever we wish it to be served.

All right. So you would just assume you could -- you would move the megawatt hours from Ohio to Pennsylvania? And physically, is that possible today if you had the power available?

Physically -- David, physically or financially.

Right.

Okay. I got you.

It doesn't make a difference how they get there.

It gets you to the same point, right?

Right. Okay. I understand. All right. Thank you, very much, guys.

Thanks, David.

Thank you. Our next question is coming from Terran Miller of UBS.

Hi, Terran.

Good morning, Rich, how are you -- good afternoon, Rich, excuse me.

Good. How are you doing?

I'm fine. Thank you. In your reconciliation of cash flow from the old guidance to the new guidance, you did not discuss the deferred income tax and ITC net changes, which look like they're about 225 million -- $215 million. I was wondering if you could go through those numbers for us?

Harvey is going answer that one, Terran.

You are looking at the change from 2005 to 2006?

No 2005, old, to 2005, new.

Okay.

Hang on one second.

In our actual numbers for 2005, our revised numbers includes the $72 million of the Ohio tax -- deferred tax write off.

Okay.

Okay. Virtually all of the rest of that is ITC amortization. They are really very, very other -- really, virtually no other changes to the estimate in the cash flow guidance.

Okay. Thank you.

Thanks, Terran. Without people on hold --

Thank you. Our next --

I'm sorry.

Next question is coming from Paul Fremont of Jefferies.

Hi, Paul.

Good afternoon, and congratulations. A quick question on -- well, two quick questions. One having to do with leverage. What is the assumed ratio of debt to total cap in your 2006 number? And without a share purchase wouldn't that ratio tend to be improving significantly over time?

What our plan is, Paul, is this year we will complete our debt retirement program that we've been working on so hard for the last couple years. And our goal and our belief is that by the end of this year, on an adjusted basis as the rating agencies look at it, debt to total cap will be around 54%, which is, if you use SMBP benchmarks, for instance, compared against that, that's pretty much right in the middle of the Triple B category business, position 6. What we'll be doing, going forward, is really not reducing debt any further, but we will be really restructuring our debt, if you will, by reducing holding Company debt, of which we still have $4 billion outstanding, reducing debt at the holding Company, pushing it down and increasing debt at the operating Company, but not changing the overall debt structure. So our expectation is that that will remain around that 54% debt to total cap going forward, with less debt at the holding Company, more debt at the operating Companies.

And the other question that I have is with respect to the timing of the collection of RTCs. To the extent that the timing moves or changes from the original projection, should we assume that that's EPS neutral because the -- there would likely be offsetting amortization arising from the new deferrals that you're booking?

Paul, there wouldn't be amortization from new deferrals, but the amortization would track with the change in the recovery pattern.

So the timing -- so the timing of RTC -- of the RTC runoff should be earnings neutral then?

That's correct.

Yes. Yes, I think that's fair.

Thank you.

Thanks, Paul. Well, we've had people on the line for 50 minutes, so why don't we take one more call and, then, if there's any additional questions which we haven't had a chance to answer, if there's additional follow-up, certainly, we'll be glad to do that after the call. So why don't we take our last question?

Thank you, sir. The final question will be coming from Ben Sung of Luminous Management.

Hello, Ben.

Hi, congratulations on the quarter.

Thank you.

Two quick questions, actually, for you. You alluded to, I guess, the potential to buy back shares or also reinvestment into your Company. Is -- are those investments, do you envision them being more on the generation or on the wires or can you sort of elaborate on that a little bit?

Right now, we've talked about our program to reinvest, certainly, in our regulated businesses to improve reliability, and that will continue next year. We have in the past, we've looked for generating assets, particularly, in PJM, that could be beneficial for us. We've not found anything. I guess my expectation is we're -- we're probably not going to see anything in that area for the time being. So net cash would probably be, when we look at those two alternatives, anyhow, being reinvested in the regulated portion of the business, and also available for return to shareholders through a share rebuy back and increased dividends.

Okay. And the other question is on RPM. I mean, I know it's sort of somewhat early on in the process there, but do you have any -- any ideas on how that could affect you financially?

There's been an evolution, and Ben's question refers to this RPM pricing model in PJM to encourage additional investment and generation, and that proposal has continued to evolve since it was first floated several months ago. And at the time that came out, the initial proposal, we thought, had some pretty significant flaws in it. And we didn't really think it would encourage new generation to be built. I think that the folks continue to work on that to see if there's something that makes more sense, whether it should be regional versus across all of PJM, all sorts of other -- other issues. So we're continuing to track that. We do not think the initial version of it would have achieved the stated objective. But we'll continue to track that and see where we go.

Do you envision -- the way you understand it, I mean, is that -- if that were to be implemented, is the additional cost something that should be passed throughable to the customers in Pennsylvania?

No, it wouldn't be passed through to customers. From what we understand at this point, the biggest impact in Pennsylvania, and this could change over time, but it would appear the biggest impacts in pricing would be in regions, probably in the eastern part of PJM, as opposed to some of the areas in which we operate.

Great. Thank you.

Well, thank you, Ben. I appreciate your questions. I appreciate everybody's time and interest, today. Obviously, this was a good day, a happy day for FirstEnergy. We're glad to be able to increase our guidance for '05 and also provide our initial guidance for 2006. And, certainly Terry, Kurt, the rest of the IR staff, and the rest of us are available to answer your questions after the call. So we appreciate everyone's time and attention today, and hope everybody has a good day. Thank you.

Thank you.

Thank you. This does conclude's today's teleconference. You may disconnect your lines at this time and have a wonderful day. Thank you.