第一能源 (FE) 2006 Q3 法說會逐字稿

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. 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 the consolidated reports 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 various non-GAAP financial measures we will be referring to today are also contained in that report as well as on the investor information section of our website, which was recently redesigned to enhance its content and capability. We encourage you to check out the new site at www.firstenergycorp.com/IR. 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, Vice President and Treasurer; and Ron Seeholzer, Vice President of Investor Relations. I'll now turn the call over to Rich Marsh.

Thank you, Kurt. Good afternoon, everyone, thanks for being with us today. I'll start our call today by providing an overview of our third quarter earnings results and financial activities, then I'll turn the call over to Tony to provide updates on our operational performance and regulatory initiatives. Information regarding our third quarter results was provided earlier today in our consolidated reports to the financial community and it might be helpful to refer to that during the call.

Let's get started with our third quarter financial results. We'll refer to earnings and cash flow results on a non-GAAP basis and reconciliations to the comparable GAAP financial measures are available in the consolidated report as well as in the investor information section on our website. Earnings on a GAAP basis in the third quarter of 2006 were $1.41 per share compared to GAAP earnings of $1.01 per share in the third quarter of 2005. Normalized non-GAAP earnings in the third quarter of this year were $1.42 per share, excluding the net affect of two unusual items that reduced earnings by $0.01 per share.

The first unusual item involved a pretax charge of $10 million or $0.02 per share related to an August 18, Pennsylvania Public Utility Commission order requiring Met-Ed and Penelec to discontinue an accounting modification for deferred power costs implemented at the end of last year. The amount normalized relates to those costs deferred in 2005. The order indicated that the companies could petition the commission to implement the desired accounting change and we've already done that.

The second unusual item relates to a $0.01 per share after-tax benefit from the sale and impairment of our noncore assets in our FE facilities group. This quarter's non-GAAP earnings of $1.42 compare favorably to the normalized non-GAAP earnings of $1.04 per share in the same period last year. Similar to the results in the first half of the year, the improvement was largely driven by the impacts of our Ohio rate plans, deferral of PJM Transmission expenses, and continued favorable operational performance. Specifically, the contributions to earnings from the Ohio rate plans compared to the third quarter of last year include reduction in transition costs, the amortization up $0.24 per share primarily reflecting the end of generation transition cost recovery in 2005, a deferral of $0.07 per share of costs related to distribution reliability spending, and a deferral of $0.08 per share of incremental fuel expenses.

These contributions were partially offset by a $0.09 per share reduction in earnings related to the rate stabilization charge, a discount provided to our Ohio shopping customers. Another key contributor during the quarter related to the deferral of PJM Transmission costs that are not being currently recovered from our customers and that increased earnings by $0.10 per share. Other positive drivers included a $0.07 per share benefit from reduced net transmission costs primarily due to lower congestion in the PJM market and higher MISO revenues, a $0.03 per share reduction in fuel and related expenses, including coal transportation and emission allowance costs, a $0.01 per share reduction in purchase power costs, a $0.04 per share change in estimated taxes payable, related primarily to the recently filed 2005 federal income tax return, and the continuing phaseout of the Ohio income tax; and a $0.02 per share benefit from lower energy delivery expenses and lower nonelectric commodity transactions.

In addition, the reduction in shares outstanding from the accelerated share repurchase of 10.6 million shares in August enhanced earnings by $0.02 per share. Factors that partially offset these favorable impacts included a $0.05 per share decline in distribution delivery revenue as cooing degree days were 20% lower than during the same period last year, a $0.09 per share decrease in generation revenues driven primarily by lower wholesale market prices and lower generation sales, a $0.04 per share net reduction in investment income from our nuclear decommissioning trusts and corporate owned life insurance, and a $0.04 per share increase in financing costs primarily attributable to higher short term borrowings to fund the accelerated share repurchase, higher variable interest rates, and the absence of gains on reacquired debt that were realized during the third quarter of 2005. Total generation sales declined 1% to the third quarter of last year as an increase in retail sales was more than offset by a reduction in wholesale sales. This change in our generation sales mix is related to the return of shopping customers to our Ohio utilities at the end of last year, following departure of some competitive generation providers. This reduced shopping at our Ohio utilities from 38% in the third quarter of last year to 17% this year.

Let me now touch on a few financing-related items. Two key activities in the quarter included the implementation of a new five-year credit facility and the accelerated share repurchase program. In August, we entered into a new five-year syndicated credit facility totaling $2.75 billion dollars. This replaced our prior $2 billion facility and provides a 10 basis point annual savings on facilities related borrowing costs. Under the new arrangement, we can request an increase in total commitments to a maximum of $3.25 billion dollars as well as two separate one-year extension options that can take the term out to 2013. This was a good opportunity for us to take advantage of strong bank markets to improve our liquidity and financial flexibility.

The other significant development during the quarter from the financial perspective was the August 10, repurchase of 10.6 million shares or about 3.2% of our outstanding common stock through an accelerated share repurchase program with an affiliate of JP Morgan Securities. The initial purchase price under the ASR was $56.44 per share or $600 million in total. Under the agreement, the final purchase price will be adjusted to reflect the affiliate's ultimate cost to acquire the shares over a period of up to seven months. The share repurchase was initially funded with short-term debt.

Looking toward the fourth quarter, we'll continue to execute our financing plan that's largely focused on capital structure management. This will include reducing long-term debt at the holding company as outstanding issues mature, including the $600 million of remaining 5.5% FirstEnergy senior notes that come due in November and the issuance of additional debt at certain of our operating utilities to achieve capital structures that are appropriate in a regulatory context. On a consolidated basis, we expect to end the year with an adjusted debt to capital ration of about 56 to 57% and our intent going forward is to maintain debt in that approximate range, consistent with our commitment to a solid investment grade credit profile. Now I'll turn the call over to Tony to provide updates on operational and regulatory matters and also to address the revision in our annual earnings guidance.

Thanks for joining us. During the quarter, our generating units continued to demonstrate strong performance. We established a new year-to-date generation output record of 61.9 million megawatt hours and we remain on track to establish a new annual output record this year of approximately 82 million megawatt hours. We're also making good progress in realizing the full potential of our assets through power uprates at several of our units.

In August, Beaver Valley Unit 1 increased its net capability by 3% from 821 to 846 megawatts. This was the first phase of its NRC approved 8% uprate program. The remainder of the 8% uprate is expected to be completed in early 2007. At Beaver Valley Unit 2, modifications are also being made during the current refueling outage to prepare that unit for an 8% increase in generation capacity. When this unit returns to service, an initial 3% uprate is expected to take affect with the balance to be implemented during the next refueling outage in 2008.

Earlier this year, we also achieved a 14 megawatt increase at the Davis-Besse nuclear plant and on the fossil side, we are in the process of implementing a 50 megawatt uprate at Unit 2 of our Bruce Mansfield plant, similar to the 50 megawatt uprate we accomplished at Unit 1 during the fourth quarter of last year.

Moving on to the regulatory matters, I'll start with an update on our metropolitan Edison and Pennsylvania Electric transition plan cases. With the completion of evidentiary hearings in August and the legal briefing process completed earlier this month, these cases are now before the administrative law judge. We expect the ALJ recommended decision by November 8, following which the parties will have an opportunity to file exceptions to that recommendation. We expect to receive a final decision from the Pennsylvania Public Utility Commission by mid-January of next year.

As part of Met-Ed and Penelec's transition cases including the need to procure more of their provider of last resort supply for the market, the Company secured approximately 950 megawatts of supply for the period December 1, 2006, through December 31, 2008, under a competitive request for proposal. Recovery of the incremental costs of this supply is one component of the transition plan cases. The prices secured in the RFP were slightly lower than what we estimated in those transition cases. And accordingly, if our plan is approved, the lower -- those lower than expected supply costs will be passed through to customers.

Turning to our Pennsylvania Power subsidiary, last week the Pennsylvania Public Utility Commission certified the results of the competitive RFP process that will complete the transition to market-based generation supply for that company. The RFP secured the provider of last resort supply for the period January 1, 2007, through March 31, 2008, for customers who don't choose alternative suppliers.

On the New Jersey regulatory front, an evidentiary hearing was held in September regarding JC P&L's request to recover 165 million of above market nonutility generator costs incurred from August 1, 2003, through December 31, 2005. If approved, this would increase cash flow but would be neutral to earnings. Settlement conferences were held earlier this month and the main briefs are scheduled to be filed on October 30. Reply briefs are scheduled to be filed on November 20, and an order by the New Jersey Board is expected early next year.

In closing I believe the third quarter represented another solid performance for FirstEnergy, both financially and operationally. This result enables us to revise our 2006 normalized non-GAAP earnings guidance to $3.75 to $3.85 per share, which is at the top half of our prior guidance of $3.65 to $3.85 per share. We're also maintaining our non-GAAP cash generation guidance at 460 million after capital expenditures and common dividends.

Going forward, we'll continue to maintain our focus on realizing the full potential of our asset base, efficiently reinvesting in the business to enhance system reliability, achieving timely regulatory recovery of our costs, and effectively managing the transition to competitive generation markets. I appreciate your time and interest in FirstEnergy, and I'll now ask the operator to open the call to questions from analysts. Thank you.

[OPERATOR INSTRUCTIONS] Paul Patterson, Glenrock Associates.

Good afternoon, guys. Can you hear me?

Hi, Paul, yes, you're coming in fine.

I just wanted to touch base with you on two of the earnings items and a quick question on Pennsylvania. When was the -- that MISO PJM transmission cost is $0.07 that you saw this quarter. If you can just elaborate a little bit more on what kind of conditions led to that lower congestion and how you see higher MISO revenues mean -- how you see that going forward? And then on the taxes, that $0.04 benefit, is that something that we'll see showing up going forward, or is that sort of a one-time kind of thing?

Let me start off by answering your question, Paul, about the MISO PJM costs. I think what we're seeing here is lower congestion cost as the result of lower load which resulted from lower weather basically throughout the region. So there tends to be somewhat of a relationship, that was definitely one of the driving factors. You get a little bit of an extreme comparison between 3Q '06 and 3Q '05. The weather during the summer of 2005 was much more extreme and this year loads were much heavier, congestion costs were much higher. What you're seeing in part here is a comparison between a relatively average third quarter of this year versus a fairly extreme weather quarter last year.

And then on the taxes?

And Paul, this is Harvey Wagner. On the tax question, it really was a a component of two things. $0.01 of it related to the phaseout of the Ohio income tax. And that trend will continue through the period ending 2009. The other $0.03 really relates to an item for our 2005 income tax return that was filed this year and it really relates to 2005. That $0.03 per share really is already baked into our earnings guidance on an annual basis, but that's kind of an amount that really applied to last year.

Okay. And then in terms of -- I guess I want to just touch base on Pennsylvania. You mentioned the litigation schedule. I was wondering, is there any possibility -- or what do you think the possibility of a settlement is in that jurisdiction with respect to this case, or do you see this basically being fully litigated?

Well, I think the easiest way at this point for us to say the case is now before the administrative law judge and I would expect that the resolution will be through that process to the commission.

Okay, thanks a lot.

Thanks, Paul.

Paul Ridzon of KeyBanc.

Good afternoon, can you hear me?

Hi, Paul, yes. Can hear you fine.

Looks like when you gave 3Q guidance in the past quarter, you came in above that. Just wondering where you saw the outperformance? And then as we look at 4Q guidance, the top end is modestly above last year. Just wondering what maybe the negative drivers are given the performance year-to-date? And then on a separate issue, just wondering about any type of legislative activity you're seeing in Ohio?

Let me take a shot at that. First, the strong results we saw in the third quarter, Paul, allowed us to be comfortable narrowing our annual guidance to that top end of the range, $3.75 to $3.85. Now that we've got actual results for the first three quarters, it becomes a mathematical exercise, if you will, to determine what your guidance for the fourth quarter is. That becomes a fallout, just subtracting one from the other. That led us to the revised fourth quarter guidance of $0.71 to $0.81.

I think when we gave our revised guidance back, I believe it was in early August. Since that time, there's just been some migration of items from the fourth quarter into the third quarter that benefited third quarter earnings, but won't have an impact on 2006 as a whole. When you look 4Q '06 versus 4Q '05, there are a couple of things that drive that difference. One is that we do have a refueling outage in the fourth quarter of 2006, that's Beaver Valley 2. There was no refueling outage in the fourth quarter of last year. We're also seeing, as we've discussed before, somewhat lower wholesale sales margins, both volume and price impacts, a little bit higher financial fuel costs, a little bit of higher financing cost, and once again, the fourth quarter 2005 weather was a little more extreme than normal. So that's what really gives you the contrast between those two years. As far as the Ohio question, Tony, would you like to address that? The Ohio legislation question.

I don't think there is any legislation pending at this point.

Are we hearing any discussions from the legislators, or anybody thinking about what happens next?

I think most of the members of the general assembly are concentrating on November 7, and what's required for that process. There's not been a lot of talk during the political season that I can see with respect to this issue. With respect to the regulatory issues.

Okay, thank you very much.

Thanks, Paul.

Greg Gordon of Citigroup.

Thanks, good morning, gentleman.

Hi, Greg.

I just want to make sure I understand what's going on in Pennsylvania. Penn Power had the procurement auction. It's my understanding that the results were already approved and the rate increases has already been approved by the Pennsylvania PC, correct?

That is correct.

But on the Met-Ed and Penelec, you've gone through an RFP process, you've procured 950 megawatts of energy and capacity, it's slightly lower than what you had baked into the filing, but that has not in and of itself been approved by the regulators, correct?

That was part of our plan, Paul -- Greg. What you say is correct. That process has been completed. Winning prices and bidders weren't disclosed. As you said, it's slightly lower than what we had estimated in out transition case and assuming our plan gets approved, that benefit would then flow through to customers next year.

But there is a risk that the regulators don't approve the entire increase, then that would impact the P&L of the two distribution utilities if that were to happen, correct?

Yes.

Okay, thank you.

Thank you, Greg.

Next question.

Ashar Khan of SAC Capital.

Good afternoon and congratulations. Rich, could you just quantify -- I was trying to look at the deltas, the transition costs, the amortization, the deferred distribution costs, what kind of numbers do you expect -- I know we have the reported numbers for the first three quarters, but what are the numbers we can expect for the whole year for those two line items?

Let me grab those, Ashar. We've got that, Kurt?

Yes, Ashar, when we talk -- this is Kurt Turosky. When we talk about the transition cost to amortization, I think back -- we had talked initially about $0.80 approximately for the year, and that that was probably going to be offset by about a $0.25 decline for the rate stabilization charge discount, so a net increase of about $0.50 or so. So if you look at it on a year-to-date basis, I believe we're at about $0.62 on the transition cost to amortization line by itself. That number could go upwards toward the $0.80 number for the year, like we talked about.

Okay.

The rate stabilization charge discount, I believe on a year-to-date basis, we're at about $0.20, so that's going to get in that $0.25 to $0.30 range probably, so you get another $0.07, $0.08, $0.07 or so in the fourth quarter probably.

Okay, okay, okay. I was just trying to make sense whether you were running ahead of schedule on that or no.

No. And I think -- and then on the distribution deferred cost, if you recall, the order allows us to defer up to $150 million for the year and I think that's pretty ratably spread over the four quarters. So you should see a similar impact in the fourth quarter that you did in the first three quarters.

Thank you very much.

Thanks, Ashar.

Paul Fremont of Jefferies.

Hi, thank you. Just following up on Paul Patterson's question earlier on Pennsylvania, is there any precedent where the Pennsylvania Commission through a litigated decision has adjusted the pricing during the sixth grade period, or have all of the past decisions to do that been in the context of a settlement? And I guess my follow-up to that would be, are there any legal concerns or issues in terms of their ability to address that as part of the restructuring law in Pennsylvania?

Paul, I've got to tell you, I don't understand your question. Could you repeat it again. I'm not sure what you're trying to get to.

Well, I mean, has the Commission adjusted generation prices that are fixed as part of the original restructuring law in Pennsylvania outside of the context of a settlement? In other words, with Allegheny, we know that there was a settlement agreement where all the parties agreed to adjust the frozen price?

Paul, maybe I should tee this up. Number one, I think the transition plans are different for every company in Pennsylvania. I'm not sure if there's a lot of precedent across the companies. In our case we're operating under a generation rate cap, it's not a rate freeze. We believe that the restructuring agreement gives the Commission the ability to modify that. So we don't view it -- at least the Company doesn't view that as a legal issue.

Okay. So you don't think that their -- a decision by the Commission to do that would be subject to legal challenge?

I'm not a lawyer, but I think any decision in this case is subject to appeal, but I don't know that it's a legal issue. I don't know, Tony?

Paul, I'm not going to give you a legal conclusion on this, but I would expect that somebody will appeal no matter what the decision is.

Okay. Thank you very much.

Thank you, Paul. Next question, please. Do we have another question?

Terry Miller of UBS.

Hi, Terran.

Terry, your line is live, Terry?

We've lost Terran. Why don't we go on to the next question.

David Frank of Peacock Capital Management.

Hi. Good afternoon.

Hi, David.

Hi. Rich, when are we going to get the results on that 950 megawatts, as far as the price?

You're talking about Met-Ed and Penelec?

Yes.

You won't. I mean, that won't be publicly announced.

That won't ever be publicly disclosed in a filing with the Commission?

I don't think so.

Okay. You had previously hedged about 16 terawatt hours I want to say, almost 16 million megawatt hours in '07 and '08 in Pennsylvania through contracts with other parties.

Correct.

How will this -- what level will that increase to now with this 950 megawatt contract? Will it be 18 terawatt hours, 18 million megawatt hours in those two years? Will it be the 20 -- do you have an update you could give us?

I mean, I guess if I understand your question, David, the amounts that we've hedged forward are still there, and remain there, and under the rate plan we filed, we certainly offered to give customers the continued benefit of those hedges, forward purchases, and so forth. What this other transaction that you're mentioning talks about is just part of our plan to reduce the sales from FES to those two utility companies so that they self-supply more, but it doesn't have an impact on the forward purchases that currently exist.

No, I understand that. I'm just trying to get an update on the hedged levels in terms of sales volume that you've hedged now in '07 and '08. What capacity factor should I assume on the 950? 60%?

Yes.

It's the top end of the curve.

Yes.

It's the low-following product of what's necessary to meet the Met-Ed and Penelec loads.

So it's 950 of peak power?

Not -- no.

It's an all-in product?

It's an all-in, but it will follow that load.

Okay, okay. I think I understand. So you had in your filing calculated an under recovery related to NUG contracts in Pennsylvania because that recovery was based off of market prices and I think you were calculating around a $90 million shortfall. If market prices have come down now from your forecast, will that under recovery go down as well, related to the NUG contracts?

This is Harvey Wagner, it really shouldn't affect that. What we were talking about is the gap between market prices and what is currently being recovered through the generation tariff. As market prices change, the amount that gets deferred would also change, except if the market price actually exceeds the actual cost of the NUGs. That's the issue that we have pending before the PUC and the separate addition that we filed. As long as we have deferral accounting for the difference between the wholesale prices that are below the NUG costs, it shouldn't matter.

Okay. I thought the shortfall was calculated off of market price and if the market price is turning out to be less than what you had previously forecasted, then the shortfall would decline. Am I not thinking about that correctly?

If the market prices go down, the gap between what we're collecting for customer rates and the wholesale prices goes down, but the gap between the wholesale prices and the actual NUG costs go up. So the deferred prices would be higher. So on an earnings basis we would be neutral there as long as the wholesale prices are below the actual NUG prices.

I guess I can follow up with you off--?

The wonderful world of NUG accounting, we would be glad to do that, David.

Maybe one last quick question is, could you explain the rationale for breaking the generation rate caps in Pennsylvania, your ability to -- and we look at the [ERIPA] decision and the judge was kind of clear that you can't break those, but there are a lot of legal technicalities involved here. Is there a bottom line synopsis you could just give us for your rationale why you think you can break those if someone were to argue that you can't?

Well, I think if you just look at the documents themselves, the specific transition plan or restructuring plan that both Met-Ed and Penelec entered into, there's a very specific provision in that plan that provides for shopping and provides for the continuation of the polar obligation beyond the statutory time frame. If you don't meet the shopping requirements, which are basically 80%, the words are very clear that the Commission has the jurisdiction to change the generation price. There's a second provision of the document that also provides a specific opportunity to change the price based on a calculation of how that works under very specific language. And of course, there's always a third way the Commission can change a price, and that is through the continuing jurisdiction that the Pennsylvania Commission has based on years of precedent in Pennsylvania to be able to deal with any sort of change that's required in an agreement like that entered into by Met-Ed and Penelec.

I think the two sections Tony was referring to, David, I believe those are section F-2 and F-9 of the restructuring agreements.

Thank you guys.

Hugh Wynne of Sanford Bernstein.

I was, wondering if I could get a point of view from you all regarding the PJM capacity market that PJM hopes to introduce next year? And specifically the extent to that -- extent to which the capacity charges that load serving entities such as your own in Pennsylvania will be required to pay to generators might be recovered from rate payers or whether conversely the existing rate freeze will prevent you from increasing your rates to cover any capacity charges that you might incur under the new capacity payment scheme.

I guess I can give you the 50,000 foot view of RPM which is this process and PJM. By the time that got enacted, you would have gone through several revisions -- quite a few revisions, in fact. Initially, I think the way RPM was laid out, we were not in favor of it. But by the end, by the time it was implemented, it had changes such that we were supportive of it. I think there's still some skepticism in terms of how well this will actually act to incite people to build generation. Only time will tell whether it works or not, but we think the way that PJM rolled this out, is something that we can support, and in fact, we did support that.

On the second part of your question, I don't know but we can check and get back to you. Specifically on how the PJM tariffs work.

A more specific question, then. On the first page of your earnings release and the second paragraph discussing results, you make the point that your generation sales declined reducing earnings by $0.09 per share. And all of that was offset by reduced fuel and purchased power costs. It seems like the generation business in general was a drag on earnings to the tune of $0.05 per share. Yet back in your breakdown of segment results on page 6, you show an increase in net income from power supply services in the quarter rather than a decrease on the order of a couple hundred million bucks. Can you help me put those two things together so I understand what's going on with the two different pages?

I think the big driver there, Hugh, is the impact of the Ohio rate plan. The RT -- GTC ending at the end of 2005, RTC beginning in January of 2006.

Yes.

Why does that cause earnings to go up on page 6 and go down on page 1?

Hugh, on the rate stabilization charge really is part of our generation cost recovery, but we tried to isolate the impacts of the Ohio rate plan on page 1 and therefore the positive impact of the rate stabilization charge is included with that $0.30 per share benefit because of the Ohio rate plan in 2006.

Okay. So basically, the numbers on 6 give me a picture of the true profitability of the generation business. It's just that on page 1, you were trying to allocate that change in profitability between the Ohio rate plan and other operations?

Right, just to make it a little more meaningful.

Could I just ask quickly why you've not revised your 2006 cash flow guidance? It seems like you're only about 60% of the way there and you've got -- 60% of the way there in terms of net cash from operating activities and the first three quarters being like 1.25 billion relative to the 2.1 billion you're expecting for the year. Will this be something that you simply cannot achieve this year, or how will this work out?

We still think that's achievable, Hugh, and that's why we maintained that. Typically the fourth quarter is a big cash generation period for us, particularly October and November tend to be strong cash generation months. I can't remember the exact number for 2005, but I believe October alone in 2005 was something to the tune of about $300 million of positive net cash flow. So the fourth quarter is good for us. We're running on track and that's why we decided to maintain that guidance. We think it still works.

All right. Well, thank you very much.

Thank you.

[Stephen Wong of Citadel Investment Group.

Good afternoon, guys. A quick question here. Can you give us an update as to how many shares were actually repurchased thus far?

We cannot. That's proprietary, Stephen.

That's proprietary, not going to be in the Q?

No.

Okay. And then on the 950 million megawatts that we're talking about here for Met-Ed and Penelec, what is your current FES price that you guys are selling to them at?

That we sell to the utilities at?

Yes, the FES sells?

40 to 45.

45? And then under the new contract, the contracts are signed by the utilities, right, under the RFP?

Yes.

So going forward, the FES -- if they were selling, because they were the backstop, the 950, that frees them up to sell into wholesale? Hypothetically?

Yes, frees up their generation. Yes.

Okay. And then on the actual transition plan in Pennsylvania, in regards to NUG, the NUG rate increase that David talked about potentially, that had nothing to do with the actual breaking of the caps, right? Because the staff is in support of the NUG raising the rates there, so if hypothetically they don't give you the rate cap rate, you could still hypothetically get your NUG rate increases.

Yes, I don't know what the staff's thinking or what the ALJ or the final order might look like, Stephen, but I guess it's conceivable that they could approve some things and exclude others.

Right. But I think in the initial staffing, the staff was supportive of raising the NUG prices, right?

I think that's correct.

I just wanted to make sure. Thanks.

[John Keyonny] of Deutsche Bank.

Good afternoon. Can you please provide us with an update on your plans for allocation of excess capital or use of free cash flow in '07?

Sure. It really hasn't changed. When we look at our uses of cash, certainly reinvesting in our business remains as an important priority for us. Particularly over the period 2007 through 2009, we'll have our environmental program notching up toward the peak spending year. So capital will increase next year and stay at slightly higher levels over that three-year period. That's going to be a big use of cash off the top. We completed a share repurchase this year, we've not announced any decision regarding next year, but we'll consider that and obviously giving cash back to the shareholder in forms of a dividend is very important to us and the Board will consider that issue again at the December Board meeting. Our uses of cash really haven't changed going forward. That's how our priorities have been so that's what we would expect next year as well.

Will the Board, at that December meeting in addition to the dividend, be considering an additional repurchase as well, then, at that time if they were to look at it, or could it potentially just come at a later date as well?

There's no reason that it would have to be at a certain Board meeting, John, they could make that decision whenever.

And just a clarification on Stephen's question on the FES power price, did you say 40.5 or 45?

About $40, 4-0.

Great. Thank you.

Thanks, John.

Daniele Seitz of Dahlman Rose.

Hello. I just was wondering about your environmental expenditures. Do you feel that those are solid, because so many other companies have been revising them, do you feel that what you have forecasted so far is probably the right number?

Yes. We had published a range of 1.6 to $1.8 billion, Daniele, we still feel that's the right range. My expectation is that we'll be closer to the top end of that range, $1.8 billion. But I think that's still a good number. Part of the reason we've been able to avoid some of the increases that other companies are posting, I believe relates to the fact that we completed some of our engineering work and some of our engineering contracts early on and have been able to lock in both supplies and prices more effectively. So our environmental guys are still comfortable that that's a good number and I think that range still works very well, although as I said, I would expect it to be closer to that 1.8 rather than the 1.6.

Okay, thanks.

Thank you.

Dan Jenkins, State of Wisconsin Investment Board.

Hi, good afternoon.

Hi, Dan.

Just a little clarification on what you mentioned about the share repurchase. It sounds like that this 10.6 billion plan that you just implemented, that pretty much takes care of your share buybacks for '06?

For '06, I would expect that's true.

Okay. And then I think you mentioned early on the call some of your debt plans, you have the 600 million coming due next month --

Sorry, November.

And then obviously some short-term debt that you incurred related to the share buybacks. Do you anticipate -- I know you filed some S3s for Toledo and Cleveland, is that kind of related to refinancing that bad debt?

The whole coal debt, yes, it is, that's right, Dan. That's consistent with our philosophy of taking debt out at the holding company, reissuing it basically at the operating company to get those regulated operating companies properly capitalized in a regulatory context, so you're correct.

Okay. And then I was wondering, on the first page of your release, you mentioned the $0.01 benefit from the postretirement benefits other than pensions and you mentioned that it's health care benefits being -- changes in the health care benefits being phased in through '08 and I guess, could you explain a little bit what those program changes are and then since it's being phased in, is that something that should benefit you going forward through '08 as well?

What we're doing, like a lot of employers, Dan, is really looking at our health care costs and how can we minimize those? Part of it is cost sharing with employees like a lot of employers are having to do now and part of it is trying to change the behavior of employees in terms how they buy health care services to make them better consumers and more effective consumers of health care. I think our programs are working effectively. I would expect we'll continue to look at those going forward and certainly there would be a benefit from those changes relative to what we otherwise would have had.

Dan, one other thing to add to that. As you know, part of the element of the post-retirement benefit cost is the amount that we're going to pay during the retirement period for people who are currently working. So the changes that are being phased in through 2008 really are reflected already in the projected benefit obligation that we're currently accruing for people who are working.

Okay.

Okay?

Then just a question on CapEx. So far you've spent 990 million versus 756 last year. Where's most of that increase coming from? Is that environmental?

That's coming largely from environmental, you're right, Dan.

Okay. And then on the balance sheet, if you could remind me what the -- you have about $3.5 billion of investments, what's that related to?

Primarily nuclear decommissioning trust funds and nuclear field disposal.

Okay. And then on page 9 of your release, at the top there, that regulated versus competitive, is that the shopping customers switching back? Is that what you referred to, is that what that is? The positive and the negative going on there?

Yes.

Yes.

Yes, it is, Dan.

Okay. And then on the wholesale line, basically you had about a 33% decline in the quarter and about 20% so far this year, I was wondering if you could break that down. How much of that is due to the price being lower and how much of it is due to the volume decline?

Those are all volumes that you're looking at there.

Okay, oh, that's -- okay. That's kilowatt.

And that's consistent with the migration of customers back to the operating company, so we have less generation to sell at wholesale.

Okay. And then also on that same page, I noticed the industrial in New Jersey was down quite a bit compared to what you're seeing in Ohio and Pennsylvania. Do you know what's going on there? Did you have -- lose customers, or is there a different environment in New Jersey versus the other two states in industrial?

Yes. I'm not really aware of any specific reasons for that, Dan.

There was also a slight reclassification of customers between industrial and commercial, and I think that drove part of that difference.

Okay. Then the last question I have is related to -- you had some sale of the FE facilities in the quarter. How much of that do you have left to sell? And how much was the proceeds from what you sold in the third quarter?

I think the carrying value of what we have left at FSG is about 25 million and the MYR is about 45 million. So roughly about 70 million carrying value for the remaining assets.

And the proceeds in the quarter from the sale?

I don't -- It was minimal. Yes, it was nominal.

Okay. That's all I have.

Thanks, Dan. Since we're coming up on 50 minutes, let's take one more question on the call and then we'll be glad to get back with any of you offline if there are any further follow-ups.

Your last question comes from [Jim Ferguson] of AIG.

One was answered, but the second on debt of the new facility that you have described as both the holding company and the operating company, is that available for the operating companies to borrow separately and distinctly from their brethren and the holding company, or will it be all through the holding company with joint and several [obligeurs] as the [opcos]?

No, they can borrow individually.

Okay.

Thank you, Jim. Okay. We appreciate everybody's time and interest in FirstEnergy today. As I said, we'd be glad to follow-up offline if there are any further questions. Hope to see many of you in Las Vegas at the EEI financial conference coming up shortly and we appreciate your continued support and interest and hope everybody has a great day. Thank you very much.

Thank you. And this concludes today's FirstEnergy Corp. third quarter earnings conference call. You may now disconnect and have a pleasant day.