第一能源 (FE) 2002 Q2 法說會逐字稿

My name is [Amitris] and I will be your conference facilitator. At this time, I would like to welcome everyone to the First Energy Corporation second quarter results teleconference webcast. All lines have been placed on mute to prevent any background noise.

After the speakers remarks, there will be a question and answer period. If you would like to ask a question during this time, simply press *, then the number 1 on your telephone keypad. If you would like to withdraw your question, press the *, then the number 2 on your telephone or keypad.

And now, I would like to turn the call over to your host, Kurt [Cherosky], director, investor relations.

Sir, you may begin your conference.

Thanks, [Amitris]. 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

First Energy Corp. are based on current expectations that are subject to

risks and uncertainties.

A number of factors could cause actual results or cause it to differ materially from those indicated by such forward looking statements. Please see our management discussion and analysis of financial

conditions and results of operations included in our most recent annual

and quarterly reports filed with the Securities and Exchange Commission

for a detailed description of these factors.

I'd now like to turn the call over to our senior vice president and chief financial officer, Rich Marsh.

RICH MARSH, SENIOR VICE PRESIDENT, CFO: Thanks, Kurt.

Good afternoon and thank you for joining us today. With me in Akron are Harvey Wagner, our controller; Tom Navin [sp], our treasurer; and Terry Hausen and Kurt Cherosky [sp] from our investor relations group.

We released our consolidated report to the financial community earlier today. And this might be handy to refer to, as we discuss our results. The report's also available on the investor relations section of our website. And the address for that is www.firstenergycorp.com.

Our discussion today will compare second quarter 2002 actual results to second quarter 2001 pro forma results. As a reminder, the 2001 merger pro forma financial statements by quarter are available on our website. The merger pro forma statements reflect the 2001 combined results for First Energy and GPU, as if the acquisition of GPU had been completed at the beginning of 2001.

Our call will also provide an update regarding the sale of our light plant energy, the status of the Davis Betsy extended outage, and our upcoming rate case filing in New Jersey. There's a lot to talk about today, so let's get started.

Net income in the second quarter was $233 million or basic earnings of 80 cents per share. This exceeded the First Call consensus estimate, and also exceeded our second quarter 2001 merger pro forma results of 70 cents per share by 14%.

Diluted earnings per common share were 79 cents. The major drivers of this increase in earnings over our second quarter merger pro forma results included higher electric sales to retail customers, strong performance from our generation fleet, and lower purchase power costs.

These were in turn partially offset by increased employee pension and benefit costs, and higher general and franchise taxes. Additional information on the major earnings variances for the quarter is included on the first page of our consolidated report to the financial community.

I'd now like to ask Tom Navin [sp] to review the details of our

financial results.

TOM [NAVIN], TREASURER: Thanks, Rich, and good afternoon, everyone. Electric distribution delivery, which include total kilowatt hours consumed by customers in our franchise service territories, regardless of their generation supplier, increased by 2%, compared to the second quarter of 2001. Residential throughput increased by 6%, while

distribution deliveries to our commercial industrial sector remain flat.

The warm weather in June helped boost residential demand for power as

cooling degree days for the month were 16% above normal and 11% above June 2001. The fact that commercial industrial retail sales were flat for the quarter might be viewed as a positive sign that the economy is firming. Another encouraging indicator is the fact that the National Industrial Production Index has increased for six straight months, after 18 months of declines. The increase in the production index is viewed as a positive signal of economic recovery.

Overall generation sales during the quarter were relatively unchanged as a 1% increase in retail generation sales was offset by a 4% decline in wholesale sales. The increase in retail generation sales was attributable to a 15% rise in unregulated retail sales, primarily from the increase in the number of Ohio customers who are shopping with our unregulated affiliate, First Energy Solutions.

We have now achieved the 20% shopping target established in the transition legislation for all customer classes and operating companies, with the exception of the Ohio Edison residential sector. We expect to achieve the targeted level of shopping for these customers by year end.

Electric sales revenues increased by $17 million after adjusting for the increase in shopping incentive deferrals, as higher retail sales volume offset reduced volume in prices associated with wholesale sales.

Net fuel and purchase power expense for the quarter decreased by $57 million. Fuel expense increased by $37 million due to high production levels and the increased proportion of coal in the generation mix.

This increase in fuel expense was more than offset by a $94 million reduction in purchase power expense, after adjustment for a $12 million increase in transition cost amortization.

Approximately 75% of the decline in purchase power expense can be attributed to the lower price of electricity in the wholesale market, compared to the same time last year.

The balance of the decline was attributable to lower market purchases overall. The performance of our generation fleet during the quarter was very favorable, with output increasing 9%, compared to the same period last year, even including the extended Davis Betsy outage.

Output from our fossil units increased 27%, led by strong performances at the Bruce Mansfield and Sammonds [sp] Coal Plants. Both of these units achieved an 89% capacity factor during June. Also, our Perry and Beaver Valley Nuclear Plants have achieved year to date capacity factors of more than 90%.

Total generation expenses were comparable with the prior year. The favorable performance of our fossil fleet was offset by higher nuclear expenses, largely due to the Davis Betsy extended outage.

Nuclear expenses increased by $16 million, $12 million of which was related to the Davis Betsy outage. $16 million decrease in fossil operating expenses reflected the favorable performance of the fleet and the fact that little unscheduled maintenance was required.

Negatively affecting other operating expenses were the $27 million increase in employee benefit costs. This was primarily attributable to the reduced market value of pension plan assets, the conversion of the former GPU companies pension accounting to fair value earlier in the year, and increased healthcare costs.

Also negatively impacting earnings was an increase in general and franchise taxes of $34 million, compared to the same period last year. Contributing to the increase in general taxes this year was a $15 million tax credit that was applied to last year's general taxes, due to a successful court appeal on nuclear fuel valuation.

A $19 million increase in franchise and local taxes resulted from timing

differences and the implementation of deregulation in Ohio in 2001.

Total depreciation and amortization decreased by $14 million during the quarter, after adjusting for a $20 million increase in shopping incentive deferrals, and a $12 million decrease in transition cost amortization. This included a $10 million decrease in depreciation and expense associated with the pending sale of our Lake Plant to NRG and a $5 million reduction in decommissioning expense associated with the Facts and Research reactor.

Now I'd like to discuss the performance of our non electric, unregulated business units. Contribution to earnings from our non electric

businesses exceeded last year's second quarter results. The gross margin from our natural gas business improved by $11 million, while our investment in Great Lakes Energy Partners contributed about $2 million to net income.

The improvement in the natural gas business segment was largely

attributable to reduced sourcing costs, compared to the same period last

year. The improvement in our natural gas business was in part offset by

reduced earnings contribution from the MYR and facility service groups.

The contribution from these operations declined by 1 cent per share, compared to the same period last year as these companies continued to operate in a difficult economic environment with a limited number of

construction projects and intense competitive pressures.

I'd now like to provide an update regarding our continuing efforts to reduce interest costs and improve our financial flexibilities. During the second quarter, we completed $177 million of mandatory redemptions of long term debt and preferred stock, made $145 million in optional redemptions, and completed $1 billion in refinancing.

Together, these actions will reduce annual financing costs by approximately $58 million or 14 cents per share. In addition, $1.7 billion of debt was deconsolidated from the balance sheet following the sale of 79.9 percent of Avon Energy Holdings.

For the second half of the year, we planned to redeem approximately $616 million of mandatory redemptions, which will produce annualized savings of $48 million.

Our credit standing is very important to us. And we are continuing with what is probably the most meaningful debt redemption and credit improvement program in the industry. We have committed to reducing our leverage through our asset sales, and also by devoting our substantial

positive cash flow over the next few years towards debt retirement.

Our plan for 2002, including the closing on the sale of the Lake Plant, will reduce our consolidated leverage to just under 60%. Because of the strong cash flow resulting from our recovery of transition costs in all three of our states, we expect to devote about $1 billion of positive cash flow per year towards debt retirement during the next several years. This plan is expected to reduce consolidated leverage to about 55% by the end of 2003.

Now I'll turn the call back to Rich for a brief update on the progress being made on several key initiatives.

RICH MARSH, SENIOR VICE PRESIDENT, CFO: Thanks, Tom. And I'll start with an update on our asset sales activities and follow that with a review of Davis Betsy and other matters.

Following FERC's approval earlier this month, we've now received our regulatory approval needed for the sale of our four Lake plants to NRG

Energy. Following FERC's approval, First Energy and Cleveland Public

Power, that is the city of Cleveland's municipal and electric system,

notified NRG that the FERC conditions required NRG to provide notice to

First Energy and Cleveland Public Power prior to removing any of these

units from service would be fully satisfied under NRG's existing

obligation under their interconnection agreements.

This confirms FERC's July 16th order doesn't impose any new or additional burdens on NRG. And NRG has not obligations, other than this notification, under the merger settlement agreement.

NRG is currently reviewing the merger settlement agreement and has indicated that this review will be completed by August 1st. We continue to work on clearing the last few conditions precedent to the closing of the transaction under the purchase and sales agreement and expect that these will be resolved over the next few weeks. We continue to

anticipate a timely closing to this transaction.

I'd also like to give an update on our continued efforts to divest [Andersa], which is the Argentinian distribution entity acquired in our merger with TPU. The economic climate in Argentina obviously remains difficult. And these conditions have complicated our efforts to divest this asset.

However, we continue to actively pursue all options, and are currently negotiating with potential purchasers, who have not retained financial counsel to assist them in the due diligence process.

We hope that these negotiations will be fruitful, and can be completed during the third quarter of the year. If, however, we aren't able to complete the sale of [Andersa] or achieve a definitive agreement to do so by November 6th, which is the one year anniversary of our merger with GPU, several actions would be required.

First, this asset can longer be reflected as an asset pending sale on our consolidated balance sheet. This is because the relatively

accounting guidelines indicate that an asset must be sold within one year of the time that it is first such categorized.

Any income or loss generated by [Andersa] after that date, or after the date that a sale is considered not to be probable, would be included in our consolidated statements of income.

In addition, we would recognize a one time, non-cash, cumulative effect of a change in accounting to reflect [Andersa's] cumulative operating results from November 7, 2001, which is the day following confirmation of our merger with GPU, through such date that it becomes probable that a sale of First Energy's interests would not be achievable within the one year timeframe.

Based on results through June 30th, for the amount of such a one time cumulative charge would currently be about $95 million or 33 cents per share. [Andersa] generated positive earnings from operations during this period. And so, this impact results from the currently devaluation losses after the peso was delinked from the dollar earlier in the year.

Despite the difficult economic conditions in Argentina, we will aggressively continue our efforts to sell this asset, and are hopeful that our current negotiations will result in a successful outcome.

Let's turn now to activities that the Davis Betsy nuclear facility. We continue a large number of activities that are untended to start a restart of this facility during the fourth quarter. Considerable

progress was made in this regard during the period, including

establishment of an integrated return to service plans, strengthening of

our nuclear management organization, preparations for replacement of the

reactor head, and initiation of plant maintenance and repair activities

needed to support the restart.

We developed an integrated restart plan that revolves around several key building blocks. These are restart action plan, a reactor head resolution plan, a program appliance plain, containment health assurance plan, a system health assurance plan, management, human performance excellence plans, and a restart and post-restart test plan.

We continue to work closely and cooperatively with the NRC in these activities. And ultimately, that tone was evident in the most recent public meeting of the NRC's oversight panel on July 16th.

At that meeting, the NRC introduced their framework for a restart action

checklist, which largely mirrored Davis Betsy's restart plan. Members of the NRC panel expressed confidence in our ability to successfully resolve the many technical issues before us, and indicated that management and organizational issues won't be the key to the restart of the unit.

Over the past weeks, we've made significant strides in strengthening our senior nuclear management team, as well as the management structure Davis Betsy. Newly created positions within the First Energy nuclear operating company include those of chief operating officer, executive vice president of engineering, and vice president of nuclear oversight.

We're continuing our efforts to compile a comprehensive management root cause evaluation, which will include identification of the various steps necessary to address any cultural or human performance related issues.

We're also evaluating our policies and procedures to ensure that they meet the highest standards in the industry. We've also established an independent oversight panel consisting of industry experts to assist us in our restart efforts, and to provide advice regarding the safe return of Davis Betsy to service.

Testing and refurbishment of the Midland Reactor vessel was completed ahead of schedule. And the reactor head was safely delivered to the Davis Betsy facility via truck on July 18th, that Thursday. We

currently await installation on the reactor.

We continue to believe that we will identify and address any technical or human performance issues such that the restart of the unit can be supported during the fourth quarter.

We recognize, however, that NRC approval must be secured before the plant can be restarted. Our cost estimates regarding the Davis Betsy

extended outage have not changed, and consist of $55 to $75 million of

mostly capital expenditures to replace the reactor vessel head, $50 to $70 million, primarily of loan [M] expenditures traditional maintenance

projects, including acceleration of various programs.

$20 million per month for replacement power during the summer months of July and August, and $10 to $15 million per month for replacement power during the non summer months.

To ensure that we've adequately secured supplies to meet our customers' needs, we fully hedged our 850 megawatts of on peak replacements energy supply for Davis Betsy through the end of the year. And although we

expect the plant to return to service before year end, we've also made

some purchases of on peak power during the beginning months of 2003.

I'd like to give a brie update regarding our activities to secure power, to meet our provider of last resort obligations beyond 2002. Given the

current low prices and favorable market conditions, we've continued to

lower purchases to meet our provider of last resort obligations during the period 2003 to 2005.

We believe that this is prudent, and that minimizes our exposure to the commodity markets, and also reduces uncertainty regarding the pending Pennsylvania supreme court of appeals on the [Menad Empanelactifer] mechanism. We're now over 90% hedged for our projected summer peak of 2003, and approximately 85% hedge for the 2004 and 2005 summer peak loans.

Finally, what we mentioned that under the New Jersey transition legislation, all electric delivery companies in that state are required to file rate cases by August 1st of this year. We'll be making our filing for New Jersey Central Power and Light with the Board of Public

Utilities next week. This filing will address the appropriate delivery

rate structure for JCP and O and also request recovery of the company's

deferred energy balance.

The new rate structure will become effective on August 1st, 2003. We'll issue a letter to the financial community providing additional details at the time the filing is made.

In closing, I'd like to emphasize that I'm pleased pleased with our results during the quarter. It was a period of substantial progress in addressing our issues at Davis Betsy. And it was also marked by the outstanding clear units during a very a high customer demand.

Our litigation with GPU also continue to progress favorably during the quarter. Many of these activities were centered in our distribution business where synergy has been favorable, and the sharing of best practices is already beginning to produce benefits for our customers.

We're pleased by how well the cultures of the two companies have come together. For the year, our earnings guidance remains at $3.30 to $3.45 per share, excluding the costs of the extended outage of Davis Betsy and any potential adjustments related to [Andersa] if we are unable to sell this asset.

Looking ahead to 2003, our target to 7 to 8% earnings growth from our previous 2002 earnings guidance of $3.45 to $3.65 is still appropriate.

In spite of our progress and favorable earnings growth outlook, however, our stock has climbed in price along with most others in the industry. Obviously we're disappointed by this in view of the valuation our stock is trading at is irrational. We believe that our business model and our favorable regulatory status should positively distinguish First Energy from many other companies in our sector.

We continue to pursue an integrated approach to the utility business with virtually all of our generation output being sold to our retail customers at fixed rates, our substantial positive cash flow emanating from a stranded asset recovery, and our aggressive debt pay down and improving credit profile, long term value for our investors will be created.

Our business model and our growth prospects remain intact. We're hopeful that when the hysteria subsides and the market again begins to discriminate among the companies in our industry, the [very] of our franchise will be appropriately recognized in the marketplace.

I'd like to thank you for your time and interest in First Energy. And I'd now like to ask [Amitris] to open the call to questions from the analysts. Thank you.

q-and-a

At this time, I would like to remind everyone if you would like to ask a question, press *, then the number 1 on your telephone

keypad. We'll pause for just a moment to compile the Q&A roster.

Your first question comes from Paul [Riden] of McDonald Investments.

PAUL [RIDEN], MCDONALD INVESTMENT: Good afternoon. You'd given some

capitalization ratios. Are there any off balance sheet obligations that

could be put into those to make them a little bit worse?

No, Paul, actually when we calculate those ratios, we do it on a same basis as our rating agencies use. And the debt levels are adjusted to reflect sale lease back obligations and other obligations. So I think we're including everything in those numbers.

PAUL [RIDEN], MCDONALD INVESTMENT: They're fully loaded? Yes?

Yes.

PAUL [RIDEN], MCDONALD

And in the event [Andersa's] not sold, how much remaining book value is there that could, you know, have to be written off?

Well, those assets were written down as part of our purchase accounting adjustments. We set those at a level that we believe is appropriate. And our internal analysis, you know, supports that current valuation. Given the negotiations with potential buyers, they don't want to be specific on that, but for order of magnitude type of sense, you can refer to page 47 in the annual report which provides some information on international operations.

PAUL [RIDEN], MCDONALD INVESTMENT: If by November 6th, you have a pretty firm agreement to sell those, what would the implications of that be, even if you can't, you know, mechanically do the sale?

MALE

We would not be reflecting the adjustments that I had talked about if we have a FERC commitment to sell those assets, even if the transaction is not physically totally qualified on November 6.

PAUL [RIDEN], MCDONALD INVESTMENT: And lastly, you had a tax timing benefit this - excuse me, debt [inaudible], this quarter. How does that flow through the rest of the year?

This is Harvey Wagner, Paul. Comparing to last year would be pretty much on track. Some of those changes in the tax law in Ohio were effective in May of 2001. So it hit the quarter and split the difference.

PAUL [RIDEN], MCDONALD INVESTMENT: So the back half of the year is pretty much the same?

Right, right.

PAUL [RIDEN], MCDONALD INVESTMENT: Thank you very much.

Thanks, Paul.

Our next question comes from Paul Freedmont of Jeffries.

PAUL FREEDMONT, JEFFRIES: Yeah, just following up on the prior question. Can you remind us how much sale lease back debt there is?

Sure, Paul. In the calculations, we're picking up about $1.5 billion of the sale lease back debt equivalent.

PAUL FREEDMONT,

And for amortization purposes, does that all mature pretty much in a lump sum or is there regular amortization of that?

Yeah, there's regular amortization, principle and interest, over the remaining lines.

PAUL FREEDMONT, JEFFRIES: Thanks very much.

MALE

Sure.

Thanks, Paul.

Your next question comes from Jay Dobson of Deutsche Bank.

JAY DOBSON, DEUTSCHE BANK: Hey, Rich, it's Jay Dobson. Just two questions, can you just give us those capital ratios if we were to assume that for some reason the NRG late plan sales didn't go through? And then, can you also just drill down a little bit there? Have we given them copies of all the documents that they've asked for, such that they can complete this review of the documents by - sorry, August 1st? And has a finalized agreement with the CPP actually been put on paper and finalized?

RICH MARSH, SENIOR VICE PRESIDENT, CFO: Okay, let me start with your first question, Jay. We started the beginning of this year with total leverage, which includes our off balance sheet items at the time. Tom mentioned fully loaded rating agency view, debt leverage of about 66%.

Now we said with our asset sales this year, including the energy transactions and the use of our free cash to pay down debt, our objective was to get that down in the 59% range by the end of this year.

If, for some reason, the energy transaction were not to close, and I want to emphasize I do not believe that will be the case, because I do believe it will close, but if it did not, that ratio would be, you know,

roughly rather than going from 66% to 59%, it would go from 66% to

something in the 61% kind of range.

So it's about 200 basis points. So we would still experience very substantial credit improvement. However, as I say, I want to stress, I do believe that transaction will close.

In terms of the documents, I believe according to our lawyers, I think we furnished the documents that NRG needs to complete this - the review at this point in time. And an agreement with CPP has been finalized.

JAY DOBSON, DEUTCHE

Great, thanks so much.

RICH MARSH, SENIOR VICE PRESIDENT, CFO: Thanks, Jay.

Your next question comes from David Frank of Zimmer, Lucas and Partners.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: Yeah, hi, good afternoon, Rich.

RICH MARSH, SENIOR VICE PRESIDENT, CFO: Hey, David.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: Yeah, I wondered if you could tell us what percent of the retail shopping - what percent of your

retail load that is shopping is currently being served by - at the

affiliates?

Yeah, I think there's about 740,000 customers shopping. And First Energy Solutions has about 250,000 of those customers. But then, of the balance, many of the balance are also being served by our market support generation, which is the 1120 megawatts we agreed to sell to third parties to our retail customers under our settlement agreement.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: Okay, so about a third is being served directly by yourself?

RICH MARSH, SENIOR VICE PRESIDENT,

That's right, David.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: And how much is being served by the generation and you get the same margins on that that you would if you were serving the customers directly?

RICH MARSH, SENIOR VICE PRESIDENT, CFO: That's all that the fixed rate marketers, who then resell it to the customer. So that is the market's poor generation. The prices that we charge are defined in the transition plan. And it's relatively comparable to what we were directly trying with customers.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: Right, okay, another question related to New Jersey and Pennsylvania's, the deferral of energy expense group under a million dollars a quarter or about $100 million?

RICH MARSH, SENIOR VICE PRESIDENT, CFO: Yeah.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: Is that hedging for summer months that GPU put on to hedge themselves this summer? And will we see like that - grow a like amount in a second in the third quarter? And is that hedging a place for summer of '03, so you would expect deferrals to grow at this rate?

RICH MARSH, SENIOR VICE PRESIDENT, CFO: The - I'll start at the back

end. The relative to the hedging for 2003, I think Rich indicated at

[inaudible], we've hedged in about 90% of the requirements for the summer fatigue that we still have some hedging to do, which given the current market prices, you know, should be, hopefully, less of an impact that, you know, what would have been experienced thus far.

You got to recall, David, that some of the hedging for this summer was done last year.

DAVID FRANK, ZIMMER, LUCAS & PARTNERS: Right.

RICH MARSH, SENIOR VICE PRESIDENT, CFO: And when the market prices were much higher.

DAVID FRANK, ZIMMER, LUCAS &

Right.

RICH MARSH, SENIOR VICE PRESIDENT, CFO: SO I think that's why you're seeing an increase in the - especially within - it was predominantly in the JC P&L territory. And the other thing to realize is that for JC P&L is effective August the 1st. We will begin the BGS process.

And I believe under - there still won't be growing deferral balances under the BGS that's probably not the same magnitude is historically occurred.

Let me just add the - in New Jersey, the deferrals go up a lot more into Jersey because of the large amount of no contracts. In fact, if you looked at the sixth month of this year versus last year, actually in Pennsylvania, there's been a credit. New Jersey is still - the balance is still going up quite a bit. But again, that's mostly all subcontractors.

So that's hedging that was put in place last year when prices were high doesn't run into summer of '03.

MALE

It's not really hedging. It's the Nut contracts that were signed back in the, you know, '80s and '90s that were way, way above market price. So it's really the difference between those high market prices in that contract and the market.

And so that they're there to stay, then?

Yeah, Jersey will continue to - those are the

subcontracts over [inaudible] over the course of the next eight years or

so.

Okay, sorry, one last question. Can you tell us how much debt is associated within their [inaudible]?

Yes. About $185 million, U.S. denominated.

DAVID FRANK, ZIMMER, LUCAS &

Okay. Thanks a lot, Rich.

RICH MARSH, SENIOR VICE PRESIDENT,

Thanks, Jim.

Your next question comes from Jessica Rudledge of Lazard.

JESSICIA RUTLEDGE, LAZARD: Hi. Can you give us some indication of what operating cash flow is going to look like this quarter? What have been the major non cash adjustments? Or what's the actual operating cash number?

For this quarter?

JESSICIA RUTLEDGE, LAZARD: Mm-hmm.

I believe we're looking at cash flow from operations for the year 2002 in the $300 to $400 million range, dependent on which end of the range of [inaudible] expenses we come in at. So I wouldn't think that, you know, a little bit more than 30% of that would have occurred in this quarter.

JESSICIA RUTLEDGE, LAZARD: Okay, so no actual number, but there are no specific lumping the cash flow adjustments that we're going to see this quarter, relative to the rest of the year?

Not to my knowledge.

JESSICIA RUTLEDGE, LAZARD: Okay, thank you.

Your next question comes from Peggy Jones of ABN Amro.

PEGGY JONES, ABN AMRO: I wanted to just follow up on the sale of the Lake plant and ask about timeframes of what you would do if there was

another delay that NRG asked for on August 1st?

Okay, well, you know, the only conditions precedent to close at this point are being addressed. And there's a few, what I wouldn't characterize as a few minor pre-closing sort of things that we have for you. And at that point in time, our believe is that we will be in a position to quote that transaction as required under the purchase and sales agreement. So we're not contemplating a delay.

PEGGY JONES, ABN AMRO: Thank you.

MALE

Thank you.

Our next question comes from Danielle [Stikes] of Salomon Smith Barney.

DANIELLE [STIKES], SALOMON SMITH BARNEY: Hi, [inaudible] sort of review of [inaudible] your nuclear operations by the end or see. And is the result supposed to be coming in make sure - before at the authorization to restart for [inaudible]. Or is it purchasing dependent?

Well, I think it's part of their review, Danielle or Davis Betsy. They will be looking at the FENOP, First Energy Nuclear Operating Company structure and the changes that we've put in place, but from an oversight perspective and in terms of policies and procedures, focusing on being [inaudible], but looking at the other plants as well, obviously, to make sure that they feel that they're appropriate.

I don't know if there's a specific timeframe for them to complete their work, but as I said, obviously, the NRC has to approve the restart of Davis Betsy.

So I know they have a lot of events ongoing?

DANIELLE [STIKES], SALOMON SMITH BARNEY: Uh-huh, but you talk more - but you don't have a needed datas to also [inaudible] as well. This is - the results will be mentioned and basically the record we charge.

No, there's no specific date for that, Danielle. They will - the NRC will continue to hold periodic public meetings. I think probably roughly about once a month. So that will probably be the

mechanism that they would use to report on their activities going forward, about once a month.

DANIELLE [STIKES], SALOMON SMITH BARNEY: Great, thanks.

Thanks, Danielle.

Your next question comes from Greg Oro of Lehman Brothers.

GREG ORO, LEHMAN BROTHERS: Good afternoon.

Hi, Greg.

GREG ORO, LEHMAN BROTHERS: I was wondering if you could go back over the impact in the quarter on the employee benefits you mentioned? What was kind of driving that?

MALE

It think part of that was, you know, obviously, the increased pension expense this year, due to the decline in asset values.

HARVEY WAGNER, CONTROLLER: Greg, this is Harvey. We said about $27 million of increased costs associated with benefits. About half of that relates to the reduction and the market value of the First Energy plan assets. And combined with the change in GPUs valuation's accounting methodology from the smoothing to the fair value method.

So that took up - those two things combined was about half of the increase. The other half, the increase was just increased healthcare benefits.

GREG ORO, LEHMAN BROTHERS: Okay. There was no adjustment to the return assumption.

NO, there was not.

GREG ORO, LEHMAN BROTHERS: Okay. Okay, thank you.

MALE

Thank you.

Our next question comes from Steven Corn of Lowes Corporation.

STEVEN CORN, LOWES CORPORATION: Hi, guys. With regards to the pension, can you just clarify given current market conditions, should we expect [inaudible] incremental costs as we look out, assuming the markets don't recover into '03? And how do you think about what that may nor may not mean? And I have a second question as well.

Okay, answering that, Steve, yes, we would expect there would be something if the market stayed and the [inaudible]. I can't

quantify that for you because I don't know what the number is. But yet,

there would be an impact. Obviously every plant sponsor has their fingers crossed that the market will rally back, but you know -

Yeah, it would be a two pronged thing where the reduction in the market value of the plant assets would become part of the actuarial adjustment going forward. But then the return would be applied to a much lower asset base. So it's kind of a double edged result there.

STEVEN CORN, LOWES

Okay. And then secondly, I understand that you think that the league plant sale is going to close in the league. But just - let's just take the assumption that it doesn't. What was your planned environmental upgrade cost that you were going to put into the plan within the next couple years?

Boy, don't have that off the top of my head, Steven.

STEVEN CORN, LOWES CORPORATION: Okay.

I can get back to you with that [inaudible].

STEVEN CORN, LOWES CORPORATION: [Inaudible] Thank you.

Your next question comes from Chris Melendez of UBS Principal Finance.

CHRIS MELENDEZ, UBS PRINCIPAL FINANCE: Hi, guys.

Hi, Chris.

CHRIS MELENDEZ, UBS PRINCIPAL FINANCE: I just wanted to clarify something is that the FERC clarification of the Lake Plant sale indicated that NRG has to notify you and BPP. And then you guys came back with BPP, instead OK, we'll - you don't have to do that. We will - all you have to do is notify us under normal circumstances, and that'll be fine.

My question is, is that can a separate outside agreement between you and CPP supercede a FERC order? Is my question clear?

MALE

I'm not sure, Chris, but the situation, again, let me try to answer that for a minute. If it's not clear, we'll try again, but

basically what this whole issue of clarification was about was under the

interconnect agreement that NRG previously executed, which provides them

with access to the transmission grid for the four operating plans, they

agreed to provide adequate notification should they, for whatever reason, decided to remove these plants from service.

The whole issue of clarification was would there be some other notification that would be required, other than what's already provided for in the interconnection agreements?

And I think those clarifications in the agreement with CPP really indicated and clarified that no other notification would be necessary, other than what's contained in the interconnection agreement.

CHRIS MELENDEZ, UBS PRINCIPAL FINANCE: Okay, I guess I didn't read that closely enough. Then you know, essentially what FERC is saying is that NRG will notify First Energy regardless of this rule. And that will meet all the requirements?

I mean, the part that I was wrestling with.

Yeah.

CHRIS MELENDEZ, UBS PRINCIPAL FINANCE: And I don't want to beat a dead horse, and we can do it online, is that I just want to make sure that the agreement that you and CPP have together is not trying to supercede a court order, whereas it allows you to supercede a court order. Being like - can you guys meet your own agreement between you two, and say look, that solves the requirement?

These were really intended to be clarifications of what was in the FERC order, Chris.

CHRIS MELENDEZ, UBS PRINCIPAL FINANCE: All right. Thanks. We can get in more detail off line.

Yeah, I'd be glad to, if that would be useful, sure. Thank you.

CHRIS MELENDEZ, UBS PRINCIPAL FINANCE: Thanks, have a good day.

Your next question comes from Scott Pearl of Credit Suisse First Boston.

SCOTT PEARL, CREDIT SUISSE FIRST

Thanks, good afternoon.

Hey, Scott.

SCOTT PEARL,

I guess a couple months ago, when you talked about the '02, '03 guidance, there was discussion on the cost saving program and even more specifically talking about moving Mansfield [inaudible] '02 and '03.

I guess I just wanted an update as to how that program is moving along and those plans remain the same as far as moving things around from a timing standpoint?

The cost savings that we indicated, I mean, we have put in place a number of actions that will encapsulate cost savings that we had talked about.

In terms specifically of the Mansfield unit, at this point in time, given some of the cost savings, we've been able to achieve our anticipation is that we are going to go forward with that this year, as opposed to moving in 2003, as we originally thought.

We can certainly accommodate that within the existing guidance. And we also feel it was the right thing to do from an operating perspective.

So I think we said - when we changed the earnings guidance, the cost reductions would be somewhere between 15 and 25 cents per share. They will be. They will be.

SCOTT PEARL, CREDIT SUISSE FIRST

And Mansfield was I think about a third of that?

That's about right. Something on that magnitude, yes.

SCOTT PEARL, CREDIT

Okay. On an unrelated note, maybe you can just give us a little bit of an update on Pennsylvania, referred to earlier, but just where you stand with the different proceedings, relative to the deferral and the synergies?

Sure. Are you referring to the appeal of the Pennsylvania Commonwealth court decision to the Pennsylvania supreme

court, which was I believe in March, BPO was filed in March.

At this point in time, Scott, we're waiting to hear back from the Pennsylvania supreme court, to hear whether will decide to hear that appeal or not here it.

You know, on the - just based on the typical amount of time it takes them to respond, we would expect to be hearing sometime soon, although we have no definitive news about when they will choose to accept or not accept it.

So our activities at this point, as we mentioned in the call, are really aimed at going at and trying to hedge as much of that for wider, last resort obligation as possible, which to some degree helps mute the economic impact of the company.

SCOTT PEARL, CREDIT SUISSE FIRST BOSTON: Thank you.

MALE

Thanks, Scott.

Our next question comes from Douglas Lee of UBS Warburg.

Are you there, Doug? I guess not.

Our next question comes from Lynn Jenk of ABN AMRO.

LYNN JENK, ABN AMRO: I think that's me. I just have a couple of more

[inaudible] questions.

Sure.

LYNN JENK, ABN AMRO: First, has the NRC told you when they're going to be giving you the final checklist?

I don't believe that they have given us a specific date, no.

LYNN JENK, ABN AMRO: Okay, and when will you have a better sense of when you'll get Davis [inaudible].

You know, what we're saying is from engineering perspective and a human performance standpoint to think that are record control of the company. We believe that we'll be able to support a restart in the fourth quarter.

At this point in time, I cannot hone it down too much closer than that. But obviously, the NRC does have to approve the restart and what's left of that from a timing perspective. [Inaudible] who are working diligently as we can to provide them the information that they need to be comfortable doing that.

So at this point in time, we believe the restart in the fourth quarter is doable.

LYNN JENK, ABN AMRO: Okay, thanks again.

MALE

Thank you.

LYNN JENK, ABN AMRO: It's time. I would like to remind everyone if you would like to ask a question, please press *, then number 1 on your telephone key pad.

[Amitris], if there's one more question, we'll be glad to take if there's nobody else in the queue, we can wrap up.

LYNN JENK, ABN AMRO: At this time, your final question comes from Paul [Rider] of McDonald Investment.

Right. Are you there, Paul?

Yes I am. Have you gotten a definitive ruling on the fair value of pension accounting? Or are you still just assuming worst case.

We're using the fair value accounting method. That's what's reflected in the numbers.

PAUL [RIDER]: Has the IRS ruled that you have to do that yet? Or are still waiting on that. We now have a reply from the IRS. (Inaudible).

So okay, are you going to quantify any severance costs that, you know, people might want to break out and send it to non recurring?

Yes, we will be - what we know, we will.

Will that be third or fourth quarter?

Yes, it will be.

Okay, thank you.

Thank you, Paul. So I'd like to thank everybody again

for their time and interest today. If there's any questions that we

didn't answer, please feel - Reverend Jackson, and Chuck Payner. Please

feel free to call any of us to rehouse for [Trotsky], Tom [Navin] at

first.

We appreciated everybody's time and interest in First Energy. We're assuming they were contact results this quarter, and obviously we're

also hoping that as the year goes on, the market will continue to

recognize the value of our integrated business model and our cash flow and our stable customer organization base. And that they all will be reflected in our valuation.

So we certainly look forward to that. And again, thank you very much for your time and attention. Please have a good day.

Thank you for participating in today's teleconference. This call will be available for replay beginning at 6:30 p.m. Eastern

Standard time today through July the 31st, 2002, 11:59 p.m. Eastern

Standard time.