第一能源 (FE) 2003 Q1 法說會逐字稿

Good afternoon. My name is Lynn and I will be your conference facilitator. I would like to welcome everyone to the FirstEnergy Corp first earnings conference call. All lines are on mute to prevent 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 star 1 on your telephone key pad. If you would like to withdraw your question, press star 2 on your telephone key pad. Thank you.

I would like to turn the conference over to Mr. Kurt Turosky, Director of Investor Relations, please go ahead, sir.

Thank you, Lynn. 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 FirstEnergy Corp are based on current expectations that are subject to risk and uncertainties.

A number of factors could cause actual results or outcomes to differ materially from those indicated by such forward looking statements. Please see our management's discussion and analysis of financial conditions and results of operation included in our most recent annual and quarterly reports filed with the Securities and Exchange Commission for a detailed discussion of these factors.

Participating in the call are Rich Marsh, Senior Vice President and Chief Financial Officer, Harvey L. Wagner, Vice President and Controller, Thomas C. Navin, Treasurer, and Terry Heusen, Vice President of Investor Relations. Also joining us today is Gary Liden, Executive Vice President of FirstEnergy Nuclear Operating Company, who will provide an update regarding our data set to restart activities. I will turn the call over to Rich Marsh.

Thank you, Kurt and good afternoon everyone and thanks for being with us today.

We released our consolidated report to the financial community earlier today and it might be helpful to refer to this as we discuss our results. That report is also available on the investor information section of our corporate website and the address for that is at www.firstenergycorp.com.

Net income for the 1st quarter of 2003, excluding accumulative effect of an accounting change, was $139 million or 47 cents per share. Normalized earnings which exclude the cost of the Davis-Besse extended outage, were 65 cents per share compared to normalized earnings in the 1st quarter of 2002, of 45 cents per share.

During the quarter the Davis-Besse outage resulted in incremental O&M expenses of $36 million and replacement power costs of $52 million. These expenses reduced earnings by 18 cents per share. The accumulative effective accounting change resulted from the adoption of the statement of financial accounting standards number 143, which is accounting for asset retirement obligations. This cumulative effect increased net income by $102 million or 35 cents per share during the quarter.

Including this impact, reported net income was $241 million or 82 cents a share compared to $116 million or 40 cents per share for the same period last year. You may have noticed that last year's one-time items now include an accumulative adjustments related to the removal of our Avon investment for the pending sale classification.

Income statement for 2002 displayed that as a accumulative effect in a change of accounting which was approved at that time by our auditors, Price Waterhouse Coopers. This month, PWC informed us that they revised their prior conclusion and the adjustment should be included in normal operations on the income statement and we are now presenting 2002 results on that basis. There is no impact reported net income and therefore does not represent a restatement of earnings.

During the quarter, earnings were favorably impacted by improved electric gross margins driven by higher distribution deliveries and improved natural gas gross margins due to reduced sourcing costs and lower financing costs due to our continued aggressive debt reduction and refinancing initiatives. These were in turn, partially offset by increased pension and other employee benefit costs, increased Ohio transition costs, amortization and expenses of the Davis-Besse outage. I would now like to turn the call over to our Treasurer, Thomas C. Navin, who will discuss some additional details of financial results. Tom?

Thank and good afternoon everyone. First, I would like to remind you that the additional details of the major earnings variances for the quarter are included on the first page of our consolidated report to the financial community.

I will start with an explanation of our sales and revenue statistics compared to last year. Electric distribution deliveries during the 1st quarter of 2003, were 9.4% higher than in the 1st quarter of 2002. On a weather normalized basis, total through put increase by 5.4%. Sales growth was registered across our services territory and ranged from 8% in Ohio to 14.5% in New Jersey. This increase was primarily due to the cold weather in 2003 compared to the mild weather in 2002 as well as growth in the residential and commercial sectors. Residential and commercial sales in the 1st quarter were up 15.4% and 11.6% respectively.

About half of that growth was weather-related with the remainder attributable to new customers and continued demand from the commercial sector. Industrial sales in the 1st quarter increased 1.3%. Based on recent sales growth in our economic outlook, we expect total electric sales in 2003 to be about 2% over 2002 results on a weather normalized basis. Almost all of this increase will be in the residential and commercial sectors. Industrial sales are expected to remain flat in the 2nd quarter with modest gains possibly later in the year should the economy begin to recover.

Electric gross margin that includes electric revenues less fuel and purchase power increased by $113 million after adjusting for changes in regulatory deferrals and Davis-Besse replacement power costs. This improvement reflects a $390 million net increase in electric sales revenues, partially offset by a $277 million net increase in fuel and purchase power. The improvement in electric gross margin was driven by the signficant increase in electric distribution revenue due to higher sales volumes.

Despite increased generation sales, generation margins were essentially flat compared to the 1st quarter of last year due to higher than anticipated power purchases at prices that is generally exceeded our fixed generation tarriff rate and contracted sales. Generation production during the quarter totalled 16.5 million mega watt hours, 6.6% decrease from production levels of the 1st quarter of 2002. The favorable operational performance of our fossil generation fleet continued while nuclear output was 17% below the level of the prior year due to the Davis-Besse outage and the scheduled refueling outage at Beaver Valley Unit One.

The Beaver Valley Unit One completed its refueling outage and returned to service last night and will be ramping up in power over the next several days. During the Beaver Valley Unit One outage, repairs were made to minor surface cracks on four of the 65 control rod drive mechanism nozzles. These cracks did not result in any coolant leakage and an inspection of the reactor indicated the reactor head is in good condition.

The Perry Nuclear Power Station began its refueling outage on April 5th and is expected to return to service in early May.

Moving now to the performance of our natural gas business, natural gas gross margins rose $21 million compared to the 1st quarter last year. This year we had options in place to cover the increased demand resulting from the cold weather and hence our margins were preserved. You might remember that during the 1st quarter of 2002, unusually warm weather reduced customer demand and led us to sell excess generation gas supplies into a weak market which eroded our margins. Net income from the international operations decreased $12 million as a result of earnings reflected last year when we owned 100% of Avon Energy Partners holdings.

Moving on to operating expenses, the most significant items were pension, other post employment benefits and health care costs which increased by $50 million over the 1st quarter of 2002. As we previously discussed, this increase largely reflects depressed plan asset values and the use of a mark to market methodology for valuing pension plan assets rather than the smoothing method used by many plan sponsors in determining pension expense and changed assumptions for the rate of return on plan assets and the discount rate for plan liabilities.

The total depreciation and amortization expense increased by $19 million. This change is primarily attributable to a $29 million increase in Ohio transition cost amortization and $10 million of deappreciation associated with the Lake Plant in 2003. These were partially offset by an $18 million of lower nuclear decommissioning and depreciation expenses resulting from the implementation of FAS-143 which assumes the licensing period for these units will be extended.

I will now turn the call back over to Rich to discuss our financing activities during the 1st quarter.

Thank you, Tom. Our continued aggressive debt reduction program and refinancing initiatives resulted in a decrease of $47 million compared to the of last year. Specific financing activities completed during the quarter include mandatory retirement of $122 million of long-term debt, repricing of $160 million of pollution control debt and refinancing of $400 million of long-term debt which was achieved in part due to issuance of $250 million of net-add senior secured notes. These actions during the quarter will reduce our annualized financing costs by $20 million.

We were also very pleased with the reception of our recent $325 million Ohio Edison senior secured note transaction. This will enable us to refinance $220 million of long-term debt and also pay down $105 million of short-term debt. These actions will enable us to reduce annualized financing costs by a further $5 million.

Over the remainder of the year, we plan to retire $548 million of mandatory redemptions through the use of our free cash flow. I would now like to introduce Gary Lidek, Executive Vice President of FirstEnergy Nuclear Operating Company, who will deliver an update on our ongoing efforts to return the Davis-Besse unit to service in a safe and efficient manner, Gary?

Thank you very much and good afternoon, ladies and gentlemen. I would like to cover the status of Davis-Besse in terms of completed and ongoing work, our restart schedule and the progress on addressing the safety culture issues at the plant.

First in terms of plant status. We have made very good progress towards the restart in the 1st quarter of this year. As most of you are aware we achieved important milestones including the reload of the reactor fuel in the vessel. Also, last month the completion of the containment integrated leak rate test and that test was very successfully completed.

We have also finished substantial number of major projects at the plant. Some of these are projects that is have gotten a fair amount of notoriety, if you will, including the containment emergency sump strainer, our dome painting project, the installation of our new leak detection system, the decaying valve tank work, reactor cooler tank replacements and our air containment cooler modifications. All these projects are completed and some have been tested and other tests are underway as we speak. We have also done a 100% inspection of our fuel prior to reload and completed the safety system health reviews.

Finally, we completed during the quarter our integrated safety features test which is a comprehensive test covering more than 130 components and that test was successfully completed. From a plant perspective, we are continuing to make excellent progress towards restart.

The second important area concerning the restart of Davis-Besse is safety and safety culture and three points I would like to make there. First of all, we recently completed an employee survey on safety-concious work environment. That survey indicated marked improvement over the survey which was done in August of 2002.

We achieved improvement in 24 of 26 questions asked in both surveys. And in some cases, as much as 20 percentage point improvement. I will give you a couple of examples. 89% of our employees said that management clearly communicated expectations regarding safety. That was 55% last year. 90% of our employees said that first line supervisors addressed concerns brought to their attention that was 61% last year. 76% said the constructively criticism is encouraged versus 53% last year. We continue to see good progress on safety concious work environment.

The second point, in terms of safety and safety culture, is that an independent safety culture assessment was conducted in February by Dr. Sonjia Haber, an expert in organizational psychology. That is completed and has been submitted to the nuclear regulatory commission and that report mirrors many of our own findings from internal reviews we have done on safety culture.

We only found a couple of areas of emphasis that we need to address that were beyond our own assessments. For example, how we approach industrial safety and nuclear safety a little bit differently. The importance of communication between management employees and while it's improving, the progress is not consistent throughout the plant. We continue to work on our safety culture and we are make good progress at the plant.

The third area in terms of safety and safety culture is that we have taken an additional step with the creation of a new department here at Davis-Besse. The organizational development department was announced last week with Randy Fast, our plant manager, moving into the position of director of the organizational development department. Activities there will include training, human performance, safety and communications.

Other organizational changes at FirstEnergy Nuclear are as follows. As we approach the restart of Davis-Besse in accordance with the plan, we have filled the Vice President position at Davis-Besse. Mark Bezilla is the newly named Vice President, formerly the Vice President at Beaver Valley. Mark worked there early in the year and received his original operator's license here at the plant and knows the plant and the people very well.

Follow on moves from that organizational change include Bill Pierce who was our Vice President of oversight for FirstEnergy Operating Company will go back to Beaver Valley where he will be the site Vice President. Filling Bill's place in the important job of Vice President of Oversight, will be Fred Vaughnan, who was our Director of Nuclear Engineering at Beaver Valley. He has had previous management positions at Perry as well. This changes really improve our ability to address the safety culture issues at Davis-Besse and focus our management on a safe and reliable restart.

The next area relevant to plant restart is on the regulatory front. You may recall that a confirmatory action letter was written by the NRC in March of 2002 that provided six specific actions to be completed prior to restart. This is in addition to the O-350 panel requirements. Of those six, we have completed five of those confirmatory action letter items and two of the six have been closed by the NRC and the remaining three have been completed by us and these include the quarantine of the reactor pressure vessel head, completion of the root cause analysis and determination of the extent or condition.

In addition to the confirmation letter finishing now, we have inspection ongoing on the O-350 checklist items at a very high level with 16 active inspections underway. Of course the final item is the NRC approval for restart which comes after we demonstrated we addressed all of these on the checklist and the confirmatory action letter.

Some additional important items, none of which we believe will really impede restart, but that are going on out there is Representative Dennis Cosentage issued a supplement to his original 2.206 petition. We responded to this, and again, is not likely to impact the schedule because it raised no new issues and those it did raise have been or are being addressed elsewhere. It also contained numerous examples of factual errors and opinions.

The office of investigation of the nuclear regulatory commission inquiry is still underway with no official end date at this point. The NRC office of inspector general investigation of the start is expected to be completed late Spring.

Finally the government accounting office, the GAO inquiry began earlier this year has their report expected sometime this summer. Again, none of these items are expected at this stage to impede the restart of the facility.

Over all in terms of schedule, we have reloaded fuel into the reactor and completed the integrated containment testing. We have completed our safety culture assessment and we have three important issues remaining to resolve prior to restart, including the high pressure injection pump options considering replacement of that pump. Resolution of some electrical distribution calculation issues and all of these issues are expected to be resolved in the current schedule.

We expect the next big milestone to be achieved within the next 4 to 6 weeks and as the reactor vessel pressure test and then about a month after that to be ready for restart. And to request NRC approval for restart.

That's a summary of Davis-Besse and I would like to turn the call back over to Rich Marsh.

Thank you, Gary. I appreciate your efforts and those of your team returning Davis-Besse to service.

We continue to project incremental expenses of $50 million in 2003 with replacement power costs of $15 million per month in April through June and $20 to $25 million for each of the summer months of July and August. To mitigate our supply risk, we already hedged our on peak needs for Davis-Besse through the summer months. These purchases were made opportunistically over a period of time at an average price that compares favorably with current forward prices.

As most of you are hopefully aware, Standard & Poor's recently affirmed their BBB corporate credit rating for FirstEnergy and it's seven operating companies. In addition, Standard & Poor's upgraded FirstEnergy's business position rating from 6 to 5. We're pleased that S&P recognized ourstrong free cash flow, aggressive deleveraging plan, reduced supply risk resulting from our hedging activities and lack of merchant generation exposure at arriving at these conclusions and I would also like to note that Moody's affirmed there BAA 2 unsecured credit ratings for FirstEnergy corp.

I would like to briefly discuss efforts on the remaining ownership interests we acquired in the merger with GPU. On April 18, we terminated ownership in [Endurso] through the abandonment of shares in the parent company. GPU Argentina Holdings Inc.

As a result of this abandonment, FirstEnergy will recognize a one-time cash charge of 21 cents per share during the 2nd quarter of this year. This charge is the result of the realization of a 90 million currency translation loss through 2nd quarter earnings partially offset by the recognition of a 27 million gain from the assets abandonment.

FirstEnergy previously recorded a $90 million currency translation adjustment and the net effect of this $63 million charge will be an increase in common shareholder equity of $27 million. The $63 million dollar one-time noncash charge to earnings does not reflect the anticipated income tax benefit of $129 million related to the abandonment which will be fully reserved in the 2nd quarter.

In the period that it becomes probable that these benefits will be realized, net income will be released by $50 million. The remaining $79 million of tax benefits will reduce good will recognized in conjunction with the acquisition of GPU.

Importantly in the meantime, FirstEnergy will benefit from $129 million of positive cash flow through reduced income tax payments. Efforts to divest also continue. These include the 20.1% ownership interest in Avon energy holdings and in ownership generation projects in Columbia and Bolivia. The remaining interest in all of these properties is less than $50 million in total.

I would like to provide a brief update on the New Jersey Central Power and Light Energy Rate case. Hearings ended April 28. The schedule currently contemplates that official briefs will be filed on May 2. The briefs will be filed on May 16 and the administrative law judge's decision will be filed with the board of public utilities by the end of June and new rates become effective August 1.

We were pleased with phase one of the independent accountant's report on the deferred energy balances including their conclusions regarding prudence. The report found the procurement practices were informed and reasonable and the mitigation program was also prudent and reasonable. The report reviewed $436 million of deferred cost and found only $17 million of potential disallowances.

Finally, I would like to give you a brief update of regulatory activities in Pennsylvania. Following the Pennsylvania Supreme Court's denial of appeals of the Commonwealth court's order, provider of last resort rate relief, the commission transmitted the issue of merger savings to the office of administrative law judge for hearings. Also directed Penelect file a petition paper describing the status of a settlement stipulation in light of the common wealth court's opinion and directed all other interested parties to submit responses within 30 days of the filing of the company's position paper.

In conclusion, let me say I am pleased with our 1st quarter results. Although Davis-Besse continued to dominate news coverage, please don't lose sight of the progress we continue to make in successfully executing the retail strategy. In the quarter, we reduce actions by 20 million and further strengthened our credit profile of $122 million of long-term debt.

We continue to operate the first generation fossil fleet at the capacity factors first achieved in 2002 and reduced exposure to foreign operations through divestiture of [INAUDIBLE].

Finally, as Gary described we made substantial progress territories Davis-Besse. For 2003, guidance remains at $3.35 to $3.55 cents per share excluding the cost of the Davis-Besse outage and nonrecurring charges such as the [INAUDIBLE] abandonment that will be recognized in the second quarter. We very much look forward to extending the gains we made during the first quarter and very much appreciate your continued interest in FirstEnergy.

Thank you very much for taking the time to be with us on this call today, I realize this is a very busy earnings release day and we appreciate you joining us. I would now like to ask Lynn, to open the call for analysts and investors questions. Thank you.

At this time I would like to remind everyone, in order to ask a question please press star then the number 1 on your touch tone telephone.

We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Paul Fremont with Jefferies and Company

Thank you very much. Two questions really. Is you talked a little bit about the extended life on the nuclear plant. Can you quantify the annual benefits you would expect to get from the lower depreciation on the nuclear power plants and the second question relates to the [O-tab] portion of your plan. Are there any contemplated changes in the [O-tab] portion of your plan and given the fact that that plan I think is voluntary as I understand it.

Let me answer the second part of your question first and I will have Harvey L. Wagner answer the first part. We are continually assessing all of the benefit programs for active and retirement employees and made changes in the medical plan this year.

It's very likely down the road that further changes could be made at some point in time. You are right in that we have always been very specific to note that post retirement benefits are not vested. They can be changed by the company at any time

As a result of that, the liability could be changed in the future. Obviously portions of the impact that you are seeing this year on the [OPEB] Liability changes and so forth. You are exactly correct in your assumption?

The annual effect will be somewhere in the range of 20-25 million dollars of a reduction in expense.

Thank you.

Your next question comes from Paul Ridzon of McDonald Investments.

I wanted an update of whether the Lake Plants are still on the table and you are pursuing that or just a status update there and an update on the realization of merger synergies.

Let me address the Lake Plant question first. We are continuing to own and operate the units as if they will be a part of the fleet for sometime to come because we believe they will be so we don't have an active sales process in place on the units right now.

In fact what we have done with the units is inverted or transitioned them to be an intermediate load following cycling unit that help us operate our base load units more efficiently by allowing them to design as base load. Those plants are performing a valuable role for us and you are starting to see the benefit of that in terms of the increased availability and reliability in decreased O& M cost of our fossil generation fleet.

Obviously although we are not pleased at the time the sale did not go through, we are making the best use that we can in getting benefits from that.

Are you using the plants more as base? I didn't follow that.

We are using the Lake Plant portfolio to follow customer load. They tend to cycle up and down in response to the changing demand pattern. Prior to that, we had really fulfilled that function more through the use of larger base load units.

This allows us to run the larger base load units in a more thermally efficient manner, running more or less wide open all the time. Cycling up and down to chase demand through the use of a Lake Plant. That's a change in how we viewed the portfolio. It's consistent with the changes we made in the fossil generation fleet and it results in efficiency and decreased O&M of the larger base load units.

It has been a great program and you see the success of that when you look at the great job our fossil generation fleet is doing. What was the second part of your question?

An update on synergies

We continue to be on track in terms of achieving and reaping merger savings and SSAI. The shared services cost initiative. We have not cantified on an actual basis because they are occurring throughout the operation.

I believe in the distribution side of the business as well as the information technology side of the business. It's the target we set out this year, we are ramping up on the merger savings towards the $150 million target. This year we were targeting about $110 million on that way to ramp up towards the $150 million. With respect to the SSAI reduction savings, the target was about $90 million.

Last year we quantified the SSAI cost reduction to about $55 million. 35 million pick up this year on the shared services initiative. On the savings again I'm saying it's about $110 million of the 100 originally identified as the long-term savings target.

You are on track to achieve those?

Yes.

Just a follow-up with regards to S&P. It's good news the change in the business position. I assume you kept them apprised of the shifting Davis-Besse schedule and you are comfortable with that?

S&P follow that is closely and we have frequent communications with that and other issues. You are correct.

Thank you very much.

Thank you.

Your next question is from Steve Fleishman of Merrill Lynch.

Hi, gentlemen. A question for Gary. You can give specific scenarios with respect to the how you addressed the injection pumps. And this timing of your pressure test, does that assume you replace or fix the pumps before the pressure test or is there a risk that could be delayed and you have to take those actions before the pressure test? Could you scenario analysis the whole thing for us?

I can do that and I will be brief and not overly technical here so bear with me. These are the high pressure injection pumps. We have over the past several weeks explored many, many options for these pumps. The thing we know for sure is we will not use the pumps in plant operation as they exist now. We are down to two options that we are exploring.

The first of those is a replacement of the pumps with a different design. The second option is to modify the existing pumps and to add additional filtering capability so the hydrostatic bearings will function just fine with additional filtering of the water.

Those are the two options that are on the table right now, Steve. Both of those options fit within the schedule window I mentioned earlier in the call. Both of those options at this point support the pressure tests as well as the in service state. The distinction and final decision on that is really not -- we haven't decided that yet. It will come down to interactions with the nuclear regulatory commission as well as obviously the over all impact, cost, schedule, and safety. All those things rolled into one picture.

We are having dialogue right now with the NRC in terms of being able to perform the pressure test with the existing pumps. The pumps have been installed and reinstalled. We took them out to do maintenance and they have been reinstalled and tested and they operate just fine. We expect to do the pressure test again within the next 4-6 weeks with the existing pumps.

We will need a technical specification approval from the NRC to be able to perform that activity. We are in discussions with them on that right now. We've got several success paths here and over all, working hard to ensure there is no schedule impact, but also being sure we have the best possible fix, if you will, from a safety perspective.

Okay so just to clarify, under either scenario you believe an early first part of summer restart of the plant is doable, but for this pressure test you assume you do not do either of these actions before you complete the pressure test?

That's right.

To the degree the NRC does not concur with that, that would create a little bit of a delay in terms of the pressure test, but I guess in the end game it's still early summer?

That's right, Steve. We are tracking over all and we would have to shift work around. It depends on which of the two alternatives. We have a meeting with a vendor this afternoon. We are working through that and it depends on which of the alternatives we select in terms of the impact.

I think we are, over all, tracking. The other thing I would be sure that everybody understands is that there other work activities and I mentioned some of the other projects we are working on. The electrical distribution design projects and other things.

At this point the high pressure injunction pump is I guess I would say concurrent parallel path with other activities as opposed to, you know, the long lead item, if you will.

Okay. Totally unrelated question. You mention, Tom, in the quarter that sales were up a lot and part was weather, but it seemed like you indicated even the nonweather-related sales growth was pretty high. 2% growth I guess for the year. Is that in line with your current plans or above or-?

This is Rich, Steve. I think the growth like you say that we experienced in the quarter that was not related to the cold weather came as a bit of a surprise. It varied cross the territory, but particularly as you moved East. I don't know that I have a specific explanation of why that is.

It was a nice trend and hopefully something you will see going forward.

You are not counting on that as of now?

It's not a specific element of our earnings guidance, no.

Okay. Lastly we will start getting more information on this New Jersey rate case. When will you start characterizing when that fits in with your guidance and plan?

I think when we issued our original earnings guidance which remained unchanged, we tried to make that inclusive of what we thought would be a reasonable out come for that case. That's how we approached that issue.

Okay. Thank you.

Thank you, Steve.

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

Good afternoon. I apologize if I missed this because I was hopping around, but did you go over where you stand from a hedging standpoint on Davis-Besse and how far out you hedged and when you layered in the hedges relative to the way the market has been.

We talked about it briefly and we can talk about it in more detail. We fully hedged summer months and are on peak position. Even though we expect the unit will be come think back online, we did it from a risk management prudent standpoint.

The mark to market is positive and we were able to buy those opportunistically at an average price less than what the forward curve is reflecting. If expectations start to come true and it comes back online, be able to deploy the power and make a few bucks in doing that. The summer months are covered from an on-peak perspective.

Beyond summer months, we have additional power we secured for Davis-Besse or other purposes from a risk management standpoint. We look at this not on a plan specific basis, but supply planning portfolio. When we are able to buy power at a reasonable price, we do that from a risk management perspective.

We are very much focused on having the unit come back on as Gary said within the next coming weeks and months. We are looking forward to that. Our summer position is covered and we were able to do that at good prices.

Are you making sure if the unit were off, at least capacity matched up. Is that basically through August that you are covered?

We are fully covered through that period, yes. When we say summer months where you get the higher prices, that's where we focused on July and August. The unit will be back on before the months happen, but those are covered.

And just over all as we talk about a lot of different data points and the restart data that moved around, what time frame would you put your high degree of your confidence interval as far as the plant getting restarted. It was a point where it used to move around quarters. Is it down to months at this point?

We definitely think we are seeing the light at the end of the tunnel. What we have been trying to focus on is a week or two, way or the other it's not that meaningful. What we are focused on is making sure we get the job done right the first time.

We believe by doing that we will demonstrate that we are ready to restart the plant to the NRC. We are close to the end of the process. We can't say this day or this week, but what we are focused on is getting it done right. That will pay the highest benefit.

I might be able to add to that if that's appropriate. Scott, I think the key to the answer of this question is as you go through the extended shut downs and several of us had experience at these things, the beginning of this kind of a process is where the scope is uncertain because you always have to be able to answer the question what else is out there.

Besides just the reactor pressure vessel head situation. Our building block program was designed to do a lot of discovery. The course of that discovery scope gets added and added and added. Modifications to the plant get added and analytical work gets added. Where we are now is we understand what we got left.

It's reasonably bounded and it's I would say a medium-sized list. It's not real long and not 5 things, but when you get to the point where you have the scopes understood and it's a matter of marching through it and doing it well and focusing on finishing so you have everything done well and from a safety standpoint particularly. From the plant perspective, it's pretty well bounded at this stage.

The other important issue is the safety culture and never has been a situation like this, but I will tell you we are very heartened by the independent consultant report by the surveys that have been done. We think we are making good progress on that as well. We do see this in the finishing phase here at this point.

Another question just on the -- and thank you very much, on the O&M, just back in December when you talked about what the impact for the year of the pension was going to be about 30 cents or so and O&M offsetting that at 25 cents in the form of cost savings. Trying to see, does that fall even 3 throughout the year or is there a mismatch as far as when those things ramp across the year?

The cost savings will ramp up during the year. They will increase each quarter through the programs where the pension cost is more of a levelized impact.

That's why in this quarter we see more of the impact of the pension versus the O&M savings. That will start to narrow the gap as we move throughout year?

That's true.

Is that the way to look at it?

Yes.

One last thing. Obviously there has been discussions from regulators and parties about post transition in Ohio and I know there hasn't been a lot of formally drafted on that subject yet. But I was curious if you could talk about anything that you have been doing just as far as not even necessarily from a regulatory standpoint, but risk management dealing with managing risk in that time period.

Let me try to address that, Scott. Certainly part of your question stems from the comments that the chair unof the Ohio commission made at an RRA meeting in New York a month or more ago now.

He said that from his perspective he had concerns about rate shock at the end of the scheduled transition period in 2005 and expressed his view that he might be interested in exiting the rate freeze and if so he would like to get the program done this year.

He also mentioned it would not have to be a one size fits all solution in Ohio and there could be a different solution for each company. That sort of expressed their perspective on what they are seeing from the commissions by the way we view this issue post 2005 is obviously the company's intent to deploy that generation that's going to be freed up at the end of 2005 in Ohio when the [polar] obligation ends. The objective is to deploy that wherever we can realize the highest revenues for it.

It could be Ohio potentially or Pennsylvania where we have the polar obligation through 2010 at a price of about 4.6 cents per kilowatt hour. It could be in New Jersey or elsewhere. What we will be looking at is stacking up the options and where we can figure out where to deploy that power to maximize revenues. What we will not do is wait until the end of 2005 to make that decision.

We need to act soon from a risk management perspective. We will put all those things on the scale and see where events unfold and where we see revenues received for the generation.

Thanks a lot.

Thank you, Scott.

The next question is from Vic Taken at Deutsche Asset Management.

Thank you. The comments, is it fair to assume now we are talking about mid-July to August, the restart?

Gary, do you want to respond to that?

I think what I said before is that the big milestone is the pressure test and as we talked about that, I think it was in the next 4-6-week time frame and about a month after, or longer, maybe 4-6 weeks after that would be the restart.

Again, the thing I didn't mention which was important and I think you are aware of that, the restart is contingent to the NRC inspection and approval.

I understand NRC has to give you the green light, but I guess you won't be ready for another eight weeks. That's what you are saying.

That's about right. I'm hedging this a little bit because the published schedule here is more aggressive and we are working through that.

And the second question is regarding the debt reduction and the debt cost reduction. By the end of this year, where would your debt to equity be and what might be the debt coverage ratio might be running rate at the end of the year.

This is Thomas C. Navin. We project based on the redemption that will take out with cash. That is $670 million for the year.

Also we have also assumed that we will be able to move forward with a follow on securitization transaction in New Jersey which would enable another up to $400 million of debt to be treated as off credit by the rating agencies which would combined with the mandatory redemptions take the debt to total down to 61%. I believe the FFO coverage ratio for the end of the year is at about 3.1 times.

So you don't see any likely slippage on your debt ratings then?

No. Based on our ability to pay down the debt, I do not.

Thank you.

Thank you.

Your next question comes from Paul Patterson of Glenn Rock Associates.

Good afternoon. How are you.

All right.

Just a question on the safety culture survey they had, how do those results compare to an industry average?

Paul, that's a good question. There is no industry standard on this kind of a survey. There is a lot of company that is do these, but what we are looking for here is progress and as I indicated we got substantial progress. Where we want to be on this is continue to work it and get the numbers in the 90-95 percentile in terms of people's confidence.

Those few examples I gave you where we hit in the upper 70s and 80s as opposed to 50s and 60s where we think real good safety culture looks like is to be in the 90s based on our numbers what we see out there. Again this isn't like an industry standard and survey of any sort. That's what we are shooting for.

On Beaver Valley, is the NRC playing a role with respect to that and do you think you will replace the head there?

Long-term there will be a head replacement. That's out there and we haven't nailed it down. It will be done consistently with the steam generator replacements also in the plans if you will.

As we have done at Davis-Besse and other utilities have done, we are doing detailed inspections on the RPV head both on top of the head and under the vessel. The Beaver Valley head is in good shape. There certainly is no driving force at this point in the near term to replace the head although everyone is looking at head replacements as you are aware long-term particularly.

Thanks a lot and then I guess what I wanted to ask and I know you don't give weather guidance, but I want to get a better picture on this. Steve asked the question on this. What are you seeing in terms of normalized growth. At 9% sort of increase in sales, do you have an idea of how much of it might be weather driven or a ballpark feeling we might get for that?

Roughly about 5.5%. That would be attributable to weather.

Okay and finally just a question, on page 4. You guys have a break down between regulated and competitive et cetera. There is electric sales about $413 million and the expenses for performed power seem like they are $472 million which is a little surprising. What caused that or what is that about? Can you give a better picture as to what caused that? You paid more for power than what you sold it for.

This is Harvey L. Wagner, the revenues you see from the competitive unit essentially are coming from an inner company power transaction. What you are really seeing there is the fixed rate coming from the utilities to the service unit below what the competitive unit had to pay for power on the market.

Okay. How did you make up the difference? How did you make up the difference? I guess on the regulated side?

The services segment is supplying generation service to the customers in Ohio that haven't shopped and Pennsylvania and New Jersey. Actually I want to draw you to line 8 where it says internal revenues. It's the $559 million that is coming from the regulated units to the competitive services unit.

That explains it.

It's getting about a billion dollars in revenue associated with sales. Electric sales in the quarter.

Thanks a lot.

Thank you, Paul.

I would like to remind everyone if you would like to ask a question press star 1 on your telephone key papad. Your next question is from Daniele Seitz of Salomon Smith Barney.

I was wondering, do you have a cost for this pump that you think of possibly performing or do you have them already and also how long does it take to install them assuming that you get the decision asking for it?

The replacement pumps have been performed and the purchase price for those pumps was in the range of about 400,000 each.

It's not the cost?

The cost involved which we are still working on the est although we believe it's in financial guidance is really the design energy and installation cost as opposed to the pumps themselves.

These are not new pumps, but they are perfectly useable that we were able to get out in the market from one of the pump manufacturers. The installation time that we estimate will be after the pressure test is in the range of 2-3 weeks.

That's my other question. And I was wondering also is there any green light eventually on the soft issues like the culture side. Is there some sort of test that you think of going through that will really clinch it or is it all of these results are eventually reviewed by the NRC and they look at it? There is nothing more you can do at this point.

We are also working on our culture. The best way to characterize a green light the NRC is doing inspections as we speak in this area. They have a team of experts in here not this week, but last week. They will continue inspections.

So the results of that inspection module if you will which is part of the 0350 checklist would have a bearing on the NRC's decision to restart plant.

Eventually there will be comments on mark that will really say you are ready to start. It's not really that obvious.

It will, but let me add that they are looking a lot at the work we are doing. We are doing a lot of surveys and assessments ourselves. While I can't speak for them, in many helps they look at the processes we have to ensure we have the right culture for restart. It's a process between us and the NRC really.

Thank you.

We are approaching the one-hour mark so why don't we take one more call if there is one.

The last question is from David Grumhouse from Copia Capital.

Two quick questions for you. One, on this ruling by the Supreme Court and the remanding of the merger savings in the Minnesota law judge and the position paper you have to file, what is the likely out come on that? Is the settlement going to take the form of concessions by you guys or are you hoping it will go away? How is that likely to play out?

We will have to see, but the major party to the case originally we are satisfied with the sharing of synergies through an extension of the distribution rate freeze. I think everybody viewed that as appropriate. Please remember the common wealth court's order did not really make a judgment regarding the of synergies.

It was more towards the lack of documentation or adequate record in terms of supporting how the synergies were shared. Hopefully we will go through the process and be able to come to an out come that's reasonable. I think all the major parties need to believe that the type of rate sharing we had make sense and it's appropriate.

Thanks. Next question is did the prices this winter have a meaningful or material effect on switching up or down?

Customer switching?

Yes.

They did not.

They are about the same as they were at year end?

No meaningful changes.

Thanks.

Thank you very much for being with us today. I know this was a busy day for earnings release and we appreciate you making time to be with us.

We look forward to keeping you updated regarding progress with Davis-Besse and FirstEnergy. Thank you very much and please have a good day. Take care.

This concludes today's FirstEnergy Corporation's 1st quarter earnings conference call. You may now disconnect.