第一能源 (FE) 2007 Q2 法說會逐字稿

Good afternoon. My name is Cheryl and I'll be your conference operator today. At this time, I would like to welcome everyone to the FirstEnergy Corp. second quarter earnings conference call.

All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer period. (OPERATOR INSTRUCTIONS) Thank you.

It is now my pleasure to turn the floor over to your host, Mr. Kurt Turosky, Director of Investor Relations. Sir, you may begin your conference.

Thank you, Cheryl.

During this conference call we will make various forward-looking statements within the meaning of the Safe Harbor provisions of the United States Private Securities Litigation Reform Act of 1995. Investors are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of FirstEnergy Corp. are based on current expectations that are subject to risks and uncertainties.

A number of factors could actual results or outcomes to differ materially from those indicated by such forward-looking statements. Please read the Safe Harbor statement contained in the consolidated report to the financial community which was released earlier today and is also available on our Web site under the earnings release link.

Reconciliations to GAAP for the non-GAAP earnings measures we will be referring to today are also contained in that report as well as on the investor information section of our Web site at www.firstenergycorp.com/ir. Thanks.

Participating in today's call are Tony Alexander, President and Chief Executive Officer, Rich Marsh, Senior Vice President and Chief Financial Officer, Harvey Wagner, Vice President and Controller, and Jim Pearson, Vice President and Treasurer, and Ron Seeholzer, Vice President of Investor Relations.

And now I will turn the call to Tony Alexander.

Thanks, Kurt. Good afternoon, everyone.

I'll begin by highlighting our operational performance during the quarter and then ask Rich to review our financial results and provide an update on regulatory matters.

I'm pleased that we continued our progress in the second quarter in achieving our key goals for the year, including realizing the full potential of our generation assets, further enhancing our distribution reliability, pursuing continuous improvement in all aspects of our business and delivering consistent and predictable financial results.

During the second quarter we recorded earnings on a GAAP basis of $1.11 per share and our normalized non-GAAP earnings of $1.13 per share were 19% higher than the same period last year.

Our generation fleet continued its outstanding performance with a second quarter output record of 20.4 million-megawatt hours of electricity, a slight increase over the record established in the same quarter last year. The increased output resulted from the generation [uprights] we've implemented over the last year as well as the strong operating performance of our fleet.

Since the second quarter last year, we've added 93 megawatts of nuclear capacity through upgrades at our Beaver Valley and Davis-Besse, and 50 megawatts of base load fossil capacity from the upgrade of Unit 2 at the Bruce Mansfield plant.

The favorable fossil performance during the quarter was led by our Mansfield plant which is our largest generating facility at 2460 megawatts. That plant produced more than 5 million-megawatt hours of electricity in the second quarter and posted a capacity factor of 94% during the period.

With our strong performance during the quarter, we continue to pursue our goal of exceeding last year's record generation output of 82 million-megawatt hours.

As part of our environmental compliance strategy, we recently announced plans to install an Electro-Catalytic Oxidation, or ECO System on Units 4 and 5 of our R.E. Burger plant. ECO is a multi-pollutant control technology developed by Powerspan Corporation that reduces sulfur dioxide, mercury, other combustion gases and fine particulates.

We originally planned to install the ECO System on Unit 4 of the Bay Shore plant but have determined that deploying this installation at the Burger plant will result in 100 additional megawatts of scrub capacity as well as a better fit with the coal procurement strategy for both plants.

Design engineering for the new ECO System will begin later this year with operation expected during the first quarter of 2011. The incremental capital costs associated with this change will be about $38 million.

Moving on to our energy delivery business, we continue to improve on the favorable system reliability trend that we started last year. On a year-to-date basis, we've realized a 7% reduction in the frequency of customer outages and a 13% decrease in outage duration.

This improving trend was facilitated by the capital investments we've made in our distribution systems over the last several years. It's also a reflection of our talented and dedicated employees who helped us achieve these positive results while also improving our safety performance.

Through the first six months of the year, our companywide safety statistics are on track to meet or exceed the record-breaking performance established in 2006 when we achieved an OSHA rate of 0.96. That represents less than one incident per 200,000 hours worked which placed us in the top decile of our industry.

I'll now turn the call over to Rich to discuss our second quarter financial results.

Thank you, Tony. Good afternoon, everyone.

As I review our results it might be helpful for you to refer to our consolidated report to the financial community that we issued earlier this morning. Let's get started.

Earnings on a GAAP basis in the second quarter were $1.11 per share compared to GAAP earnings of $0.92 per share in the same period last year. Excluding special items, normalized non-GAAP earnings were $1.13 per share compared to $0.95 per share in the second quarter of last year.

This year's normalized non-GAAP earnings exclude the impairment of nuclear decommissioning trust securities that reduced earnings by $0.02 per share. The 19% improvement in this quarter's non-GAAP earnings resulted largely from favorable operating performance, strong sales, and lower pension and post retirement benefit costs.

Specific positive earnings drivers included a $0.25 per share improvement related to higher generation revenues from a 3% increase in generation sales, as well as higher retail and wholesale prices, a $0.04 per share contribution from distribution delivery revenues, reflecting a 16% increase in heating degree days, and a 39% increase in cooling degree days compared to the same period last year as well as our normal sales growth.

A $0.06 per share reduction in other post retirement benefit costs due to retiree healthcare design changes and lower pension expense following the $300 million contribution to the pension plan in January. A $0.05 per share increase investment income from our nuclear decommissioning trust and corporate owned life insurance. And the $0.07 per share benefit related to the reduction in common shares from the accelerated share repurchases of 10.6 million shares in August of this year, I'm sorry, in August of 2006, and 14.4 million shares in March of this year.

Factors that partially offset these favorable impacts included a $0.09 per share increase in purchase power expense due to higher market prices, a $0.05 per share reduction due to the distribution rate decrease at our Met-Ed and Penelec subsidiaries that was effective in January. A $0.05 per share comparative reduction in earnings resulting from the deferral of incremental first quarter of 2006 Met-Ed and Penelec transmission charges in the second quarter of 2006.

A $0.03 per share increase in depreciation expense resulting from our growing asset base. $0.03 per share increase in general taxes due to higher gross receipts and kilowatt taxes as well as higher property taxes, and a $0.05 per share increase in financing costs primarily attributable to higher short-term borrowings to temporarily fund the $900 million accelerated share repurchase in March and the $300 million pension contribution in January.

We recently completed several important financing transactions and I'd like to update you on those. On July 13, FirstEnergy Generation Corp., our unregulated fossil generation subsidiary, completed the $1.3 billion sale and leaseback of its 779-megawatt interest of Unit 1 of the Bruce Mansfield plant.

This is a 33-year lease and the net proceeds of $1.3 billion were used to repay short-term debt that had been funding on an interim basis the accelerated share repurchase and the pension contribution that I just mentioned. Our generation company will continue to operate the plant and remains entitled to its full power output.

The transaction is currently classified as a financing and will become an operating lease following our satisfaction of certain registration obligations in regard to the associated debt which we're pursuing. The gain generated by the sale of Mansfield 1 enables to use $830 million of tax loss carry forwards most of which would otherwise have expired at the end of 2007.

The financing aspect of this transaction results in a benefit equivalent to borrowing the $1.2 billion of after-tax proceeds for a term of 33 years and an interest rate of about 3.6%.

On May 21, Jersey Central Power and Light issued $550 million of senior unsecured notes. This offering included $250 million of 5.65% notes due 2017 and $300 million of 6.15% notes due 2037. The proceeds were used to redeem all outstanding JC P&L first mortgage bonds, repay short-term debt and repurchase common stock from FirstEnergy.

For the second half of the year our financing plans include the expected issuance of about $600 million of long-term unsecured debt at our operating companies, primarily to fund debt maturities and repay short-term debt, and the continued transfer on an opportunistic basis of about $425 million of the remaining $700 million of pollution control debt from our regulated utilities to our unregulated generating companies.

Now let's turn our attention to a few pending regulatory matters. On June 7, our three Ohio utilities filed base distribution rate cases with the Public Utilities Commission of Ohio. Yesterday, the Company submitted an update to the filing containing actual results for the period March through May of 2007, as well as asset and liability balances as of May 31.

Through cost and increase in annualized distribution revenues in the case totals $322 million and that amount is need to recover expenses related to distribution operations as well as cost deferred under our previously approved rate plans. The new rates would be effective January 1, 2009 for Ohio Edison and Toledo Edison customers and are expected to be effective in May 2009 for (inaudible) electric customers.

Although not part of the rate case, the companies will reduce or eliminate their regulatory transition charges, or what we call RTC, concurrent with the effective dates of the new distribution rates. This will reduce annualized revenues by approximately $594 million and when combined with the proposed distribution rate increase, customers will actually see a net reduction of $262 million, or 5.7% on average on the regulated portion of their bills.

Although the PUCO hasn't yet established the case schedule, we estimate that the staff report will be issued sometime in fourth quarter followed by evidentiary hearings in late 2007 and we would then expect the final order would be in the March 2008 time frame.

Our three Ohio utilities also recently filed an application with the Commission requesting approval of a comprehensive supply plan to provide generation service to customers beginning January 1, 2009. This would use a competitive bidding process to supply those customers who choose not to purchase electricity from alternative suppliers.

Under our proposal, suppliers would bid for portions of customers supply needs in tranches of approximately 100 megawatts each. A descending clock format would be used with the bid price per tranch declining until there are just enough bids to supply all customers. Individual bidders would be limited to no more than 75% of the total customer load.

To minimize our customer's exposure to price volatility in the electric markets, the process would average the results of multiple bidding sessions conducted at different times during in the year beginning in 2008. Following the 2008 bidding process, multiple bids would be held annually for one-third of the total customer supply for a 36-month period with the resulting prices being averaged with existing prices to minimize volatility.

The companies offer two alternatives to structuring the bids: Either by customer class with residential small business and large business customers being bid separately, or by a slice of system approach, that would combine all customer classes into tranches representing a portion of the total customer load. In either case, rates would be established by customer class based on the bidding results.

The proposal also includes an option for the PUCO to phase-in generation price increases for residential tariff groups that would experience a change in their average total price of 15% or more. This deferral would be available for 2009 and subject to a cap of $150 million. The deferral would be paid back by our residential customers over three years through a non bid passable charge.

To provide sufficient time to conduct the competitive bidding process, the Company's requested that the Commission issue an order on the plan by November 1. The Commission has scheduled to technical conference on August 16 to allow interested parties an opportunity to better understand the filing.

Let me conclude my comments today by affirming our non-GAAP earnings guidance for the year 2007 of $4.05 to $4.25 per share. For the first two quarters of the year, cumulative normalized non-GAAP earnings were $2.01 per share.

Earnings during the second half of the year, exclusive of any special items, are expected to be allocated approximately 56% to the third quarter and 44% to the fourth quarter. And this allocation reflects the impact of the Perry plants 26-day maintenance outage that was completed on January 24 to replace a motor in the reactor recirculation system, as well as the miler than normal weather we experienced during July when cooling degree days were about 17% below normal.

The same quarter was a successful period for the Company in achieving our financial and operational objectives and I expect the second half of the year to be just as productive.

We appreciate your time today as well as your continued support of FirstEnergy. And I'd now like to ask Cheryl to open the call to questions from analysts. Thank you.

(OPERATOR INSTRUCTIONS)

Your first question is coming from Daniele Seitz of Dahlman Rose.

Thank you.

I was wondering if you intend to do some additional share repurchase over the next year or so or your program is pretty much done now?

We haven't given any guidance or any thoughts, Daniele, beyond the existing program that we completed earlier this year so we haven't really said whether we were or were not going to contemplate any other share repurchase programs.

But it's not out of the question as far as over the next 12 months, do you?

We haven't said that we weren't going do it. We haven't said that we are going to do it.

Okay. Great. And just a detail.

The pension contribution for the impact for 2007 would be roughly how much do you anticipate for the year?

The pension contribution in terms of reduced pension expense?

Yes.

It'd be on an annualized basis about $0.05.

Thank you.

Sure.

Thank you. Your next question is coming from Greg Orrill of Lehman Brothers.

Hi, Greg.

How you doing, Rich?

Good. How are you doing?

Good.

Was wondering if you could quantify with the impact of the Perry, the recent Perry outage was? And then kind of remind us of the dividend policy. The -- you're talking about the Perry outage to replace the recirculation pump? The one to replace the motor.

Yes. It was a 26-day outage. I guess the general rule of thumb that we often apply to nuclear outages is for purchase power costs roughly $1 million a day. This is a larger than normal, obviously, nuclear plant so I would expect it to be somewhat higher in this outage was in July, although, the month overall was mild.

I mean it was still the summer period so I would think something north of $1 million a day is probably the appropriate number that we would expect to see from this outage. Minimal, very minimal O&M cost related to that so most of the impact was from the purchase power side.

I'm sorry, and the second part of your question?

Dividend policy?

Sure.

I think the last, yes, dividend policy.

Sure. Obviously, very important element of the thinking of both the board and management, something we that review on a quarterly basis. I think everybody's aware that at the beginning of the year we increased the dividend over 11% in order to show our commitment to that and that remains a very important component of our going forward uses of cash over time and the board will continue to consider that each quarter.

Great. Thank you.

Thanks, Greg.

Thank you. Your next question is coming from Greg Gordon of Citigroup.

Thanks.

I'm hoping you can put something in context for me with regard to Pennsylvania. The PPL utilities did their first bridge auction recently, began sourcing power fiscal year 2010 to customers and that price was, depending on how you look at it, in the low to mid 90s for the generating companies that won that bid.

Can you help us understand as we look at your 2011 situation, how much load for FE actually goes to market that's currently being served by FirstEnergy Services and if you were pricing in this market looking at that auction, can you give us a sense of what the price might be today?

First part of your question's easier than the second part. Total load for our Pennsylvania companies, for Met-Ed and Penelec it's about 30 million-megawatt hours. FE serves about two-thirds of that in 2010 we're off the [grey].

In terms what the price might be there, your guess is as good as ours. I think we see more data points as these auctions continue. Obviously, the PPL auction was another interesting and relevant data point I think.

So let me ask the question a different way. What's the contract price going to be in 2010 in rough numbers?

$41.50, yes. If you're talking about the contract between FES and the companies it's $41.50.

And PPL priced in the low to mid 90s. So I guess when you look at your plants relative to their plants and your load relative to their load do you see wider basis differential? Do you see, you know, you just price off a much different hub?

Allegheny Energy, for instance, said that the comparable price for them was around 75 because their plants are all the way in Southwest Pennsylvania. I'm wondering contextually as we look at your current contract price and we look at clear differences between your portfolio and your load versus their portfolio and their load, if there's any way we can triangulate around an approximate comparable number?

I certainly know where you're going with your question, Greg, I'm not sure if I can give you a much better answer in terms of specifically what the price might be, but if you look at projected demand growth and relative limits or relative options for new load coming on, I guess our feeling would be that the fundamentals seems to increase the prices would remain relatively high over that period of time. But specifically what they may be within that pricing point, whatever, I just can't go there right now with any degree of accuracy.

Tony, do you want to add anything to that?

No, only that it's pretty clear in 2011 we'll no longer have to supply that requirement under the existing contract and, therefore, that power can be placed into the market. Whether it's placed into the Ohio market or the Pennsylvania market will depend on where the price points are from our standpoint.

Okay. Thank you, guys.

Thanks, Greg.

Thank you. Your next question is coming from Paul Fremont of Jeffries.

Sort of looking out into the future and maybe to the 2011 that you're talking about, there seems to be an awful big price differential right now between the Pennsylvania market and the Ohio market, especially given the 2008, 2009 TJM auction results.

Is there an expectation that that price gap will ultimately close to the construction of transmission lines or the use of existing transmission lines to bring power from, let's say, Ohio into Pennsylvania?

I'm not sure there's a relevant price point in Ohio at this point since there's not been any retail auctions for several years in Ohio since the auctions we did a few years back. So I'm not sure it's even comparable there.

Certainly, different companies have talked about different transmission options between [Miso] and PGM and so forth, whether any those will happen or what time frame, Paul, I really don't know. Typically there is somewhat of a spread of $10 per megawatt hour. It's a number that gets banted around sometimes, but how that will persist over time yet to be seen.

And the second question I have is, I guess earlier on a conference call you sort of expressed that the Governor of Ohio has a fairly high priority energy in terms of new legislation. Can you comment at all as to how his proposal might deal with either an extension of your existing plan or going to market?

Well, I don't think, the Governor's, Paul, this is Tony.

The Governor laid out some principles several months ago that are fairly consistent with what we have filed. I think the Governor is particularly interested in conservation, energy efficiency and we are awaiting more definitive information from his staff and from him concerning which direction he'd like to move in with respect to those kinds of matters.

Thank you.

Thank you. Your next question is coming from Charles Fishman of A.G. Edwards.

Good afternoon.

Hi, Charles.

Following the, with the competitive bid process you'll have a hearing, I believe, on the 16th.

Technical conference.

Technical conference. And then after that briefs, reply briefs, is that correct?

I think we scheduled that.

Yes, the procedurally schedule hasn't yet been established, Charles. (Inaudible) will be laying all that out.

Well, is it still, I know at one time I know your strategy was to avoid any kind of formal testimony. Is that still the strategy?

I'm not sure I understand.

Well, would there be like, you know, in a traditional rate case you'd have a lot of filings, a lot of testimony. And there's obviously not the, really the technical issue or not necessarily technical, but the quantity of data, obviously, isn't there with respect to the competitive bid filing.

So is this a process that can be expedited and reach a decision pretty quickly so you can keep on your schedule to actually bid that first tranch this year?

Well, again, we've asked for a Commission order in November of this year and that's going to require a movement through the process at a relatively good pace. I think the technical conference as a starting point is probably the way to help facilitate that as we try to get the questions of people answered in a more, kind of deal with the more technical aspects of it so we're not chasing necessarily issues that can be resolved pretty easily just by face-to-face conversation.

Okay.

Are there any big industrial groups or other user groups that are against the competitive bid process at this point that have surfaced?

I don't know who has intervened in that proceeding at this point with respect to the processes that we've identified. I don't, quite frankly, I don't know what the time frame is for them to do that. It may extend 'til after the technical conference, I'm just not sure, Charles.

Okay.

And at this point from an answer you gave to a previous question I assume the Governor's office, his Director of Energy or the Commission has not approached you to negotiate an extension of the rate certainty plan versus the, you know, in lieu of the competitive bid process. Is that -- I took that to be the case from your previous answers. Is that correct?

With all of the discussion and conversation that's going on in Ohio, I'd say that is on its face correct. But there are certainly a lot of discussion at the general assembly and with members, with the PUCO, with the Governor's staff on what the future of Ohio might look like.

Okay. Thank you. It'll certainly be an interesting time to watch Ohio.

Thanks, Charles.

Thank you. Your next question is coming from Steve Fleishman of Catapult Partners.

How you doing?

Good. How are you?

On the share repurchase plan, do you have some update on how far along the banks are in completing that plan?

The shares came off our books today. We executed the ASR. They are out there covering their short position.

There is a pricing grid in the mechanism, Steve, we haven't disclosed what those price points are but, obviously, as the stock price goes down, the numbers of shares purchased go up. So I think we said this program would be completed probably depending where the stock price is later this year and (inaudible) expectation as (inaudible).

Okay. But is there, would there be any update, for example, in your Q on that?

No.

Okay.

And then is there along some of the other questions, and this may have been answered already, there is any update on your hedging in Pennsylvania?

Talking about energy hedging?

Correct.

Capacity hedging or all of the above?

I guess the whole picture.

There's really no changes in that. I talked about that in the past, Steve. There's been nothing new to report there.

Okay. Thank you.

Thanks, Steve.

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

Good morning.

I was wondering if you had any views regarding the legislative initiative in Illinois to phase-in the increase in the rates, of Echelon and Amren and whether that has implications for legislative action, similar legislative action in Ohio and Pennsylvania with a (inaudible) rate transitions to market in those states or whether you feel that's an isolated Illinois event and that Ohio and Pennsylvania are unlikely to take a lesson from that?

The fact of the matter is, Hugh, as part of our generation filing we proposed a phase-in. In the event that the rates exceed 15% the increase would exceed 15% for certain residential tariffs.

So I think we've tried to address that as what it is. It's just kind of a political transition to make it a little easier on customers. We thought about it when we made our filing and I think we've addressed it and I believe Ohio has the tools to allow that to happen.

I think my question was more towards the mood, let's say, of the legislators in the two states and whether you saw the kind of, sort of populace anti-utility sentiment as strong and whether you expect it, therefore, the type of legislative intervention and conflict, frankly, that we've seen in Illinois.

Again, I think we try to manage that through dealing with issues, hopefully, before they become that type of political issue like a phase-in -- like our phase-in proposal would accomplish.

And then final question on that point. Did you see the transition to market rates in Ohio as being managed on a company by company basis or do you see some kind of statewide policy likely to be implemented?

I think we have a statewide policy right now that says we are going to market. I think every individual company might choose to get there. For example, I think AEP and Mike in his most recent conference call talked in terms of moving to market in a stepped process in which the difference between market prices and price to actual customers would be deferred and collected as a regulatory asset. That's another way it get to the same point.

I think there is a potential to do that with the goal ultimately being moving in the direction of market prices. That's effectively what we've proposed when we say we're going to phase-in if the price gets above 15%. We put the step in at that level.

Right. Okay. Good. Thank you very much.

Thanks, Hugh.

Thank you. Your next question is coming from Paul Ridzon of KeyBanc.

The Ohio questions have been asked, just more near-term.

Looks like trailing 12 we're at about the top end of your guidance. Aside from Perry, which kind of was a surprise, is there anything else in the back half of the year that we need to be thinking about with regard to maybe potential detractors from earnings?

The two things I'd mentioned, Paul, were just the Perry outage and the mild weather we saw during July in this part of the service. Otherwise, no.

No, no incremental nuke outages or refuelings?

No, nope.

Okay. Thank you.

Thanks, Paul.

Thank you. Your next question is coming from Dan Jenkins of State of Wisconsin Investment Board.

Good afternoon.

First I'd just, a clarification. I missed, you talked about your second half financing, I think you mentioned a $600 million long-term issue. If you could just run through those details again real quickly.

What I had said, Dan, is that we have about $600 million of unsecured debt issued out of our operating companies during the second half of the year. What we're still working on exactly is when, where, who and how (inaudible), but that's our expectation.

Okay.

And then related to that your financing of the Mansfield leaseback, did that pretty much take care of all your short-term refinancing, short-term debt?

Yes. Those proceeds were applied to reduce short-term debt. So we have our liquidity position where we want it to be and in fact that will continue to improve during the year. So we are, we're in good shape there.

Okay.

And then I was wondering about the Perry, the unplanned outage if you'd give me just kind of some details as to what happened to cause that outage and then if there are there any issues that NRC's looking at related to that outage.

What happened was the circulation pump motor in the recirculation system of large motor, I think it's about 30-tons failed. This happens from time to time, which is why we had a spare there which we were able to take out and put in.

It was a big project. This is a big piece of equipment. You have to move a lot of things to get it out of containment to put the new one in. Unfortunate circumstance, which is one of those random things that happens from time to time and that's why we had the spare in place ready to go when those kind of things do happen. But there was completed no NRC implications from them.

Okay.

And then I was curious on the $0.25 increase at the generation, you mentioned that was both due to higher volume and higher prices. I assume we could break that down between the two pieces (inaudible).

Hang on just a second here. Almost, of the retail generation sales, let's see, $0.16 and $0.09 from the wholesale sales. And think most of that was rate driven. All of that was rate driven.

Okay. And then just the decline in the wholesale, is that primarily due to the plant outages or --

Yes.

Okay. I think that's all I had, then.

Thanks, Dan.

Sure.

Thank you.

Thank you. There appear to be no more questions at this time. I'll turn the floor back it to your host, Mr. Rich Marsh, for any closing remarks.

Thanks, Cheryl.

I just, again, want to thank everybody for their time today and their continued support and interest in FirstEnergy. If anybody has any follow-up questions please feel free to get a hold of our investor relations group and I hope everybody has a great day. So thank you for your time.

Thank you.

Thank you. This concludes today's FirstEnergy Corp. second quarter earnings conference call. You may now disconnect.