公共服務電力與天然氣 (PEG) 2005 Q1 法說會逐字稿

Ladies and gentlemen, welcome to the Public Service Enterprise Group first quarter 2005 earnings conference call and Webcast. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session for members of the financial community. [OPERATOR INSTRUCTIONS]. As a reminder this conference is being recorded Wednesday, May 4, 2005, and will be available for telephone replay for 48 hours beginning at 1:00 p.m. ET today until 1:00 p.m. ET on May 6, 2005. It will also be available as an audio Webcast on PSEG's corporate website at www.pseg.com. I would now like to turn the conference over to Sue Carson. Please go ahead.

Thank you and good morning. We appreciate your listening in today, either by telephone or over our website. I'll be turning the call over to Tom O'Flynn, PSEG's Chief Financial Officer for a review of our first quarter 2005 results and a discussion of key issues, but first I need to make a few quick points. We issued our earnings release this morning. In case you have not seen it, a copy is posted on our website www.pseg.com. We expect to file our 10-Q with the Securities and Exchange Commission in a few days which will contain additional information.

In today's Webcast Tom will discuss our future outlook in his remarks and so I must refer you to our forward-looking disclaimer. Although we believe that our expectations are based on reasonable assumptions we can give no assurance they will be achieved. The results or events forecast in our statements today may differ materially from actual results or events. The last word on any of our business is contained in the various reports we filed with the SEC. I also want to remind everyone that this call is not a solicitation of a proxy from any security holder of PSEG or Exelon. All investors and security holders are urged to read the joint proxy prospectus and all other relevant documents for additional information when they become available. Finally, Tom will take your questions at the conclusion of his prepared remarks. Note, to accomplish this effectively we would appreciate it if you limit yourself to one question and one follow-up. Thank you. And I will now turn the call over to Tom O'Flynn.

Thanks, Sue. Good morning and thanks all for joining us today. I hope you've had a chance to review the release we put out this morning. I will spend some time during this call going through the first quarter drivers and how 2005 is shaping up. After that I'll give you an update on our proposed merger with Exelon.

Power reported earnings of 108 million or $0.45 per share for the quarter, a $1 million or $0.01 decline in the first quarter of 2004. In looking at the details, there are a couple of items, that in the end, netted out for the quarter. Margins were down a $0.01 primarily due to higher coal and gas prices than last year. We've locked in 100% of our expected usage for our coal units this year and 90% for next year. Our fossil operations materially improved over last year. We've seen meaningful increases in both the availability and capacity factors for our New Jersey fossil fleet due primarily to Hudson being on line for the entire quarter. As you may recall, last year our 600 megawatt Hudson coal plant was down for most of January resulting in significant replacement power costs. Our Bridgeport Harbor Coal Plant in Connecticut recently finished a 150-day run and is now in a maintenance outage in anticipation of summer operations. In addition, the Reliability Must Run or RMR payments we're receiving in Connecticut added another 7 million pretax during the quarter.

The lack of the $0.04 charge incurred last year for the refinancing of the Lawrenceburg and Waterford debt was a positive for the quarter. Lawrenceburg went into service in the middle of last year resulting in increased depreciation of about $0.02 in the first quarter of this year. As you know Hope Creek did not return from its extended outage until January 27th. It was off line for two weeks starting in late March. In March we are tracking a water leak in the dry well for a few weeks. The leakage was well-below technical and administrative limits and we felt it prudent to determine the cause and make repairs. We took the unit off line and identified the source of the leak which was a weld in a certain fitting that had fatigued. We've resolved this issue and the unit has been back on line since April 10th. However, this resulted in a nuclear capacity factor for the quarter of 89%, a 4% decline from the first quarter of last year.

During the first quarter post-Salem units reported capacity factors in excess of 102% of the summer rating. While the Peach Bottom units ran at 98 to 99% of capacity, all of which served to balance out our nuclear performance. In early April Salem Unit 2 began a scheduled outage of refueling and replacement of the reactor vessel head. The original 42-day schedule was established prior to the implementation of the nuclear operating services agreement with Exelon. When the Exelon team arrived they reviewed our work plan for the outage and made some improvements. For example, they introduced the use of "super crews" for the outage. The use of two 12-hour shifts each day, rather than three 8-hour shifts. This increased the communication in continuity between shifts and enhanced productivity. In addition, the implementation of Exelon's nuclear management model has improved our daily financial and production plan reviews during this outage. The vessel had replaced what someone had accomplished a few days ago and the final fueling activities are under way. The outage is proceeding well on all fronts, safety, schedule and cost. Salem 1 is scheduled to undergo a similar refueling outage in vessel head replacement in the fall. We expect to take the lessons learned from the current outage to see if the Salem 1 outage can be accomplished more effectively in the fall.

Finally, the Fourth Annual BGS Auction was completed in early February where PSEG Power was once again a direct participant. The clearing prices remarkedly higher this year due mostly to higher natural gas prices. As we look at it, the clearing price reasonably reflected all the components of serving a BGS contract. These higher-priced contracts representing about one-third of the total statewide load obligation will be effective June 1st. However, the impact of PSE&G customers this year will be a modest 2.8% increase because the lower rates from prior auctions have blended with the current year results. Longer term, Power is well-positioned to benefit from rising fuel and power prices with approximately 90% of our output coming from low-cost nuclear and coal. A weighted example, since the start of this year around-the-clock prices in PJM West have risen from the mid-40s to the low 50s per megawatt hour. Power will see an increasing benefit from these prices as existing contracts roll off and new contracts are entered into.

Now on to the utility, PSE&G reported earnings of 117 million or $0.48 per share for the quarter, a decrease of 7 million or $0.04 per share. As noted in the earnings release, most of this decline in the first quarter was a result of lower gas demand. Weather versus normal, accounted for $0.01 of the reduction, with another $0.03 coming from lower demand. While the average natural gas price to PSE&G's residential customers was only up 3% from the first quarter of last year, sales on a weather-adjusted basis were flat year-over-year, which may indicate some price sensitivity. We are looking at the implications of this as part of our long-range forecasting process. Interest expense was $0.03 per share, lower this year as a result of several economic refinancing that took place last year. This helped to offset a $0.01 increase in O&M expenses, primarily payroll and benefit cost inflation. In other news, the replacement transformers at Branchburg were energized about 10 days ago, ending a 15th-month period of increased congestion cost for suppliers in that portion of PJM. The replacement units will bring a total capacity of Branchburg to 2,150 megawatts, an increase of 550 megawatts of capacity at that critical switching station. By aggressively managing the installation schedule, PSE&G was able to cut more than a year off the normal schedule for a project of this size. For the remainder of the year PSE&G will be focussed on maintaining a system to insure reliability year round, but particularly in the summer.

Moving on to Energy Holdings, for the quarter they reported earnings of 77 million or $0.32 per share, an improvement of 34 million or $0.14 per share. About half of this improvement came from the absence of the $0.07 charge we took last year for the termination of the Collins lease at PSEG Resources. During the first quarter, both resources and global sold their interest in SEGS, the small solar investment, resulting in a combined gain of $0.03. Global had a good quarter with improved results from our South American distribution investments reflecting positive rate case outcomes. The strengthening of the U.S. dollar, particularly against the Polish Zloty, contributed another $0.02 to global's results for the quarter. During the quarter Energy Holdings paid a common dividend of 100 million to PSEG, with another 184 million paid this month to a preferred stock redemption. Since the beginning of 2004, Energy Holdings has returned over 750 million of capital to PSEG. The outstanding balance of 99 million from the sale of MPC last year, was received in late April.

Global also completed the successful selldown of 35% of our ownership in Dhofar Power Company, a generator in Salalah Oman for 25 million. The reduction in our ownership interest of 46% is part of the original contract with the Government of Oman. When the final stages of renegotiating a couple of credit facilities that expire this year, at PSEG there was a five-year 280 million facility that expired in March, and a three-year $350 million facility that will expire this December. There's also a small facility of Power that is scheduled to expire in August of 2005. We're looking to replace all three with a 650 million five-year facility that is structured to remain outstanding after our merger with Exelon.

Our 2005 guidance remains at 315 to 335 per share in continuing operations. We also expect to incur about $0.10 per share this year in merger-related costs, mostly associated with the regulatory approval process, integration efforts, and employee retention. Our guidance does not include this $0.10 expense. When we announced our '05 guidance last fall, the merger was not a consideration. Unlike Exelon we have not at this time specifically pro forma out these costs. We continue to work hard in the merger process with a focus on gaining the necessary regulatory approvals. The New Jersey BP issued a schedule in April that indicated a completion date by the Administrative Law Judge of February 26, 2006 with a BPU decision around March 23, 2006. As we state in our filings, successful settlement discussions with the involved parties could result in earlier BP approval. As in the past cases, in other proceedings, we'll continue to work toward this settlement that addresses the concerns of everyone involved.

April 11th was the final date for interveners in the FERC proceeding to file their complaints. You may have seen some press reports around the various parties that requested FERC to deny our mitigation plan or hold public hearings. As we noted in the release, we should know some time in June if FERC will hold hearings. If FERC will hold hearings the approval process could extend into mid-2006 or perhaps longer. In the meantime everyone here continues to focus on delivering the best possible results from every aspect of PSEG, nuclear and fossil operations at PSEG Power, electric and gas distribution at PSE&G, and maximizing the value of our investments at Energy Holdings. With that Operator I'll now turn it over to questions.

Operator, can you provide the instructions for the Q&A, please?

Thank you very much. [OPERATOR INSTRUCTIONS]. Our first question comes from the line of Greg Gordon, Smith Barney. Please proceed with your question.

Hey, Tom, good morning.

Hey, Greg, how are you?

I'm good. One question, you said that RMR for the Connecticut plants was a significant piece of earnings in Q1, could you say again how much that contributed? And then also should we assume that you receive RMR in similar magnitudes throughout the balance of the year on a pro-rata basis? And finally, how does that compare with what you received last year, if anything?

I think we said it was 7 million for the quarter. It's about 3 to 4 a month, which is reasonable to keep using. From last year, there was nothing there.

Okay. And then that segues to the next question, obviously there's been a lot of debate and anticipation around whether or not we will see some sort of new capacity market regime, the RPM proposal, in PJM actually get implemented. What's your view as a corporation on RPM, and absent implementation of RPM, would you then expect to receive RMR in lieu?

In general we're supporters of the PJM, RPM. We think there will be a need over time to build new capacity, especially in PSE&Gs there -- their area in the East and in PS North, a subpiece of the East. And we think that's having a gradual glide path on to giving signals for new capacity, signals for value in capacity. We think all that makes sense . Otherwise, you run the risk that there could be shocks to the system as the economic consent is to build, so building doesn't happen, and then all of a sudden you've got a shortage and we've got a big problem.

In terms of the RPM it was reviewed by the PJM members. The PJM members were not in support of that, I think it was 60/40 against, is my recollection. Keep in mind that's a broad constituency of generators, purchasers, small companies, large companies. All folks may not appreciate some of the dynamics and some of the necessity to have some reasonable incentives for capacity. I think where it stands is PJM is contemplating moving that forward to FERC, exactly where it stands is really more in their hands. But I think they're going to move it forward to FERC and try to keep that moving.

We are definitely beneficiaries of that. Capacity values are in the single-digits in terms of dollars per kilowatt year in our area, whether we sale in the market, whether it gets baked in the BGS. So we're getting really very, very modest amounts and the RPM would materially increase those prices. It would also as the RPM goes out in the -- I think it's in the second or third stages, they breakdown PJM into a couple of zones and then ultimately into even the East and potentially subzones within the East. Potentially the more they bifurcate the better that is for us because as we said before we've got assets that are in high demand zones with some constraints. So our stuff would have meaningful value. So bottom line, Greg, we're supporting it. We're watching it. And it's worth a lot of money to us.

If for some reason RMR didn't get -- I'm sorry for some reason RPM didn't get implemented, do you think that PJM would then be able to go petition for Reliability Must Run revenues in lieu of implementation of a more robust capacity market?

Possibly. There is RMR that we've petitioned for, the FERC approved subject to looking at a couple of issues in more detail. Those are some older peaking facilities. We asked to retire them, PJM said, no, we need those essentially. And there's a Reliability Must Run that was recently granted to us subject to looking at some of the details. I think in general, we will continue to support broader things that are market wide as opposed to one off plant-by-plant things. The RMR that we had applied for [FIRE ALARM] [inaudible] was really a --.

Hold on a second. Sorry we got --.

There's a fire alarm.

Folks, we have a fire got a fire alarm here. [Laughter]. Sorry. I'm just going to put this on mute for a couple of minutes.

Ladies and gentlemen, please continue to stand by. Your conference will resume momentarily.

All right, we're back. The place is not burning, there's no drill. Sorry. Next question.

Thank you. Our next question comes from the line of Ashar Khan with SAC Capital. Please proceed with the question.

Good morning, Tom. Tom, could you just tell us -- I guess I was looking through your assumption page, one thing was for '05, the natural gas 630, the PJM at 45, East/West differential 230, and capacity prices of 10. Exelon mentioned that -- I guess the East/West differential was big in the first quarter. Can you tell us how that impacted you in any way?

Ashar, you're thinking back from the November investor conference we had when we went through all the stuff?

Correct. Right.

I think we mentioned in the year-end call that the East/West was wider. It's been the 4 to 6 range. Generally in the -- that certainly helps us in the longer term. It probably helps us less in the short-term. It gives a reflection that, I think as we said before our objective -- and we've been successful on it -- is to sell 75% or more of our forward output over a 18 to 20 month period. We continue to be in that position, especially in the first year in '05 or meaningfully over that position to the extent that there's basis differentials. It gives us a little bit of support in the near-term, but if those were to continue -- to give us very meaningful support in the '06 and typically '07 period. We have seen that probably -- I know the Exelon folks mentioned that in their call. We've probably seen that for six months, the mid to late part of last year.

Okay. And can I just ask you where you stand on your fuel hedges as of today?

I think I went through for coal -- and actually our coal numbers are very similar to that same book, if you've got it. Were about 100% for this year, 90% for next year and then we tick down a little bit, but we're in quite good shape for coal.

For gas, I think what we looked at is hedging. The gas sales -- or the output from the gas plants that are in the mid-merit zone, where we've effectively sold power through the dispatch stacks, that would include those gas plants. As we look at our portfolio, the primary area for that then is for the summer. For combined cycles in the summer we're in good shape for the summer. As you go into the shoulder months, you tend to think more spark spread rather than strict gas availability because they become more marginal in terms of their output.

Okay. And then just going -- Tom, this is again a sensitivity analysis from that same presentation. You had plus or minus $1 per megawatt hour on the BGS auction prices, '05 contributed $0.01 or so, how should we look at the BGS auction? How did it come up versus what was in the plan? Can I ask you?

Ashar, remember back from at that time -- it would have been up a few bucks, Ashar, from that time.

So a few bucks more than planned, correct?

Yes. I think the easiest way to do it is to look at around-the-clock prices. But then in early October we're in the 46 buck range, maybe I'm kind of ballparking, and around the time of the deal they were in the low 50s. So maybe up 5, 6 bucks around the clock. Which is good. Obviously, they've -- the BGS has a lot of pieces in it. It's just a simple way to look at differentials, when we look at PJM West around the clock.

Okay. Thank you very much.

Thank you. Our next question comes from the line of Paul Patterson, Glenrock Associates. Please proceed with your question.

Good morning. Can you hear me?

Yes.

The tax rate seems -- and I apologize if you went over this. I might have missed it. But the tax rate seems a little bit lower this quarter compared to last. I was wondering if there's -- where we should be basically putting our numbers for the full year as a tax rate?

Yes, I'm not sure if it's that much. I mean going from 30 -- well, 40 to 37?

Yes. Maybe it's not that much. If -- we can -- I can circle back --. [multiple speakers].

Paul, there's no material pieces in there. There's no specifically unusual things. I will say tax always has some unusual things in it. It is a mix of earnings to the extent the international earnings are higher perhaps. And global has been up a little bit. Those have lower tax rates especially with the repatriation, so that in and of itself may --.

What should we use for 2005 though in general or what do you guys range -- what's the benchmark or the effective tax rate that you guys use?

I think generally it's something in the 38 to 40% range.

Okay, fine.

That number is over the last few years absent some one-time things -- that kind of number.

And then the Branchburg thing, what was the financial impact associated with that? I mean in terms of what will be -- in terms of the operation or the prices or -- do you know what I'm saying? I mean it sounds like it was a big deal in terms of how it influenced the ability to sort of move Power around. What kind of impact does that have getting it up sooner then expected and just what is the impact associated with having that thing come back up?

Let me go through -- it's really from two different directions. From PSE&G who was a constructure, and that's in their transmission system, the FERC regulator business, it's a typical kind of investment, modest amount of money, but it goes into rate-based and they share earnings on that. So that's a modest amount of the overall general [indiscernible] equipment of PSE&G.

From Power's perspective, I think we said last year, that that was increasing congestion cost and widening the spread between the value of the output and our plants and the cost to bring output into that zone. So it did cost some linkage at Power. On an annualized basis for last year it was maybe in the 6 to $0.08 range. It's hard to tell because you have to track basis differentials, which you unfortunately can't just isolate for [indiscernible] a lot of moving parts, weather, other plants, transmission and different areas. But it was probably in the high single-digits. I think P&G -- PSE&G have said they would bring it back by June 30th, to the extent it came back in earlier -- maybe that's worth a penny or two to Power, as well as for other suppliers. But it's a fairly modest amount.

And then finally I guess on Salem and what have you there, is there any event that we should be focusing on in terms of the review that's happening at that plant by the NRC or what have you?

Salem is in a normal outage.

I mean like Hope Creek -- I guess whatever. I mean the issue that they had there about a month or so ago, is there any inspection or anything that were -- or report that's supposed to be coming out?

No, there's nothing specific. No, I mean the issues out of Hope Creek -- as you may remember last year Hope Creek got a fair amount of -- more attention than perhaps was warranted for the pump -- the vibration of pump that certainly contributed to the extended outage that we had from the, I think the second week of October until the last week of January. We feel that that's behind us in terms of doing a thorough assessment of it ourselves, outside experts, the Exelon, Bill Levis and his team have also supported our findings. We put on a material amount of vibration monitors to be continually monitoring the vibration of the pump to the extent the vibration get out of the levels increase. We said we'll assess whether to we'll replace the pump. Nevertheless, we will replace the pump the next outage, which is a year and a little bit away.

The issue on the steam leak that we had was really for a weld and a fitting that fatigued, it was not associated with the vibration of that pump. So those are issues are -- I think behind us, but we're still obviously attentive and closely monitoring them. Salem is just a general outage, the head is for -- the head replacement is just standard. Head replacements that all reactors of that vintage and type are doing as of a couple years ago when the head in the Midwest was -- the vessel head had some problems. We had a 42-day outage planned. I think this was about day 29, something like that. They said it's going along well. In terms of if there's anything to watch, I just say watch when it comes back. We'll certainly notify the right folks and give people heads up when that comes back on.

Okay. Great. Thanks a lot.

Thank you. Our next question comes from the line of Margaret Jones with [Admil]. Please proceed with the question.

-- getting on the call, so I'm sorry if I missed comments on these two points. Could you talk about prospects for LICAP pricing in your area of PJM? And the second question that I had was could you update us on plans to bring home some money from Energy Holdings' subsidiaries over seas through the Jobs Act?

Yes, hi, Peggy. Yes, I did go through -- I think Greg Gordon asked it early on about RPM, as we call it in PJM. We're generally supporters of it. Quite strong supporters. We think it makes sense. It was reviewed by the PJM members. The PJM members I think voted against it, I think it was 60/40, which is a very broad group of constituents, obviously. I believe PJM is really in their court, I won't speak for them, but I believe their assessing pretty net to FERC and bringing it back to the members in some form. We think ultimately it does make sense. It would be material benefit to us as capacity prices are quite modest. Now, as you look out in time we may eventually, they'll need to be new build and the only way you get that is through -- to have a value for capacity and having that RPM, we get that gradually over time makes a lot of sense.

In terms of repacks subject to the Jobs Bill, yes, we are still evaluating that. We've got I think our "Q" that we'll expect to file in the next day or two. We'll say we've got something in the range of 170 million or something like that of earnings and profit for businesses that we are in control of. We got a little more if you roll in our jointly owned businesses where there's a little bit less control over that. We've got about 140 million of cash offshore, so we are looking at that carefully and may well make a decision on that at some point here in the next few months.

So the cash is already at the companies offshore, you wouldn't have to raise it?

Correct, it is held in offshore structures.

Okay. Thank you.

It's actually centralized I believe at an entity closer to home, but it's held in offshore structures.

Thank you. [OPERATOR INSTRUCTIONS].

Thank you for joining us. Maybe we can go back and reinitiate our fire practice. Thanks for joining us and have a good day.

Ladies and gentlemen, that does conclude your conference call for today. You may disconnect. And thank you for your participation.