公共服務電力與天然氣 (PEG) 2005 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by, welcome to the Public Service Enterprise Group second quarter 2005 earnings conference call and webcast. At this time all participants are in a listen-only mode. Later we will have a question-and-answer session for the members of the financial community. [OPERATOR INSTRUCTIONS] As a reminder, this conference is being recorded Monday, August 1, 2005 and will be available for telephone replay for 48 hours beginning 1:00 p.m. Eastern today until 1:00 p.m. Eastern on August 3rd, 2005. It will also be available on audio webcast on PSEG's corporate website at www.PSEG.com.

I will now 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 will be turning the call over to Tom O'Flynn, PSEG's Chief Financial Officer for a review of 2005 results and a discussion of key issues. But first, I need to make a few quick points.

We issued our earning 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 later today, which will contain additional information.

In today's webcast, Tom will discuss our future outlook in his remarks, 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 businesses is contained in the various reports that we file with the SEC.

Recent SEC actions have created a heightened sensitivity to confirmation and or changes in forward-looking information. In particular, earnings guidance. Our guidance speaks as of the date it is issued. Any confirmation or update in guidance will only be done in a public manner, generally in the form of a press release, a webcast such as this, or 8-K or other SEC filings. PSEG may or may not confirm or update guidance with every press release. As a matter of corporate policy we will not comment on questions regarding guidance during one-on-one meetings or individual phone calls.

Finally, Tom will take your question at the conclusion of prepared remarks. In order 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 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 second quarter drivers and how 2005 is shaping up.

As you may have noticed in the release, we've introduced the term "operating earnings" this quarter; which excludes merger-related costs as our standard for comparing results. This term should not be confused with the GAAP term, "income from continuing operations." We also, of course, show net income, which includes the impact of the pending sale of Waterford as discontinued operations. By excluding the merger-related costs, our results and guidance are consistent with the way Exelon is treating their merger-related costs. The attachments to the press release provide the reconciliation between the GAAP term, income from continuing operations and operating earnings.

Operating earnings for PSEG were 115 million for the quarter, excluding 14 million of merger-related costs. A decrease of 13 million from the prior year. PSE&G, our regulated utility, reported operating earnings of 48 million, a 14 million decline from the prior year. Power reported operating earnings of 63 million, 3 million better than last year. Finally, Holdings reported operating earnings of 21 million, a 5 million improvement.

Now let's go through each of these three major businesses. Power reported operating earnings of 63 million, or $0.26 per share for the quarter; compared to 60 million, or $0.25 per share last year. While the results reflect a modest year-over-year improvement, operating performance has improved significantly. As a reminder, the 2004 quarterly results included a $0.09 benefit from the Nuclear Decommissioning Trust Fund and another $0.04 per share from other items.

Starting with the nuclear operations, Salem 2 completed the replacement of the reactor vessel head in refueling on May 11th in just under 36 days. This was a tremendous accomplishment, the shortest outage in the history of the unit despite the added complexity of replacing the reactor head. The outage management expertise of Exelon, along with the experience long-time PSEG employees attribute to do success of this outage. Salem 1 will undergo a similar outage in the fall and we're hoping to reduce that outage to less than 36 days. During the quarter, Hope Creek was out of service for about 19 days to investigate leaks in the dry well. The source of the leaks were identified and proper corrective action was taken. Hope Creek has been on line since June 17th.

Overall, the three New Jersey units covered by the nuclear operating services agreement with Exelon, had a capacity factor of almost 79% for the quarter, a 16% improvement over the second quarter of last year. Year-to-date the units have a capacity factor of 84%, which includes about 50 unplanned outage days at Hope Creek , a 6% improvement over the first six months of last year. For our entire five-unit fleet, the year-to-date capacity factor is 87%. We are targeting a full-year capacity factor around 88%, which includes the scheduled refuelings at Salem 1 and Peach Bottom 3 in the Fall. By way of comparison once again, last year our capacity factor was 85% at mid-year and almost 82% for the full year.

In June, Power implemented a plan to reduce the workforce at our nuclear plants. This is part of the overall plan reduction of 400 positions at nuclear that we've talked about as part of the merger synergies. And is being done in conjunction with the operating services agreement. The program involved both represented and non-represented employees and resulted in about 200 requests for voluntary separation. Management at the site is now in the process of reviewing the individual requests to ensure no adverse impact on the business. The estimated cost of this program is 10 million and was recorded in the second quarter.

Turning now to fossil fleet. Our coal units produced 236,000 more megawatt hours this year in the second quarter than last year. Availability increased significantly for our New Jersey coal units, primarily due to improved performance at Hudson and the absence of the extended maintenance and environmental outage last year at Mercer. You may remember last year at our analyst conference, Mike Thompson, President of PSEG Fossil, indicated that improved performance by the fossil fleet could reduce replacement power costs by 80 million in 2005. As of June 30th, we've realized about half of this improvement.

For the quarter overall fuel costs were higher. Primarily as a result of higher coal volumes. Pricing for coal year-over-year was up about 16%. And we are about 90% termed up over the next two years. Natural gas prices continued to be high, averaging $7.54 per MMbtu for the quarter, versus 6.30 a year ago. Increased output from our nuclear and coal plants allowed us to use 30% less gas this quarter than the second quarter last year.

During the quarter, Power continued to see favorable trends in the evolution of the capacity markets. In Connecticut earlier this year, the Company started to collect about 5 million per month in Reliability Must Run or RMR payments. In April, the Company also received approval for monthly RMR payments of 3.3 million in PJM. While the operating margins of the effected plants are netted from both RMR payment streams, we continue to see them as a bridge to more favorable LICAP payments in Connecticut, and RPM payments in PJM.

Also during the quarter, Power reached an agreement with a subsidiary of American Electric Power for the sale of the Waterford, Ohio plant. The 821 megawatt gas-fired combined cycle plant entered commercial operation in the Summer of 2003. Conditions in the wholesale power markets in that region have been disappointing and we decided to sell the plant. We recorded a loss of 183 million, or $0.76 per share, as discontinued operations. Discontinued operations treatment requires that all prior costs and revenues associated with the Waterford plant are moved below the line, so previously reported results for PSEG and Power have been adjusted.

Although we were clearly not pleased about the significant loss, we believe the sale is an attractive means to maximize the near-term value of the facility and also demonstrates our willingness to make difficult decisions. Looking ahead, power prices remain very strong in PJM, with round-the-clock forward prices averaging in the low $50 per megawatt hour. By way of comparison, this time last year that number was in the low 40s per megawatt hour. Better performance by our nuclear and coal units have allowed Power to sell more output into this market resulting in higher margins.

PSE&G remains on track for the full year. However, the results for the second quarter reflected some declining usage from our largest industrial customers. Demand revenues were down for the quarter as a result of fairly mild temperatures in April and May. For electric customers, peak demand is established with each monthly billing cycle. Temperatures like we experienced here in New Jersey last week will certainly drive up demand revenues for July.

We have also seen reductions in usage by a handful of our large industrial customers, that have closed plants to induce production. The combined impact for the second quarter for the demand revenues and the reduced volume was about $0.03 per share. Weather did have a favorable impact for the quarter, contributing $0.02 per share, mostly in June. For the full year, weather was fairly flat with a modest $0.01 favorable impact. O&M was $0.02 higher for the quarter, result of increased fringe benefit costs.

Energy Holdings was up $0.02 for the quarter, with an $0.08 improvement at PSEG Global, offset by a $0.06 loss at PSEG Resources. If you recall, we purchased the remaining 50% of two gas-fired units in Texas from TECO about a year ago at a nominal cost, less assumed debt. Over the past couple of months, with high temperatures and a resulting demand for electricity increasing in Texas, we've seen these plants running just over 51% for the quarter. For the full year, we are forecasting a capacity factor of about 60%, which almost 70% is already locked in with forward sales. Coupled with Global's 100% ownership this year, TIE has produced about $0.02 per share of incremental earnings.

Operations in South America are also improved from last year. Adding about $0.03 per share to year-over-year results. Finally, for Global, the continued decline in the Polish Zloty against the U.S. dollar added about $0.03 per share to the results for the quarter.

At Resources, the write-off of the United Airlines lease was responsible for the entire $0.06 decline quarter-over-quarter. As we noted before, Resources remaining gross investment in leased aircraft is approximately 36 million. We continue to look at tax repatriation provisions in the Jobs Act. As of June 30, Global has approximately 190 million of earnings and profits that could reasonably be considered for repatriation under this provision. With an estimate of another 60 million available before the end of the year. The decision to repatriate this 250 million of earnings would come at an estimated cost of about 13 million in tax expense. We are still looking at a number of factors before the final decision is made.

On the financing front, PSEG closed on a new five-year, 650 million revolving credit facility on May 31 that replaced a 280 million facility that expired in March, 2005, and a 350 million facility that was schedule to expire in December. Holdings closed on a 115 million, five-year revolving credit agreement in late June that replaced a 200 million three-year facility that was scheduled to expire in objection. In July, PSE&G replaced 125 million of nine and one-eighths percent mortgage bonds and paid down some short-term debt, with a 250 million short-term note and a five and a quarter percent 30-year bond. Also, PSE&G, final approval was received from the New Jersey BPU to issue about 100 million of securitization bonds for the year four BGS costs that were deferred. We expect the bonds to be issued some time in the Fall.

Excluding merger-related costs, our year-to-date results are in line with our full-year expectations of $3.15 to $3.35 per share. The merger-related costs are expected to be between $0.10 and $0.15 per share this year, including the workforce reduction program at nuclear. We continue with our expectations for each of the operating companies; namely Power, 335 to 385, PSE&G, 325 to 345; Holdings, 135 to 155. Each of those were millions of dollars.

On the merger front, there are several teams working on the specifics of the merger, the day-one requirements and design of the in-state organizations. John Rowe and Jim Ferland announced the first-year management structure a few weeks ago, the first step in putting names in boxes. We'll continue to provide updates as appropriate, as organizational and staffing decisions are made over the next several months.

With the FERC approval behind us, we are working hard with both Pennsylvania and New Jersey on their approvals. In New Jersey, the BPU has selected the consultants that will assist them in their review. However, the volume of data requests has slowed the process somewhat. The schedule has the merger on track for second quarter 2006 closing. However, we continue to believe that successful settlement discussions with both New Jersey and Pennsylvania would allow the merger to close in the first quarter of next year. In the meantime, everyone here continues to focus on delivering the best possible results from every aspect of PSEG. Nuclear and fossil ops at PSEG Power, electric and gas distribution at PSE&G, and maximizing the value of our investments at Holdings.

With that, Operator, I will now turn it over to questions.

[OPERATOR INSTRUCTIONS] Our first question comes from the line of Paul Patterson from Glenrock Associates. Please proceed with your question.

Hi. Can you hear me?

Yes, Paul, I can hear you.

Just wanted to ask you about the megawatt hour sales on the retail side. You mentioned some industrial demand reduction and that's pretty dramatic. What's causing that? Is that basically because businesses are shutting down or is it because they are actually changing their electric or power consumption? And just to get a better idea about what the actual weather impact was versus normal, I see the $0.02, and that seems to be on the gas side, there was no impact of weather on the electric side for the most part? Is that right? And what would it have been versus normal?

Yes, the electric for the quarter versus normal was $0.005, maybe $0.01, versus normal. So year-to-date, it's probably about $0.01, and year-to-date $0.015, on the electric side. Gas, is negligible in the second quarter, the first quarter was helpful by a couple of pennies.

In terms of consumption, it's a couple things. One, we had that increase in price in the BGS, the most recent BGS was 65, the one before was 55 using ballpark numbers. Now the consumer, the residential consumer, in particular, is heavily cushioned because as those filter in, the consumer really only sees about a third of that increase in any given year. They are staggered on three years just as the BGS processes or bidding processes are done. But number one, maybe some modest indication on the residential side of some elasticity that is very modest. I think it's probably fair to say that our statistical analysis doesn't find that to be significant enough at this point.

What you are seeing though on the commercial industrial piece, even though those are really the CIEP customers, they are paying hourly spot prices in PJM. That's under the CIEP rate of the BGS. And spot prices in 2005 are about 8% higher than they were in 2004. So those large commercial customers, they may have their eye on that ball and maybe tail-end consumption a little bit.

On the industrial side, there is seven customers representing about 5% of our load, and there are a couple of field plants, Raritan Steel, a plant closed down, a Ford plant, J&J had a plant closing down. There are six or seven customers that either had a plant closing down or material reduction or curtailment of operations. We don't think that's a trend, but at least year-over-year it is a factor. When I say it's not a trend, it's really not a trend from the industrial plant closing perspective. From the price elasticity, especially in the CIEP area of higher prices, that's something we may see.

In terms of the residential ME [ph] elasticity there, I mean, you mention that they've been cushioned the way the BGS option works, but I'm wondering whether or not you guys, in terms of your long-term growth, would expect to see a decline in terms of retail growth in general?

We don't see much. We are generally around the 1.5% range. We don't see much. Keep in mind that the electric business in the $64 million proceeding that we will file in mid-November, that's the tail end of the electric relief that we got. To the extent that we did see some slightly lower demand, those numbers would get factored into that proceeding.

Okay. Thank you.

The next question comes from the line of Paul Fremont from Jefferies & Co. Inc. Please proceed with your question.

Thank you. My question really pertains to the lease write off. What was the ongoing contribution of that lease and why should we -- should we not look at that as sort of a non-recurring event?

Yes. It was $15 million of book value. It had been on the books for a while. The contribution was less than $1 million. It was negligible. Yes, it's a fair point, Paul, that it is a one-time non-recurring event. We have shown those above the line of not pro forma the margins, we've had these one way or the other. That's the way GAAP recommends them, so we just leave them that way. We did -- the only thing we pro forma'd out is the merger-related costs. I think we've talked now for a couple of periods about excluding those from our guidance. It's also consistent with the way our friends in Chicago are treating those, so we thought it was helpful to have some consistency there. But, no, it is fair. Certainly in our mind it is seen as a one-time event. The other 35 million of planes that we've got we think are on solid ground.

And the remaining aircraft leases are, can you tell us with who?

Yes, there's four of them, there's two 757s with Northwest -- and there's a 7 -- actually there's three 757s with Northwest and at Delta. Two of them were just re-done late last year in terms of refinanced, renegotiated with the lenders. And two of them we recently had appraisal -- the largest two with Northwest we recently had appraisals and had some work done, we are comfortable of the carrying value.

Thank you.

Next question is from the line of Leslie Rich, Columbia Management Group. Please proceed with your question.

Hi, Tom. Could you repeat what you said about your fuel costs and expectations there?

You mean in terms of coal costs, which are--?

Yes.

Coal costs are up about 16% this year.

Is that on your total inventory or just on new contracts signed or what portion?

That's an average on new. It's a little bit skewed. The biggest increase is at Mercer, and so if you remember Mercer was out last year so we didn't burn a lot of Mercer, so Mercer is kind of skewing that average out. If you look at the average Mercer coal costs are up about 40%, frankly, and that's skewing us because we had more -- we had much more volume this year at Mercer because we don't have the outage that we had last year.

Going forward, I think we feel we are in good shape. We've gotten more inflation type kind of numbers, low single-digit, low to mid single-digit numbers for the next few years. And we are 90% or so hedged for the next couple of years and we have some contracts that go out beyond that.

Okay. Thank you.

On -- you didn't ask about gas, I didn't really comment on gas. We don't -- with coal we look ahead and its fairly straight forward to, at least within a range, to estimate the amount that a coal plant is going to run, and the coal doesn't really set the inframarginal price, with gas plants they do set the inframarginal price, so we don't by gas nearly as far forward as our coal.

Great. Thank you.

The next question sums from the line of Paul Ridzon from Key McDonald. Please proceed with your question.

My question has been answered. Thank you.

The next question comes from the line of Stephen Hung from Smith Barney.

I think you guys in your Analyst Day forecast or your '05 forecast for the parent overhead was about $60 million. Year-to-date you guys are running way ahead of that and you are on track closer to 80 million now, and I just wanted to make sure that you gave the -- reaffirmed the guidance ranges for the three subs, but what about parent overhead?

The number we include, we don't break that out. But certainly when will we talk about the 315 to 335, that incorporates the parent. The convert is -- is a more expensive, because on an as-if converted basis, it's a much longer explanation. As the stock price goes up, it's a more significant number, obviously that convert, the new common comes in in November. I think it's that and maybe a little bit of financing costs.

Okay. And then your merger-related costs, looks like it's up about $0.05 since the last time we talked, is that just the inclusion of the nuclear layoffs.

I think it's two things. It's inclusion of nuclear and it's the profitability of the legal profession. It is -- we are very pleased about our FERC outcome, it was not without a lot of good work from internal people and some good work from some external folks. Looking forward, I think I mentioned that 2,000 or so requests from the BPU, that's largely internal resources we used for that, but that is indicative of the level of things. And probably going forward, we do expect some material activity with the Department of Justice just in their review.

And then following up on Paul's question, in terms of the industrial sales, I guess you would presume that a lot of the decline is going to just hold at the lower level because of the plants closing. How much of that low would you say was lost permanently?

If it's 4 to 5% I think the -- they are probably as they communicate to us and their constituents, I think they characterize these as plant closings, not as plant vacations.

Right. Okay.

Once again, we don't -- we see it as unusual activity. We don't foresee that going forward. There will be some sensitivity especially in that CIEP zone.

And the last thing I have for you is, any new developments on the securitization?

I mentioned it briefly. I'm sorry, we did -- this is what was initially about $140 million, I think it's now down to $103 million. We did get that all approved. I believe it's done-done, and we expect to issue that in October.

Okay. Great. Thank you.

Yes. That's money from about two years ago, two and a half year ago, so we are glad to get that, knock wood, done.

[OPERATOR INSTRUCTIONS]

Well, Operator, if there's no further questions, I will just briefly say thanks everyone for joining. Once again, we continue to focus on our operations at Power --.

Pardon me, sir, we do have more questions. The following question comes from the line of Paul Debbas of Value Line, Inc. Please proceed with your question.

Hi, what effect do you expect the Energy Bill to have on your company?

We don't see a major impact. There are small pieces around the edge, getting PUHCA repeal I think is good. There's a couple of very modest tax things. I think we see it as good for the industry. Good to get that behind people. There's no material impact to PSEG.

If I can ask one more, do you use PRB coal and have you seen any problems with deliveries?

No, we don't. We had a little bit of problems in deliveries in January, February, more coming up from the East with some train lines, some freezing. But, no, we don't use PRB, we use metallurgical coal at Mercer, use Indonesian coal in Connecticut, and we use Pennsylvania coal, largely Keystone and Conemaugh. We've been able to work -- generally any transportation issues we've had, we've been able to work around them just fine.

Thanks.

The next question comes from the line of Daniele Seitz from Maxcor. Please proceed with your question.

Just if you could give us the dates and milestones for the New Jersey and Pennsylvania. And also your impression of an agreement or a settlement in either areas?

Yes, let me start with New Jersey. And New Jersey, the current schedule is the ELJ in late February and the BPU in late March. That continues to be, as I said, they've -- I believe it was just recently that they got their four consultants on board to look at various aspects of this. There continues to be a large volume of requests. We are working through that. And, Daniele, kind of summarizing up, I think New Jersey is likely to be a last piece of this. Especially we haven't got an SEC 35 Act and the PUHCA piece that's normal the last piece would not be there, to be honest. So we are generally seeing it as a second quarter, 2006 event.

Pennsylvania, I haven't got the schedule at my fingertips, but it's generally in the fourth quarter of 2004 -- I'm sorry, 2005. That may have been recently pushed back a little bit to December, January.

And as far as your impression of the chances of an agreement or a settlement, is that a long shot?

I wouldn't want to get into a handicapping situation. Let me speak to New Jersey, which I am closer to. And then it will be, I think, likely the pacing jurisdiction here. There was recently a -- maybe a month or so ago, request for positive benefits test. We think there are positive benefits. There are some rate payer benefits, certainly some meaningful synergies and best practices. The New Jersey nuclear plants are already running better. I think I enumerated some of that. That flows into the benefits of New Jersey and eastern PJMs, so there's a number of things. We haven't seen the testimony yet, so it's a little early to the start speculating. But we certainly, had you looked back at our record, we certainly have a number of situations where we have settled things after a full and fair hearing and airing of all the issues.

Well, when we -- the leads become official, the position of the people who are going to be testifying? When will we know the position of all of the parties?

I believe that's in the next two to four weeks?

Okay. Great. Thank you very much.

That's the current schedule, Daniele, whether that gets moved around, we will see, but that's the current schedule.

Great. Thanks.

The next question comes from Zachary Schreiber from Duquesne Capital Management. Please proceed with your question.

Hi, Tom, this is Zack Schreiber of Duquesne Capital. How are you, sir? Just a question to make sure I understand this. The leveraged lease charge for the United Airlines lease, that was $0.06 a share?

Yes.

So your reported EPS was $0.34. We add back Waterford, $0.75, $0.06 for the merger cost, and if then we decide to add back the $0.06 for United Airlines, we are really at $0.54 with that last $0.06 be something that did you not add back, but which you could make an argument for. Is that what you're saying?

Yes, that's fair. It was on the books for 15 million, there's not much of a tax offset. So the pretax and after tax are pretty close, so that's why it's --.

Oh, really? Perfect.

But you're right, we -- that is a very reasonable argument that that's a one timer, that's not how we characterize it but that's a reasonable thing.

And on the nuclear capacity factors, where were we for the quarter if we were to just sort of normalize for the fact that you had the 36 day planned refueling outage. How do we monitor whether this joint nuclear services agreement with Exelon is making progress or not on a core basis? You see what I'm saying?

Yes. I will tell you, Zack, one thing we looked -- let me see if I can figure your number out, but at the same time, if you ask the guys down at the plant, Bill Levus [ph], the senior Exelon person down there, he would say that you look to the more -- the larger events or the more challenging events and he would say that the Salem 2 refueling was one thing that he was -- back when he got here, would look at as a very major milestone and that was the heavy competitive process or the real challenging period where you can see how the team did. I think being able to do that in 36 days, which was a record for Salem, as well as put a new reactor vessel head on at the same time, that is a -- we are very pleased about that.

I think you would also look and say, well, Salem 1 in the Fall will be another process. Let's get that done. Done effectively, safely, reliably and see if whether we can't do it in less than 36. I have to get back to you, Zack, if I want to normalize it. I see what you are trying to do, because the Salem -- because the numbers I gave you, it's fair, they did have all 36 days in the second quarter for the Salem 2 outage.

Exactly.

So we would have to add back effectively normalized for those days, which --.

How about this? How many days of unplanned outages did you have in the quarter?

Hang on one second here. Why don't we circle back with you, Zack? Because we can also look at what we call Skyline charts that's typical for the industry, that measures just that, the number of outage days. But I haven't got a sort of summary net number for you. I have to walk you through plants that would be more information. I would be happy to circle back and get you a punch line.

And just to make sure, on the airline residual exposures, you said you had $35 million of residual investment but that you are comfortable that that investment is all good.

Yes. We have four planes left. Two, 757-200s with Northwest that are about 25 million. And we did just do a reevaluation with those, and we are comfortable. And then a Northwest K-757 and a Delta, and that represents about 11, 11.5, and that -- the terms on those just did get re-extended in conjunction with the debt.

Got it. And you mentioned --

Zack, this was by far the one, I think if you look at our disclosure back for the last couple of years, it's by far got virtually all the press in that airline portfolio.

Right. And as far as the coal, you mentioned that you used met coal at Mercer.

Yes. Metallurgical coal.

Why would you use met coal instead of steam coal at Mercer when met coal is like twice the price of steam coal.

It is. It's a long answer, but it's something, if we could use something else we would.

So there's no way you steam coal at Mercer?

Not that I'm aware of.

Okay.

We do move coal around. We are actually doing some test burning of our Indonesian coal at Hudson. So we are trying to optimize coal leverage, a couple of good coal contracts we've got, but I don't believe there's a lot of flexibility at Mercer.

Okay. And last question about weather, what was the net sort of weather impact for the quarter? Was it that $0.06 that you laid out at the utility? Is that the way to think about it or were there other ripple effects on it through your business either positive or negative, like PEG Power?

Let me say at PSE&G, it was $0.01. It was -- and that's basically all in the electric business, $4 million pretax, that's basically $0.01 and it's about double that for the year. It's about $0.02 benefit. Net versus normal.

That's a benefit versus normal?

Yes, benefit versus normal. And it was $0.01 -- it was $0.01 better than normal second quarter this year. It was about $0.01 worse than normal second quarter of last year. So for the second quarter we are $0.01 above normal, about $0.02 above last year.

Got it. And this issue -- I lied about it being my last question, this is the final last question -- on the demand response and the seeing eye customer shutting down, can you say what kind of customers they were, what industries they are in, whether you know if they moved their production to other states or whether they just sort of took that kind of capacity out of the markets?

I can't tell you about the six -- I've got a list of six here, there's Raritan Steel, Hess, a Ford plant, J&J plant --.

Hess, what was it a refinery?

I don't it may have been. We can circle back. A Ford plant.

A Ford.

There was a J&J plant. Hoffmann-La Roche I think may have increased some of their co-gen, and then Union Carbide.

Great. Thanks so much for your time.

We have a follow-up question from the line of Paul Patterson, Glenrock Associates. Please proceed with your question.

Just a quick question. On attachment five, the cash flow statement, is it other working capital primarily or is there something else in there?

No, it's primarily -- it's two things, it's largely working capital, two things, one is some clauses at Power in we filed for gas case on the commodity side. That's -- there's a number of clauses, but I think the [inaudible] is about $50 million, some SBC, that are societal benefit clauses is another about $45 million, so E&G is about 100 million. We did fund the pension, $100 million or 90, I think it was, and then working capital other is about 75, is largely, largely margin posting at Power.

Okay.

When prices go up in the long-term, I like it, but obviously the contracts that we've got become out of the money, there is usually some dead band, but once you get beyond the dead band, you have to post. So kind of going through a benefit plan about 90, the utility about 95, and working capital, which is largely margin posting about 75, so it's about 250.

It looks like OCI also went up as well, I mean, went down I guess.

OCI went up, the biggest move there was Power, once again some longer-term contracts we got, it's our practice to hedge. We talked about 75% or more for 18 to 24 months, we continue to be in that zone or more. But then that's where we think it's just reasonable fiscal management. But prices go up and you've got to mark those. In our disclosure we talk about a contract with a couple of Pennsylvania companies and that goes up for a number of years. I think that's the biggest piece of that.

Then finally, TIE and South America, the global numbers for the six months, there appears to be $0.04 associated again with other as classified as other and I was wondering if there's any particular item in there that is causing that, or if you could just describe a little bit about what's going on there and why TIE and South America, I'm sorry if I missed it, why they are doing so much better this year?

I haven't got all the pieces here, but it's really a collective effort between Chile and Peru doing well. I think it was a rate case that we got a reasonable outcome for. Some good sales. But just good blocking and tackling in Chile and Peru.

Okay, great.

The other piece, TIE, is about $0.02. In TIE, we are getting -- Texas, as I said, we are getting more encouraged about.

And then other, you just said it's a bunch of cats and dogs, you don't have the break out yet?

Well, yes.

Okay. Thanks.

Cats and dogs isn't exactly the term I would use, but it's collective contribution.

Okay. Great.

We have a follow-up question from the line of Stephen Hung, Smith Barney. Please proceed with your question.

Tom, I had a question here on the UIL plant in Connecticut -- or the UIL contract in the plant in Connecticut, is there any environmental items in with the Connecticut plants where it would force retirement in 2007 or beyond?

No, you are thinking about Hudson. We have had -- just if you think about forced retirement in '07, we do have one of those, that's Hudson, where we do need a major environmental back end put on and some CapEx. We talked about that being sort of a 350ish kind of number and were still under -- we're still assessing that. That being said, we are not, at this point it is not physically possible to do that in advance of January 1, '07. That plant Hudson is very much needed for the PJM reliability. So the Q that comes out today, tomorrow, will say we expect that plant will keep going for some period of time.

There is about a $100 million up at Bridgeport 3 that's a 375 megawatt coal plant and we talk about, I think it's Mercury, complying with Mercury legislation in Connecticut by '08. That's scheduled, it's in the 100 million zone. It's in our CapEx numbers that are in our K, in I believe it's '07.

Well, the contract for the UIL, though, ends at the end of '06 and I have it priced at around $55 or so. When you market to today's market and you look at how you guys do BGS, we are talking close to $100 -- 90 to $100 new recontract price, if you guys decide to sell back to UIL, that is.

Yes. the UIL process was competitive so we certainly hope to compete in that. You're right. We had a three-year contract with UI up at the end of '06, market prices in UI are higher. So as that comes off whether we resell the UI, which we -- I'm sorry?

Do you remember what the market price was when you signed it versus today?

We didn't disclose that, but it was consistent with market prices back then it was, what was it, November or October of '03. It was gas prices were materially lower. There was some capacity in it, but it was nothing like the kind of LICAP prices that are talked about for that zone. I think what LICAP prices in southwestern Connecticut were $80, $90 a kilowatt year, and the New Haven, right on the margin, is in the 60 to 70 and those numbers go up meaningfully after that in '08, '09. So we expect meaningful revenue contribution for that.

Do you happen to know whether or not that Connecticut has a rule on how much it can increase the contract for, like 15% upside max or?

No, I'm not aware of anything of that nature. Once again the UI had a competitive process, and we won that process so it was for a three-year deal. They should be pretty happy with that. Very happy with that.

Yes, a great deal.

It was something, once again, we look to hedge and sometimes if prices go up you leave some money on the table, but that's the prudent way to run the business. But, no, looking at today it's a super deal, but that price will go up. I think it's that expectation of a meaningful price increase that's causing a lot of chatter around this LICAP stuff.

And the last thing is Energy Holdings, you guys had a strategy for prior, back in '04 to sell off more assets. What is your strategy now for EH? Should we be looking forward to more asset sales coming about?

There's some, I think it's a multi-year process. There's a couple of things that we are looking at that are still in the -- of a relatively modest size, but that we're -- we are nibbling on. I don't think you should expect any -- between now and the closing of the merger, I don't think you should expect any material change in our practice, and we did -- the last thing we did of course was the sale of MIA [ph] Power that was for, what, 220, we got a piece last year and a piece in January. We continue to take some pieces -- some pieces like that. And I think Exelon has been a little more in their commentary. And suggests that they may look at a quicker pace, but we'll have to see after the merger.

Thank you.

We have a follow-up question from the line of Paul Fremont, Jefferies & Co., Inc. Please proceed with your question.

Thank you. Can you give us a brief update on RPM and whether you would expect PJM to file under Section 206 maybe as early as August?

They may well, Paul, I think all our indication is that they have not reached agreement with their members and they need to force the issue somewhat to get it moved forward. I think there is some support within FERC for that. Once again, we think it's a positive indication that we have got LICAP moving forward in New England. We've got a capacity market pricing mechanism in New York. We do have the RMR that we are getting on our plants here is further justification of the need for capacity payments. So we think all those are positive trends. We think that's a reasonable possibility, Paul, but I wouldn't want to be predicting the actions of others too strongly.

I mean in terms of reaching a consensus, it seems as if that's nearly impossible given the position that some of the parties have staked out. So would you expect it to be simply getting some additional parties on board, or are you looking -- when you are talking about a consensus are you referring to sort of getting all of the major five constituencies on board?

No, I think it's fair that they've tried a consensus and it wasn't as successful, obviously, as they wanted it to be. So forcing folks hands through a filing may be more appropriate. Once again, I wouldn't want to get too far into predicting their next actions.

Thank you.

We have a follow-up question from the line of Zachary Schreiber with Duquesne Capital Management. Please proceed with your question.

Tom, it's Zack Schreiber. Just a follow up. Can you just remind us on the RMR contracts that you have now for the Bridgeport asset, the number of megawatts that are especially tied up in the RMR contract and what the capacity price implicit in those contracts for the RMRs from Bridgeport or either implicit in the UI contract. And then secondly, for the RMR contracts, in PJM east what are the number of megawatts that are specifically tied up in the RMR contracts? What's the capacity price implicit in them? And then in an RPM world, remind us on sort of where the demand curve would have a capacity price, would it be for the same number of megawatts or would it be for wholesale PJM east fleet? I just want to look at it as what kind of change, because I know that we have some positive in there that we already have in there, so it's the incremental. Thanks.

Yes, what I would say is number one, the -- keep in mind that the RMR payments that we are getting, we are getting capacity payments, but they are netted back. They are netted of energy margin. So when I talk about $5 million in Connecticut on New Haven, we are getting that -- that's the only revenue effectively we are getting for those plants, because any energy margin we receive is thrown back into the pool. Under capacity pricing model, you would get value for capacity and value for energy, so it is immaterial.

I get it. So the whole thing is a step up.

Yes. Now , in terms of the numbers -- the Connecticut number -- we can get back to you, Zack, with some of the specific more refined numbers, but the Connecticut numbers are about $5 million a year over -- I'm sorry, 5 million a month over about 500 megawatts. Once again, that's the gross member, that gets netted down materially from any energy margin that New Haven would generate. PJM is about $3.5, $3.9 million for, I think, 800 to 900 megawatts.

Is that on a month?

That's on a month. Net/net though in terms of bottom line contribution --

800 to 900 megawatts, Tom?

Yes.

Got you.

Now keep -- this has been good for us in the -- especially in the second quarter it is during the Summer we expect that we won't have any benefit from these RMR contracts, because that is the period when these plants are running. So you would get less benefit, to be honest. Bottom line, Zack, this year these two things I think are going to be in the $0.06, $0.07 range, something like that, benefit to maybe $0.05 to $0.07, it depends on energy margin and some other pieces. It's in that sort of zip code of value from these. If we get the capacity markets, we've got about, just taking PJM, we've got 12,000 megawatts of PJM excluding our Midwest facility. And you get any kind of capacity market you can look at the PJM, RPM stuff, and there's numbers in the $20, $30, $40 per kilowatt year, so you get some large numbers in a hurry.

Okay. Thanks so much. I will follow it up.

Mr. O'Flynn there are no further questions at this time. Please continue your presentation or closing remarks.

I think I will make my closing remarks briefer. Anyway, thanks all for joining. As I said, we are pleased about Power, especially the nuclear and fossil opportunities. PSE&G continues to move forward. And we have some good results out of Holdings. So thanks again. Take care.

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