公共服務電力與天然氣 (PEG) 2010 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Dashondra, and I am your event operator today. I would like to welcome everyone to the PSEG third-quarter 2010 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, October 27, and will be available for telephone replay beginning at 1.00 PM Eastern today until 11.59 PM Eastern on November 3, 2010. 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 Kathleen Lally. Please go ahead.

Thank you, Operator. Good morning. Thank you all for participating in PSEG's call. As you are aware, we released our third quarter 2010 earnings statements earlier today. They are also -- the release and the attachments are posted on our website at www.pseg.com in the Investor section. We have also posted a series of slides that detail our operating results by Company for the quarter. Our 10-Q for the period ended September 30, 2010, it will be filed shortly.

I am not going to read the full disclaimer statements or the comments that we have on the difference between operating earnings and GAAP results. However, as you know, the release and other matters that we will discuss in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if our estimate changes, unless we are absolutely required to do so, obviously. Our release also contains adjusted non-GAAP operating earnings. Please refer to our 8-K today containing the earnings statement and other filings for discussion of the factors that may cause results to differ from management's projections, forecasts, and expectations, and for reconciliation of those operating earnings to GAAP results.

I am now going to turn the call over to a Ralph Izzo, Chairman, President, and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on the call is Caroline Dorsa, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions, and we do ask that you limit yourself to one question and one follow-up. We hope that there will be plenty of time for all of your questions today. With that, I'll turn the call over to Ralph.

Thank you, Kathleen. Good morning, and thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the third quarter of 2010 of $1.06 per share, compared with operating earnings of $0.92 per share in 2009's third quarter. Overall, operating earnings benefited from strong weather-related demand. New Jersey experienced the hottest summer on record this year. This stands in contrast to last year's very cool weather conditions.

For the past three quarters, we've been seeing the economy appears to have stabilized. That story remains unchanged. The signals coming from employment levels and housing indicate the economy may have bottomed, but as of yet, no signs of a significant recovery have appeared. Company execution was strong in the quarter. Our fossil-generating units in particular were available to respond to the increase in demand, and our employees continue to support our results through their constant focus on operating efficiency and cost control.

Capital commitments are being met as well. PSEG Power is in the midst of testing the back-end technology installed on the Hudson and Mercer coal stations. These units are expected to meet stringent environmental requirements for sulfur, mercury, nitrous oxides, and particulates. PSE&G is in the midst of a $700 million capital program that will produce 160 megawatts of solar energy. PSEG Energy Holdings has completed the installation of 29 megawatts of solar capacity in New Jersey, Ohio, and Florida, and is reviewing additional PPA-supported solar investments. These are but a few examples. Caroline will have more details on the capital program later on.

We're moving forward with PSE&G's substantial capital investment in transmission. The update we're providing you today of PSE&G's planned capital outlays takes into account the announced reductions in distribution-related spending, the delay in construction of the Susquehanna-Roseland transmission line,and PJM's recently approved reconfiguration of the Branchburg-Roseland-Hudson transmission line. The net result will be a capital program yielding annual growth in the utilities rate base of 9.5% per year over 2010 to 2013, with transmission continuing its role as our most significant area of investment.

We continue to reduce our financial risk and maintain our focus on core markets. PSEG Energy Holdings successfully terminated another two cross-border leases during the quarter. Over the past two years, the successful termination of 17 leases has reduced Holding's potential tax liability by $1 billion, with one lease remaining in the cross-border lease portfolio. PSEG Power announced during the quarter that it is exploring the sale of its Texas gas-fired combined cycle generating capacity. If successful, we expect the sale to close during the first quarter of 2011. We've been saying that we needed to get bigger in Texas or get out, and we have not found appropriate opportunities to grow in that market. The sale of the Texas assets will reduce the overall size of the portfolio by 2,000 megawatts, but it will improve returns on the portfolio and keep the focus squarely on the markets and assets with the highest value.

Our results for the quarter and year-to-date continue to support our full-year operating earnings guidance of $3 to $3.25 per share. We experienced the benefits of an improvement in weather-related demand on pricing this summer, which continues to demonstrate the locational value of our assets. Said another way, basis returned with demand, albeit weather-driven. The power markets, however, remain challenging. The price of natural gas has fallen faster and further than implied by the forward curve.

Our reported results continue to benefit from higher priced legacy hedges, which are scheduled to expire in 2011 and 2012. As you know, the relatively high embedded cost of energy in our hedges under the basic generation service, as we refer to it as BGS, contract, versus today's market prices led to the entry of new retail suppliers into the marketplace. An increasing market penetration by retail suppliers accelerates the impact on margins that would happen eventually from the reset of the BGS contract prices.

We are working hard to address the market challenges. We're focused on reducing our O&M without sacrificing reliability. Our financial condition remains strong. The markets we serve remain constrained, and we are well-positioned for potential new EPA regulations. Our efforts to build an organization that focuses on maximizing efficiency, promoting renewables, and building a sustainable energy strategy have not gone unnoticed.

PSEG was added to the Dow Jones Sustainability World Index for the first time this year, having been on the national index for the prior two years. And PSEG was recognized by the Carbon Disclosure Project for its efforts to reduce emissions and mitigate the risks of climate change. We aren't immune to declining market prices, but we're well-positioned to meet these challenges. Now let me turn the call over to Caroline. But I will return prior to the question-and-answer period for a few closing remarks.

Thank you, Ralph, and good morning, everyone. I will review our quarterly operating earnings as well as the outlook for full-year results by subsidiary companies. As Ralph said, PSEG reported operating earnings for the third quarter of 2010 of $1.06 per share, versus operating earnings of $0.92 per share in last year's third quarter. Slide four provides a reconciliation of operating income to income from continuing operations and net income for the quarter.

As you can see on slide nine, PSEG Power continues to provide the largest contribution to earnings. Power reported operating earnings of $0.70 per share, compared with $0.71 per share last year. PSE&G reported operating earnings of $0.30 per share, compared with $0.17 per share last year. And Energy Holdings reported operating earnings of $0.05 per share, compared with a negligible contribution to earnings a year ago. The parent Company reported earnings of $0.01 a share this year, compared with earnings of $0.04 per share a year ago. We've provided, as always, the waterfall charts on slides 11 and 12 that take you through the net changes in quarter-over-quarter and year-to-date operating earnings by business.

And I'll now go through each company in more detail, starting with power. As shown on slide 14, PSEG Power reported operating earnings for the quarter of $0.70 per share, compared with $0.71 per share a year ago. The operating environment in the quarter benefited from extremely warm weather, as Ralph mentioned, a sharp contrast to the operating environment of a year ago. A 10% increase in generation volume at spark spreads during the quarter improved Power's earnings by $0.04 per share. While we had a 10% increase in generation during the quarter, the improvement came primarily from Power's coal and gas units. A 17-day unplanned outage at the Salem 1 Unit, which you may recall we mentioned in the July call, reduced generation from the nuclear fleet during the quarter and reduced earnings by $0.03 per share.

So, given the different fuel mix and the cost of the outage combined, the increase in output resulted in a net increase in earnings of $0.01 per share. While we realize the benefit from the net increase in generation, the price received for base load generation declined as a result of lower contract hedge prices versus prior year. This reduced Power's earnings by $0.04 per share. We can also see that weather had a positive effect on BGS load, adding $0.03 per share to earnings. Slightly offsetting this was the reduction to BGS results based on the impact of migration, which hurt Power's earnings by $0.01 a share. The impact of migration during the quarter was in line with our revised forecast. We estimate that approximately 22% to 24% of the load supplied through BGS migrated to other suppliers at the end of September, but we don't have the final September data yet. This is approximately steady with the level we saw, as you may recall, at the end of the second quarter.

Our forecast assumes further erosion in margin of $0.01 per share in the fourth quarter, which is consistent with the upper end of our prior guidance of a $0.02 to $0.04 per share impact of migration for the full year versus 2009. We're now forecasting about $0.04. Market prices for energy remain lower than the embedded price for energy in the BGS contract and this dynamic has led to the entry of new retail suppliers into the market. For your modeling purposes, while we don't specifically forecast migration, keep in mind that each 5% of customer migration from BGS would reduce Power's earnings by about $0.015 per share on an annualized basis at current prices.

In addition, the continued erosion in margin on certain wholesale electric energy supply contracts reduced earnings by $0.02 per share. Recall that these contracts are marked to market. Also, realized gains on investments in the rabbi trust fund added $0.01 per share to Power's earnings, and the decline in the effective tax rate aided earnings by about $0.01 a share.

The increase in volume from the fossil fleet and lower average prices resulted in gross margins for the quarter of $57 per megawatt hour, compared with $64 per megawatt hour during the third quarter of 2009. Power's gross margins were significantly increased by -- influenced by an increase in generation from its coal-fired fleet and a higher cost of fuel, given the outage at Salem 1, versus year-ago levels. Generation from the coal-fired fleet increased 40% during the quarter versus last year in response to weather-related demand and an improvement in dark spreads from the levels experienced earlier in the year. The combined cycle fleet also benefited from market opportunities, with an 11% increase in generation versus last year, and operated at an average capacity factor of 59% in the quarter.

The increase in coal-fired generation for the quarter and year-to-date has reduced our inventory of coal. We've also exercised the flexibility that exists in our contracts to reduce delivery of coal, and the completion of the back-end technology work at Hudson and Mercer this quarter will provide greater flexibility with regard to our coal supply by reducing the need for the low-sulfur Indonesian coal burned at Hudson in 2011, when the BET is expected to go into service. Our coal supply needs over the intermediate term will be lower than historic requirements. Continued weakness in forward dark spreads is expected to reduce coal-fired generation for 2011 to about eight to nine terawatt hours. Our reduction in output has effectively lengthened our supply. Recontracting an existing supply should be sufficient at this point to meet 2011's coal requirements.

Power's operating earnings for 2010 are still forecast at $1.06 billion to $1.135 billion, compared to operating earnings for 2009 of $1.205 billion. Full-year operating earnings will be affected by continued lower energy pricing. Power continues to hedge its expected generation in future years, consistent with past practice. At the end of September, approximately 68% of Power's anticipated coal and nuclear generation for 2011 is hedged at an average price of $71 per megawatt hour. This compares with an average hedged price for energy in 2010 of $72 per megawatt hour.

These hedges reflect a PJM West forward energy price embedded in BGS of $70 per megawatt hour in 2008, $57 per megawatt hour in 2009, and $50 per megawatt hour in 2010. And, as you know, the current PJM West forward prices are in the approximate $40 per megawatt hour range today. These figures don't reflect the potential impact of increased levels of customer migration, which could reduce the level of power supplied under existing BGS contracts. As I just mentioned, incremental migration equal to about 5% of customer load would reduce earnings by $0.015 per share. If you run out the math, an additional loss of about 15% of load would reduce our average hedged price in 2011 to about $67 per megawatt hour.

Now let's turn to PSE&G. PSE&G reported operating earnings for the third quarter of 2010 of $0.30 per share, compared with $0.17 per share for the third quarter of 2009, as shown on slide 22. PSE&G's results were influenced by the electric and gas rate relief, effective in June and July of 2010 respectively, which improved earnings by $0.05 per share. And earnings also benefited from a return on the capital invested in the capital stimulus, energy efficiency, and solar investment programs approved in 2009 by the Board of Public Utilities. And these programs added about $0.01 per share to earnings.

As Ralph mentioned, New Jersey experienced the hottest summer on record in 2010, and we estimate an increase in weather-related demand added about $0.03 per share to earnings. An increase in transmission revenues effective at the start of the year added $0.01 per share to earnings this quarter. A decline in operating and maintenance expense during the quarter improved earnings by $0.02 per share, and realized gains on investments in the rabbi trust also added $0.02 per share to the utilities earnings. And a decline in the effective tax rate added about $0.01 per share. These items more than offset an increase in depreciation and interest expense associated with higher levels of capital investment, which together reduced earnings by about $0.02 per share.

PSE&G's operating earnings for 2010 are forecast at $425 million to $455 million, the same as our prior guidance, compared with 2009's operating earnings of $321 million. Operating earnings will be influenced by a full year of return on capital projects approved by the BPU in 2009, the June and July 2010 increases in electric and gas distribution rates, an increase in transmission rates, a forecast decline in operating and maintenance expenses, and the weather-related impact on sales. We've updated PSE&G's capital budget for 2010 to 2012, and we're providing you with our initial forecast of PSE&G's 2013 capital expenditures.

PSE&G's revised budget for 2010 to 2012 calls for capital expenditures of $4.5 billion, with plans to spend $1.6 billion in 2013, bringing the capital budget for this four-year period to approximately $6.1 billion. And on slide 25, you can see a breakdown of the spending by category and by year. This revised capital program recognizes the two-year delay in the in-service state of the Susquehanna-Roseland transmission line, the reconfiguration and delay in operation of the Branchburg-Roseland-Hudson transmission project, and the reduction in distribution spending. In fact, distribution spending is lower by about $425 million through 2012, versus the prior guidance we gave you earlier in the year. This should increase the proportion of our expenditures that earn a contemporaneous return. For example, transmission-related capital spending now represents $3.1 billion, or about 50% of the capital budget for the four-year period. Of course, the number of these transmission projects depend upon our receipt of all the necessary approvals.

At the end of 2013, PSE&G's investment in transmission would represent about 31% of its consolidated rate base. Distribution-related capital spending is forecast at $2.2 billion for 2010 to 2013. Future capital spending on distribution is aligned with forecast levels of depreciation to support earning our authorized return. PSE&G's investment program is expected to result in annual rate-based growth of about 9.5% per year over this period. Supportive regulatory recovery mechanisms and a constant focus on cost control should support PSE&G's earning its authorized return, with growth in capital providing for growth in PSE&G earnings. For the past 12-month period, PSE&G's distribution ROE was 9.5%, reflecting only one quarter of results since the completion of the rate case.

Now I'll turn to PSEG Energy Holdings. Energy Holdings reported operating earnings of $24 million, or $0.05 per share, for the third quarter of 2010, versus an operating loss of $1 million during the third quarter of 2009. Operating earnings benefited from the successful termination of two cross-border leases during the quarter, which resulted in a gain of $0.03 per share, which matched a similar level of termination-related gains recorded in the year-ago quarter. And results also benefited from the absence of a premium paid on the debt exchange with Power of $0.04 per share, as well as a decline in interest expense of $0.01 per share.

The successful termination of the two cross-border leases during the quarter reduced Holdings's potential net cash exposure to $330 million on this issue at the end of September. And recall that Holdings has $320 million on deposit with the IRS to defray potential interest costs associated with this issue. Holdings's operating earnings for 2010 are forecast at $30 million to $40 million, compared to 2009's operating earnings of $43 million. The loss of income on terminated leases and a reduction in gains from the termination of leases will be partially offset by lower financing costs and tax benefits from the start-up of solar projects in Ohio and Florida.

Finally, a few other items. PSEG Power indicated during the quarter that it is exploring the potential sale of our two 1,000-megawatt each combined cycle generation facilities in Texas through an auction process. The sale is dependent upon the receipt of offers that we feel reflect the appropriate value for the assets. And should we decide to sell, the schedule would call for closing to occur during the first quarter of 2011. Finally, just to note, we completed several transactions during the quarter at PSE&G to finance its capital program and refinance high-cost debt. We issued $250 million of 10-year paper at 3.5% and refinanced $100 million of 6.4% tax-exempt bonds with the issuance of tax-exempt paper as multi-mode or annual put bonds with an initial term rate of 1.2%.

Holdings recently announced its intention to call debt in December 2010 for the redemption of the remaining $127 million of outstanding principal balance of its 8.5% senior notes that are due in June 2011. Those conclude my remarks and comments on some of our financings. I'd now like to turn the call back to Ralph for some final comments before, of course, we open the call up to your questions.

Thanks, Caroline. A few points to highlight. In conversations with many of you, we have heard concern expressed about transmission, and we've heard concern about migration and the impact on Power's margins. We hope that we've answered your questions surrounding transmission. Now, while it isn't easy to build these lines, we're committed to investing in the projects that will improve the reliability of our system, and as you can see, it remains the single largest capital program for PSE&G.

We've also provided you with some guidance around the potential impact of migration on our results. While we're not pleased with the associated loss of margin, the more fundamental concern is the forward price of natural gas and its effect on electricity prices. And, candidly, we're pleased to see some of you have addressed this issue in your forecasts. Now, while we aren't immune to declining prices, we are working to mitigate the impact through cost control where we can and through growth investment. So now, we will open up the lines for your questions.

Ladies and gentlemen, we will now begin the question-and-answer session for the members of the financial community. (Operator Instructions) Your first question comes from the line of Daniel Eggers of Credit Suisse.

Yes, on the increase in transmission CapEx, could you guys talk a little more about how much of that spending has been locked down through the approval process, and what major projects we need to follow to deliver or convert the planned CapEx into real spending?

Dan, there's multiple approval processes, so it starts with designation by PJM that it's in the RTEP, the Regional Transmission Expansion Plan. And it's safe to conclude that all of these projects are in the RTEP and all of this expenditure level. Then there's the rate treatment at FERC, and as you know, we have a macro-level formula rate treatment at FERC. Some of the projects receive a different level of formula rate treatment -- incentive adders, construction work in progress. We've received that -- those two for Susquehanna-Roseland. We had received that for Branchburg-Roseland-Hudson when it was a 500-kilovolt project. Now that it's been redone, we're back at FERC to talk to them about the return that that will be granted.

As you see, as I go down this path of what approvals you need, the path gets wider and wider with many more branches and tributaries off of it. The widest set of branches and tributaries are, of course, the environmental approvals and the siting approvals, which I just don't have the information at my fingertips about what all -- what each of these projects are still lacking. Clearly, for Susquehanna-Roseland, as we've disclosed in the past, we're working with the National Park Service towards a 2012 approval date there.

I guess, to put them in the capital budget, you guys have a higher level of confidence on conversion as the [port flow] is laid out today? Or how did that level of confidence --

It's higher for a simple reason, that -- well, first of all, we've made a lot of progress on SR, and we now know what the obstacles are, and that's resulted in delay. But probably more importantly, all the other projects are 230-kilovolt and below, and many of them are underground. And they don't engender the kind of siting opposition that 500-kilovolt, above-ground projects engender.

Okay. And so, are there -- how many of these are kind of big-profile lines, relative to small, $50 million, $100 million investment type of projects?

Well, it depends on how you define big in profile. The 500-kilovolt is the one that attracts the greatest attention, and that would be Susquehanna-Roseland. Now, the next step below that is 230-kilovolt for our system. That's Branchburg-Roseland-Hudson, but that's -- a large part of that is an underground construction, so -- and underground tends to not attract the same amount of concern because it's -- it's underground. Sorry, I don't know how else to complete that sentence. So, I'd say the one that still is the primary focus of attention is Susquehanna-Roseland.

And Dan, this is Caroline. Just one other thought as you look at the numbers here and think about the modeling of our spend. One of the things to keep in mind, as you know, the in-service dates for Susquehanna-Roseland and Branchburg-Roseland-Hudson were delayed, as we said. So in these numbers that we included on slide 25, just for your information, for Susquehanna-Roseland, we estimate that about $550 million of the total of up to $750 million is in the numbers through 2013. And for Branchburg-Roseland-Hudson, about $250 million to $275 million of the total of $700 million is in the numbers through 2013.

So there is some spend as you would expect on these projects outside our forecast period through 2013 given their in-service dates. So if you look at those two big amounts, and you look at this CapEx for transmission, just so you can keep the timing and proportionality, that might be helpful.

Okay, and not to upset Kathleen, but just to clarify one last question. All of this transmission CapEx, you assume, is going to get CWIP? Are there -- is there going to be a subset that wouldn't because they're not discrete, rate-making -- ?

No, no -- that's right. All of the transmission gets formula rate treatment, just the big projects get CWIP. And right now, the only one that's approved for CWIP is SR. So, the logic being, of course, that the smaller projects go in-service much more quickly. So the formula rate treatment gets you as close to the contemporaneous return as FERC feels they need to get you.

Okay, great. Thank you, guys.

Thanks, Dan.

Your next question comes from the line of Greg Gordon of Morgan Stanley.

Thank you. Good morning.

Good morning.

I just have a -- everything you've articulated is crystal clear. But there was one thing I wanted a little more color on if possible. You talk about in the first full paragraph in the press release on PSEG Power a $0.02 decline in earnings associated with wholesale electricity energy supply contracts that you supply from the market. Can you go into a little more detail on what that activity is, and what the aggregate contribution is, if possible?

Sure, Greg. Thanks for the question. Yes, so, we've talked about some of these before, and these are load transactions that we bid on, that -- in most part, load transactions that we bid on whose power we supply through the market. And so, because they're not supplied from our assets, we treat these on a mark-to-market basis. And so, every quarter we're marking both sides of that transaction to market, and we're putting any changes in that through the P&L. So the primary driver of what you see here in the $0.02 is really a function of the same dynamics that are going on in the base business, and that is, in these load contracts, there is still opportunity for migration out of those types of contracts by the provider.

And so, as migration is expected or experienced, and then we forecast it going forward, to a large extent based on the experience that we have, we reduce the value of those contracts in terms of what they would return to the Company. And therefore, we take that mark, because they're mark-to-market, directly in our earnings as we update those forecasts. So, think of this as mark-to-market, its not cash, but it's the representation, our best representation, of the change in value of those contracts, primarily driven by the same thing we talk about in the base business, which is the migration out of these full-requirement [puller] like contracts.

And are those customers also concentrated in New Jersey, or are those customers in the larger PJM market?

In the PJM market near us, but not New Jersey.

And do you have an estimate of what the expected contribution from that business is in terms of the total gross margin outlook for 2010?

Sure, so keep in mind, and I'm glad you asked that, because we do pull this out on a quarterly basis to show you the mark to market, but it is less than 1% of our gross margin. So it is actually a very small piece of our business.

Fantastic. Thank you.

Your next question comes from the line of Paul Patterson of Glenrock Associates.

Good morning. Can you hear me?

Yes, Paul, we can.

Basically, I would -- just wanted to touch base of the Texas sale. What should we think about being the potential [site] for these proceeds, and what your expectation might be to deal with the proceeds, I mean, in terms of what you might -- what the use of proceeds might be?

So, Paul, we're right -- you can respect the fact that we're right in the middle of a sales process now, so we couldn't even come close to remarking on that question, in terms of what we expect for the size of the proceeds. In terms of the use of the proceeds, if we sell, and we're exploring the sale, so we're not sure, we think we have some good opportunities to deploy capital. There's no surprises in there, it's what you've been hearing from us. We have a large capital program and utility, with a nearly 10% [indiscernible] associated with it, and there are some opportunities perhaps to revisit some of those programs and expand them. Our infrastructure is not getting any younger.

We have found some opportunities in Holdings with some attractive terms and conditions, with creditworthy counterparties to do PPAs on the renewable side. We have some [peakers] we're building in Power and some [uprates] in our nuclear plants that were looking at, that are now within the planning horizon. So we think we have some good opportunities in our core business to deploy that capital, if we opt to sell.

Okay. And then, the lease that's remaining, I guess you've got one lease remaining, is that correct?

That's correct.

How should we think about the impact of what you guys might do with it, and would it happen this year, and what would that suggest would be the impact in 2011?

Do you want to buy it, Paul?

I don't think so.

Sure. So we only have one lease remaining. In terms of how to think about it, as you know from what we've been talking about over the past year, the team has been working hard to terminate these leases at appropriate terms. So, as you think about all the leases that we've terminated, what's essentially happened is we reduced our tax liability, essentially by the cash received from the counterparties coming in and going out. So, if the terms are appropriate, we would look to terminate this last lease, but of course we have to talk to the counterparties. If not, we keep the lease.

One thing to keep in mind, though. That -- the termination of the lease where we are with the IRS -- those two things can continue to happen, independent of each other, to some extent. In other words, you don't have to terminate all your leases to try to have a settlement with the IRS. Given what we have now, our exposure on a total basis, is about $330 million. And we're continuing to have discussions with the IRS to see if we can come to terms, and we'll try to do that. At the same time, we'll continue to try to terminate this lease. So, you can really -- one is not dependent on the other. You can really pursue both paths, and that's exactly what we're doing.

Given the size of the remaining lease, though, in terms of its impact to earnings, it will be marginal, in terms of what might happen either from its earnings proceeds next year or a termination. As you know, we have two leases this quarter, and it's just 0.03. So it's really a small number, and I think it's a credit to the team's work to really bring us down to only one lease left.

I want to make sure -- that $330 million exposure, there's $320 million on deposit.

Correct, correct.

Okay, great. So then when we're rethinking about 2000, and, I mean, is it likely that, I guess, we won't see much of any of this activity in 2011?

That's right, because there's only one left. So it will either be terminated, or it's the last one left.

Okay. Thanks so much.

Your next question comes from the line of Paul Fremont of Jefferies.

Thank you very much. I guess I am a little surprised in terms of use of proceeds not to hear possible share repurchase as an option, particularly given the fact that the Company has gotten the balance sheet to where you want it to be. So, I guess I'd be curious to hear why you wouldn't consider using at least a portion for share repurchase.

So, Paul, it's Ralph. Thank you, by the way, for recognizing the condition of the balance sheet. We are proud of that, we've worked hard for four years now, at least, to get it to where it is. And we are pleased with that condition. Most of our long investors tell us, look, we look to you to find good ways to deploy capital. And if you can get us risk -- attractive risk-adjusted returns, then we want you to use it in that way.

So, we are obviously disclosing to you the things that we have a high degree of confidence we can invest in. What I was trying to say earlier to Paul, was that there are many things like that that we consider all the time. Some of them we shred the paper and say oops, that one didn't pan out the way we want, but there are others that are percolating that -- all organic in nature, that we like and we think we can put that money to good use. So, I'd rather grow the business with attractive risk-adjusted returns and create a positive NPV investment for our shareholders than something that just has a zero NPV.

As a follow-up, there were a number of unresolved issues in the rate cases that were supposed to be dealt with in separate proceedings. Have those proceedings started, and can you just give us an idea of where you are on those issues?

So, there were two issues in particular, one related to a tariff rate that Power had pertaining to gas purchases. I guess we're about to disclose in a Q, so I shouldn't front-run that, where that stands. But we have been in settlement discussions, and we'll have a little bit more color on that in the Q. Suffice to say that there was a prior published date of October 25 when the hearings would take place, and you can go to the BP website to see that those hearings have not taken place, and draw your own conclusions from that.

The second issue is on consolidated taxes, and there have been a series of extensions that have been granted to us to file for a full-blown proceeding on consolidated taxes and how those are applied, not just to us, but to all utilities in New Jersey, inclusive of water utilities and gas utilities. So that is still in the regulatory calendar, being pushed off a bit.

And keep in mind, as we've said before on consolidated taxes, should any proceeding result -- come to any conclusion about consolidated tax adjustments, that would be prospective only and there would be no impact on the rate case that we just settled.

Okay. And then, I was curious, on your coal cost per megawatt hour, there's a 10% reduction if I compare this quarter to a year ago's quarter. Can -- what accounts for that saving?

Sure. So, Paul, as I mentioned, we are burning more coal, right? So as we burn more coal we bring the inventory down, and some of the higher-priced inventory comes off and we have lower-priced inventory that we're burning. Also keep in mind, we talked about earlier this year that the price of our Adaro coal relative to last year also came down. So that really moderated our coal costs overall, as we burned more, brought down the inventories, and had some lower-priced coal from Adaro.

Great. I think that's it. Thank you very much.

Thanks, Paul.

Your next question comes from the line of Jonathan Arnold of Deutsche Bank.

Good morning. Two questions. The first one relates to the distribution capital spend. I think I heard you right, that it's down $425 million from what you had given before. And if I remember rightly, $140 million of that you communicated at the Q2 stage. I wanted just to check that number is -- that the $425 million is not incremental to the $140 million.

Oh, no, no. The $425 million is obtained by taking $140 million and multiplying by three and rounding.

Oh, okay. I see. Can you -- so the $140 million is not an incremental in any way?

No.

No.

The $140 million was an annual number?

Correct.

Okay, and the $425 million is over the three years.

Right. And in fact, if you notice on our page 25, we give the number out through 2013. So while the $425 million is $140 times three, when you look at this page you should know that in our planning, we planned that distribution spend at $140 million lower each year over the entire period. We're just reconciling to our prior numbers there.

Okay, I get it. And is that $400-ish million number where 2012 and 2013 shake out, is that a reasonable run rate? Or are you still doing things out at the end there which are somewhat one-off in nature?

Yes, so you know, that is our normal run rate for matching our maintenance CapEx to our depreciation so we can achieve our allowed return. So the earlier years are driven by the stimulus funding that we had received approval for in 2009.

And then on the same slide, you have this sort of, obviously the drop-off in the renewables line. Is the $30 million number in 2013 -- should we think about it as just something you have less visibility on what you're likely to be doing out in that time frame, or -- ?

Jonathan, that one is tough to predict. As you know, the state is now revisiting its energy master plan, and I suspect the entire 20% renewables -- it's not exactly 20%, but it's close to that, by 2020 will be something that will come under review. At these CapEx numbers for renewables, we are nowhere near the run rate required to achieve the 20% by 2020, so I think we'll get a little greater clarity at the end of this year, first quarter next year, in terms of how aggressive the state wants to be for the next decade, and that will influence 2013 and beyond.

Okay, great. Thank you. And just on one other topic, I want to make sure I understand the sensitivities you gave on migration. 5% incremental migration in 2011 would be about a $0.015 per share hit. But then you talked about 15% in terms of average hedged prices. Was that a -- 15% beyond the 5%, so 20% in total? I think I -- the release said one thing and then you seemed to say something slightly different in the prepared remarks.

Right. No, thanks, Jonathan. Just to clarify, to give you some pieces of the map maybe just to help you to think that through. In terms of the $0.015, so if you think about what our coal and nuclear output, let me just walk you down this a little bit, because that may help. About 50% of our coal and nuclear output -- in total, coal and nuclear is about 40 terawatt hours a year. So, half of it is about 20 terawatt hours. With the migration we've already seen in BGS, BGS is about 15 terawatt hours. It used to be half, and now it's less than that because of the migration.

So if you take 5% of the 15 terawatt hours and you multiply that out by the delta in the embedded PJM West price in the BGS contract with the current level of PJM West price, and you roll out that math, you get about $0.015. So that's how we came up with $0.015. The 67 -- the change in the hedge price was simply running that same sort of thinking and that same sort of calculation by taking that out of the hedged amount that we have pulling that migrating BGS load out of the hedged amount, and then recalculating the weighted average hedged price of the portfolio, keeping in mind that the BGS hedge price has more things in it besides just the energy -- all of those things we talked about in our bar chart, relative to the PJM West hedge, which would not have hedged things like basis in it.

So you have to just do that math in two pieces. So, one is about how to do the $0.01 per share, the other is weighted average of our hedged portfolio average price.

15% would be on top of 5%, so really 20%.

No, no. What we're trying to give you is a rule of thumb way to think of migration. You can easily think of the rule of thumb in terms of EPS impact, or you can think of the rule of thumb in terms of gross margin impact.

It's just two different --

Well, unfortunately, we gave you two different thumbs. We gave you a 5% thumb and a 15% thumb.

No, I was just making sure they were -- they were separate. Finally, on that topic, is it reasonable to assume, given that switching showed up during the course of this year, that there will be another $0.04 or so of carry on into 2011 from 2010?

We haven't -- as you know, we're not forecasting 2011, so it's too soon to know. As we pointed out, we do have, obviously, retailers out looking for residential switching. We don't know the success of that yet, so we're not really sure. One thing I would just add is keep in mind we saw levels of migration appear to be similar at the end of this quarter to where they were last quarter. But you also have to keep in mind that that's always a function of that headroom calculation, as we call it, and with the hot weather and the spike in prices, you saw headroom actually go the other way. Remember, last year in the summer we talked about it being very high. This year, this summer it was very low because of the spike in prices. So when you come back to a more normal condition, and then with what's happening with residential, it's too early to really forecast what that would be.

Thank you very much.

Sure.

Your next question comes from a line of Steve Fleishman of Merrill Lynch.

Hi. Actually, you hit the topic I just wanted to clarify on. What was the number percent of load that migrated this year? Was it basically -- are you saying that basically it wasn't any incremental migration?

It started out at 19% -- 18%, 19%, and it's now at about 24% at the end of third quarter. It was also about 24% at the end of the second quarter.

That's right.

Okay, so 24%. And the 15 terawatt hours is what it is now after the 24% has left.

Correct.

And when you talk about the 5% sensitivity, that's off the 15 terawatt hours, so that's off of where we are today, not where the load used to be.

Correct. It's also off of the comparison between the prices in BGS and the prices today. So, you have to be careful when you look at the percentage migration like last year and try to say it should be the same number, because you have to compare the embedded PJM West price to the market prices last year.

Right.

So all we're trying to do is keep current, right? The current migration amount, the current terawatt hours, and a current estimate of what the loss would be for an incremental percentage point of -- or five percentage points of migration, given the current delta.

And we generally assume that you resell the power just into the around-the-clock wholesale power market in PJM? Is that the right way to look at it?

For the most part, yes, Steve. But we'll also try to aggregate a full-requirements product or bundle of products or TPSs, third-party suppliers. So, as Caroline said, our generation output is up this year. It's just the price we're getting for it is different, depending on whether we're selling it through BGS or selling it into the market, or selling it through bilateral arrangements to third-party suppliers.

And, we're doing -- as Ralph said, we're doing some of those products like a [six load shape], for example. But we're not going to take full-requirements risk on the things that have already migrated out, and take the full-requirements risk over again.

Okay. And then, with respect to -- Ralph, you mentioned O&M savings, and with pricing coming down, managing costs. Is that something where we should think about maybe generation O&M being flattish, so you offset growth? Or is it something where it's possible that it could come down going forward?

No, I think I would stay with the numbers that Caroline and Kathleen and I have been showing you now for probably a year in terms of the CAGR, the comp and annual growth rate for O&M. That's not easy work Steve, I'm not looking for sympathy. Our hands are full just getting there.

And that's about half a percentage that we've been forecasting for CAGR.

Okay. And then, one last popular topic on the -- from a credit standpoint. Where is roughly the FFO to debt at PEG Power, either now or when you look through the downcycle?

Right. So, good question, Steve. As you know, and we've said before, we target as a floor -- not as a target, but as a floor, of 35% FFO to debt for PEG Power. And as we look at historically where we been, as we look at our forecast, we see ourselves staying comfortably in that range. PEG Power's debt-to-cap ended this quarter at about 42.5%, similar to what it has done in prior quarters. We managed those debt levels to make sure that we keep the balance sheet trim, and we see ourselves being able to sustain that kind of level, 35%, as a floor, going forward.

Thank you.

Your next question comes from the line of Neil [Nietra] of Simmons and Company.

Hi, good morning. Just wanted to clarify what percentage of the 24% of switching comes from residential customers versus commercial customers, and maybe just some color on the switching activities between commercial and residential and how they would differ between the customer classes.

Sure. So on residential customers, we're seeing almost no switching at this point. So, we've talked about numbers in that 1% range or so, depending on the particular LDC you might see something different, but we're still -- the numbers are very small. All of what we've talked about in terms of the drivers of the incremental hit to our EPS from migration has been in the commercial and industrial, so we really haven't seen it as a factor to date. Keep in mind, as you probably know, there are folks out there looking to sign up residential customers. They're probably stickier than the commercial and industrial, but we haven't seen that yet. So we'll have to see that going forward.

Okay. And then second, at this point, do you believe that the east portion of Susquehanna-Roseland is going to be included in the 2014, 2015 RPM auction, or is that going to be delayed until the auction after?

No, I think that in general right now, the line is being viewed in its totality. And the desire on the part of policymakers in the region to split it really isn't there. And I think that's not unreasonable on their part. People want to see what the National Park Service is going to do.

So, would you view it as being in the 2015-2016 auction, or 2014-2015?

I don't have the dates straight in my mind. Do you know ?

So yes, it's potentially at the earliest, the 2015-2016, because the eastern portion is mid-2014, the western portion is mid-2015, so if it doesn't slip and if it's on time, you might see it then come back for 2015-2016.

Great. Thank you very much.

Your next question comes from the line of Mark Decorsid of FBR Capital Markets.

Hi. Thank you. Good morning. Just a question on the hedges, if I may come back to that subject. Have you been hedging 2012 at Power?

Yes, so we have been hedging 2012 at Power, but very small degree, so the hedges for 2012 for Power are in about the mid- 20% range. Typically, think of, as you go out the markets become obviously less liquid. And of course the BGS, by nature of it being a three-year contract, puts some percentage out in 2012. But right now, the 2012 hedged amounts are relatively small, in that mid-20% range. Remember, we try to put this in ratably, so that as you move into a year, we move up in the hedge percentages. But right now, 2012 is about that amount.

Right, thank you. And one point of confusion on 2011. When I looked at the prior disclosure on the hedges, I saw 68% of coal and nuclear output was actually hedged in 2011 at $75. And in the new disclosure I see 68% at $71. What's the disconnect there? Why does the percentage hedge remain about the same?

Yes, that's a good question. I don't think we gave out that number. But I know if you take a ruler on the graph, you can get to a number similar to that for the hedged amount. Yes, so when we provided that disclosure at midyear, we were using the data we had that was a little bit older. What we've done now is to update that hedged price for the assumption of the migration amount that we just talked about. The 22% to 24%. So as we updated that and assumed that going forward, that pulled that average price down, even though the hedge percentage is not really that different. The average price has come down. We pulled through the hedged -- the migration amount added a little more in hedging, that's how you get back up to about the same hedge percentage. But your weighted average math is now a little bit different.

Okay. We may have to discuss this off-line. As a quick last question, have you disclosed the amount of O&M in depreciation that's carved out of the Texas assets?

No we haven't. We haven't talked about that in terms of overall profitability, except to say that they are profitable. And we did give you in our deck this quarter, as we typically do, the margin performance for Texas. So just to point that out, on page 19, $41 million in gross margin from the two assets both planned in the third-quarter.

Thank you, that's very helpful.

Your next question comes from the line up of Ashar Khan of Visium Asset Management.

Good afternoon. The way I look at it is, by the time we come to the next BGS auction, this migration risk will go lower because [hedge room] would have decreased as the average goes down. Is that a correct assumption?

That's correct. In theory, as BGS approximates the market, there's no room for the SG&A associated with customer acquisition, so how do you acquire customers?

So in essence, as commodity prices -- so we are basically, what we are doing is we are coming to market with this migration a little bit earlier, but then as prices kind of -- we go to 2012 and then go to 2013 when capacity kind of picks up. Our outlook going forward in terms of higher capacity prices and everything going into 2013, that's not affected. The only thing that is being affected is that we might be coming to the trough a little bit earlier -- the trajectory of the trough is becoming a little bit changing and going a little bit earlier than before. Is that correct?

That's correct, Ashar. That's exactly right.

Okay. Thank you so much.

Your next question comes from the line of Leslie Rich of JPMorgan. Morgan.

Hi. I wondered if you could just touch on the CapEx for PEG Power and if that outlook has changed at all. And in particular, I believe you might have allocated some CapEx to growth projects, and maybe that's TBD based on the sale of the Texas generation. But just wanted to make sure my total CapEx numbers were in the ballpark.

Yes. Thanks, Leslie. No, we haven't really changed the numbers for PEG Power. Keep in mind that we did have some growth spending in there. It wouldn't change because of Texas, as the growth spending is essentially things like nuclear uprates at our nuclear plants, at Peach Bottom in particular. And the [peakers] that we bid in successfully in the last two RPM auctions, they are the primary drivers of the growth CapEx going forward. The other thing that we've noted a lot, and it's in the table that we put in the K, and it's still relevant, is the decrease in the environmental spending, environmental CapEx, because the BETs are essentially complete at the end of this year.

So that number comes down. As you think about that, also, for going forward, keep in mind what that also means is those assets go into service, and of course then they start o become depreciated as well. So that's essentially the story on Power, and it really has not significantly changed. The [peakers] and the uprates are the growth capital, the environmental spend winds down, it's actually part of the reason why we are able to do what we're doing, which is to fund the utility, allow it to grow, while still maintaining the balance sheet that we have.

Okay great. Thanks for clarifying that.

Thanks.

Operator, I think we've reached our allotted time, unless there is another question.

Yes, there is another question. Would you like to take that question at this time?

Yes, yes, we will. Thank you.

Your next question comes from the line of Michael Lapides of Goldman Sachs.

Hey, guys. Thank you for taking my question. I was just looking at New Jersey electric switching stats for the various P&D companies. Notice that the total amount of loads switched in the PSE&G service territory at the end of August was about 31%, but you talked about the amount of power having seen migration being 500 or 600 basis points less than that. Just curious to understand the explanation for what you think may be driving that delta.

Yes. Remember, Michael, that BGS is a statewide phenomena.

Sure.

So you have to look at PSE&G, Atlantic Electric, and Jersey Central. I don't have the numbers memorized, but I'm pretty sure Jersey Central and Atlantic have a much larger residential population, and therefore, they'll have a smaller amount of switching.

Right. Got it.

You have to be careful if you're looking at commercial and industrial midsize or the CIEP class of load, which is essentially out of -- migrated out already. So, depending on which customer class, and within BGS there are customer classes, you have to be careful when you look at those percentages to come up with the right numbers, that you should put in our models when you're looking at our numbers.

Yes, and it seems that the place where acceleration, at least through the end of August, had really picked up, or at least that it surprised us a little bit, was in the really small commercial side, the sub-500-kilowatt customers. Just where the customer count and switching level had picked up pace a bit. How do you compare the profitability of that customer class versus residential?

I'd say for commercial and industrial, just looking at the class in the aggregate, looking at the pieces and then looking at the total, we see commercial and industrial, just to give some color around your numbers, at about two-thirds switched in the aggregate out of BGS. We don't really do profitability specifically by customer category. But just to give you to round numbers, about two-thirds out of commercial and industrial, and as we said, only about 1% out of residential.

Got it. Okay, thank you. Much appreciated.

Sure.

Thank you all. If you do have additional questions, you should feel free to call Investor Relations at 973-430-6565. That's my number. Or Carlotta [Chan Lane] at 973-430-6596. We appreciate it. Thank you very much for your interest and participation in today's call.

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