公共服務電力與天然氣 (PEG) 2010 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Kenisha, and I will be your event Operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group fourth 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 Tuesday, February 22, 2011, and will be available for telephone replay beginning at 1.00 PM Eastern Time today, until 11.00 PM Eastern Time on March 1, 2011. It will also be available as an audio webcast on PSEG's corporate website, at www.pseg.com. I would like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Kenisha, and good morning. Good morning, everyone, who is on the phone call. We appreciate your participating in our call this morning. As you are aware, we did release our fourth quarter and full year 2010 earnings statements earlier today. And as mentioned, the release and attachments are posted on our website, www.pseg.com, under the Investor section. We also posted a series of slides that detail operating results by Company for the quarter. Our 10-K for the period ended December 31, 2010 is expected to be filed later this week.

I'm not going to read the full disclaimer statement, but I do ask that you read all of those comments contained in our slides and on our website. The disclaimer statement regards forward-looking statements, detailing the number of risks and uncertainties that could cause actual results to differ materially from forward-looking statements made therein. 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 required by applicable securities laws.

We also present a commentary with regard to the difference between operating earnings and net income, reported in accordance with Generally Accepted Accounting Principles in the United States. PSEG believes that the non-GAAP financial measure of operating earnings provides a consistent and comparable measure of performance of metrics, to help shareholders understand performance trends. I would now like to turn the call over to 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. I'm going to ask that you limit yourself to one question and one follow-up, and we hope to have enough time for all of your questions. Thank you.

Thank you, Kathleen. And thanks, everyone, for joining us today on this call. Earlier this morning we reported operating earnings for the fourth quarter of $0.60 per share, which resulted in operating earnings of $3.12 per share for 2010. I want to remind you that the results for 2010 reflect the movement of the Texas generating assets to discontinued operations. If we had left Texas in, our operating earnings would have been $3.15. We were able to achieve earnings within our guidance range for the year, despite very difficult market conditions.

Each year, our employees put a great deal of effort into meeting the objectives we establish, regarding the needs of our customers and shareowners. We are indebted to PSEG's workforce. We would not be able to achieve our financial and operation goals without their daily commitment. It is their hard work that helped 2010 become a year of significant accomplishment, despite the challenges of the marketplace.

I want to take a few moments to review these accomplishments with you. At Power, 2010 represented a year of record output from our fleet, with an increase in generation of 8.7%. We completed installation of the back-end technology at our New Jersey coal stations. These upgrades support their operation under more stringent environmental rules. We also committed to invest in new peaking capacity in Northern New Jersey, as well as initiated work on some nuclear upgrades. Power's Hope Creek nuclear station achieved a 100 INPO rating. This is the result of the investment in people, processes, and equipment we have made to lift our nuclear program to world-class levels.

Power announced that it has entered into contracts for the sale of its two Texas gas-fired combined cycle generating units. The sales are expected to close in late March, early April. But our accomplishments were not limited to PSEG Power. PSE&G won its ninth consecutive Reliability One award, as the most reliable electric utility in its region. PSE&G settlement of its electric and gas rate issues in mid-2010, while not all that we wanted, allowed it to earn more reasonable returns for the year, and will help support its long-term rate base growth of 9% per year.

In Energy Holdings, 2010 was a year of continued emphasis on eliminating financial risk. We did this by terminating all of our remaining international leverage leases and paying down all recourse debt at the Holdings' level. Energy Holdings also made strides in building renewables outside New Jersey, with 27 megawatts of new solar capacity entering service under long-term power purchase agreements. But that is in the past.

As we head into 2011, we will continue to focus on maintaining high levels of operating efficiency, and meeting our commitments to providing a reliable, clean, and economic product for our customers that supports our shareholders' expectations. We will not, however, be able to offset the impact on operating earnings in 2011 from a decline in the market price for energy, and the increased expenses associated with commercial operation of the back-end technology on our coal units.

We are providing you with operating earnings guidance for 2011 of $2.50 per share to $2.75 per share. The replacement of high-priced hedges we have enjoyed since 2008 with lower-priced hedges reflecting market realities, and the continued loss of customers under the basic generation service contract -- or BGS, as it is commonly called, to retail suppliers are expected to reduce margins and earnings at PSEG Power in 2011.

Our challenges are not limited to the marketplace. As you are all aware, we are faced with an intrusion by the state of New Jersey into the competitive power market. In January, the state passed a new law establishing a long-term capacity agreement pilot program, which provides for 2,000 megawatts of subsidized baseload or mid-merit electric power generation. New Jersey is seeking ways to promote newer, cleaner generation in the near term, to meet its energy and economic development goals. We understand the desire to implement policy that supports economic growth. The legislation, however, removes reliance on the marketplace, and would substitute government management of supply, versus the private sector.

This is an approach that has been tried many times in the past, and failed. It poses a challenge to investment in the state, and is likely to have unintended consequences for the customer. We have, therefore, joined with other generators to challenge implementation of the legislation. A complaint has been filed at the Federal Energy Regulatory Commission, to ensure that the market decides what type of investment in energy capacity are best, and keeps the risks and rewards of such investments with investors, not customers. An action has been filed at the US District Court for the State of New Jersey by us and others, challenging the constitutionality of the legislation under the Supremacy and Commerce clauses of the US Constitution.

However, we are readying ourselves to operate in this potentially new framework. Therefore, we are also considering submitting a bid for new capacity at our existing sites, as part of the New Jersey-supported procurement process. No single generator or affiliate may win over 700 megawatts of the 2,000 total megawatts to be awarded contracts. The bid is not without risk if the legal and regulatory challenges are successfully upheld; and we will only participate if we believe it is in our customers' and our shareholders' best interests. An investment in new capacity will also have to be considered as part of a long-term answer to the retirement of generation under New Jersey's high electric demand day regulations, which are scheduled to take effect in the middle of 2015.

We strongly believe we remain favored by our asset mix, their location, and our environmental position. These all support our continued market advantages, as Clean Air Act regulations, in particular, become increasingly more stringent. We begin 2011 with a strong balance sheet, capable of withstanding the challenges from the marketplace; and one that will also support our plans to invest $6.7 billion over 2011 through 2013, without the need to access the equity markets. In addition to this level of capital spending, PSE&G has requested approval from the New Jersey Board of Public Utilities to spend approximately $400 million over a 24-month period on energy efficiency, gas distribution, and electric distribution programs, in support of state efforts to boost the economy by improving our infrastructure.

These efforts would represent a continuation of the stimulus-related spending programs, which received approval in 2009. These programs provide appropriate risk-adjusted returns for our shareholders, and support maintenance of the systems' reliability at the levels our customers have come to expect. We should know in April if this additional level of capital spending has been approved. The Board of Directors recently declared a common dividend for the first quarter of this year, which represents a continuation of the common dividend, at an annual rate of $1.37 per share. This declaration is the start of the 104th year of PSEG paying an annual common dividend to our shareholders on an uninterrupted basis.

We are proud of our record of returning cash to our shareholders, and recognize the importance of maintaining a strong financial position that supports the common dividend and investment plans for growth. I will now turn the call over to Caroline, who will be available to answer your -- and will be available to answer your questions at the close.

Thank you, Ralph. Good morning, everyone. As Ralph just said, PSEG reported operating earnings for the fourth quarter of $0.60 per share, versus operating earnings of $0.66 per share in last year's fourth quarter. Our earnings for the fourth quarter brought operating earnings for the full year to $3.12 per share, versus operating earnings for 2009 of $3.09 per share. The results fell in the middle of our operating earnings guidance for the year of $3 to $3.25 per share.

The results for the quarter and the full year have been adjusted to reflect a reclassification of the Texas generating assets to discontinued operations. For your information as you complete your models, operating earnings from the Texas assets were $0.03 per share in 2010, and they were offset by a mark-to-market loss of $0.02 per share, resulting in earnings from discontinued Texas operations of $0.01 per share in 2010. In 2009, operating earnings included a $0.03 per share contribution from the Texas assets, which was offset by a mark-to-market loss of $0.03 per share, as well.

On slide 4, we have provided you with a reconciliation of operating income to income from continuing operations and net income for the quarter. As you can see on slide 10, PSEG Power provides the largest contribution to earnings. For the quarter, Power reported operating earnings of $0.42 per share, compared with $0.51 per share last year. PSE&G reported operating earnings of $0.16 per share, compared to $0.13 per share last year. And PSEG Energy Holdings reported operating earnings of $0.01 per share, compared with operating earnings of $0.03 per share in the year-ago quarter. Finally, the parent Company reported earnings of $0.01 per share, compared with a loss of $0.01 per share in last year's quarter.

We've also provided you with waterfall charts on slides 12 and 13 that take you through the net changes in quarter-over-quarter and year-over-year operating earnings by major business. And I'll now go through each Company in more detail, starting with Power. As shown on slide 16, PSEG Power reported operating earnings for the fourth quarter of $0.42 per share, compared with $0.51 per share a year ago. The results for the quarter brought Power's full-year operating earnings to $2.15 per share. Power's fourth quarter and full year operating earnings for 2010 and 2009 reflect the exclusion of earnings from the Texas generating assets, pending their sale.

Power's results in the fourth quarter benefited from a price uplift in the wholesale market, which limited the impact of a decline in volume on earnings. Higher prices and improved margins added $0.03 per share to the quarter's earnings. Power's generation volumes increased 8.7% for the year, to a record level. Output during the quarter, however, declined by 5.7%. The decline in volume during the quarter reduced earnings by $0.02 per share. Output for the quarter was affected by a planned 26-day refueling outage at Power's 100%-owned Hope Creek nuclear reactor, and planned implementation of the back-end technology at our New Jersey-based coal units.

The gas-fired combined cycle units maintained their availability in the quarter, leading to a record level of generation for the year. This enhanced Power's profitability in the quarter, as Power was open to take advantage of the expansion in spark spreads during the quarter, to $22 per megawatt hour from the $11 per megawatt hour prior quarter; and contributed to the $0.03 improvement in margin and earnings that I mentioned earlier for the quarter.

The migration of customers away from the BGS contract continued to impact Power's earnings in the quarter. We estimate earnings in the quarter declined by about $0.01 per share, due to an increase in migration. For the year, customer migration reduced Power's earnings by $0.04 per share. And at year-end, approximately 30% of the BGS-related contract volume had switched to alternate suppliers of energy. The level of switching was higher than anticipated earlier in the year, as retail suppliers turned their attention to the residential market. The impact of the increased volume on earnings was limited, however, by the weather-related uplift in wholesale energy prices, as effective headroom was reduced.

The increase in pricing during the quarter offset the reduction in volume, and resulted in gross margins for the quarter of $53.20 per megawatt, compared to $51 per megawatt hour during the fourth quarter of 2009. For the year, however, Power's gross margins declined from $54.30 per megawatt hour, from $60.15 per megawatt hour in 2009. The continued erosion in margin on certain wholesale electric energy supply contracts that Power supplies from the market also reduced earnings by $0.03 per share in the quarter.

An increase in operating and maintenance expense associated with the refueling outage at our 100%-owned Hope Creek nuclear plant in this year's fourth quarter, compared with a refueling outage in the year-ago quarter at the 57%-owned Salem 2 unit, which reduced earnings in the quarter by $0.02 per share -- and by the way, the 26 days associated with the Hope Creek's latest refueling was among our best performance ever in that regard. In addition, Power's recognition of bonus tax depreciation on investments lowered income available for the manufacturing-related tax credit. This increased Power's tax rate, and reduced earnings by $0.04 per share.

PSEG Power's operating earnings for 2011 are forecast at $765 million to $855 million. The decline in forecast operating earnings is the result of several factors -- an anticipated decline in realized energy prices and capacity; an erosion in margin from customer migration; an increase in depreciation, with the commercial operation of the back-end technology at Hudson and Mercer; and the continuation of reduced manufacturing tax credits, due to bonus depreciation. And I'll briefly touch on each of these.

First, a decline in realized energy prices. The 2008 BGS contract for $111.50 per megawatt hour will be replaced on June 1 of this year, by the recently concluded auction contract for PSE&G, which was priced at $94.30 per megawatt hour. Overall, the average BGS price is therefore reduced by about $5 per megawatt hour, beginning in June. In addition, for non-BGS-related generation, average realizations in 2011 will be impacted by a reduction in capacity prices, as the 2009-2010 RPM capacity auction price of $191 per megawatt day rolls off at mid-year, and is replaced by a $110 per megawatt day price for 2011-2012. Also, wholesale power prices, which benefited from weather-related improvements in demand in 2010, are expected to be lower in 2011 from 2010 average prices. As a result, we expect lower market prices and lower overall generation.

As a note, this lower generation means our coal supply needs over the intermediate term will be lower than historic requirements. Our reduction in anticipated output has effectively lengthened our coal supply, which will be sufficient to meet 2011's coal requirements. Second, the impact on margin from customer migration. At the end of 2010, approximately 30% of customers served through the BGS contract migrated to retail suppliers of power. Our estimate of earnings and the amount of energy hedged for the year assumes the level of customer migration in 2011 increases to between 38% to 40% by the end of this year. This level of migration would reduce the amount of energy supplied through the BGS contract to an average of 14 to 15 terawatt hours for the year, compared to 17 hours terawatt served through the BGS contract in 2010.

Following the conclusion of the most recent BGS auction in New Jersey, approximately 95% of Power's anticipated coal and nuclear generation of approximately 40 terawatt hours is hedged at an average price of $68 per megawatt hour. For 2012, approximately 45% of generation is hedged, at an average price of $68 per megawatt hour. Our assumptions on migration that I just mentioned are now embedded in the hedge percentage and the averaged hedged prices. For comparison and for your reference, the average hedge price in 2010 for the 91% of output that we had hedged during the year was $72 per megawatt hour.

Third, Power's results will also be affected by an increase in depreciation expense of $45 million per year, primarily associated with the commercial in-service date of the back-end technology on the New Jersey coal units. In addition, Power's results will reflect the impact of bonus depreciation on its ability to capture manufacturing-related tax credits, at levels similar to what we had just disclosed for 2010.

Let me now turn to PSE&G. PSE&G reported operating earnings for the fourth quarter of 2010 of $0.16 per share, compared with $0.13 per share for the fourth quarter of 2009, as shown on slide 23. PSE&G's full year 2010 operating earnings were $430 million, or $0.85 per share, in line with our guidance; compared with operating earnings of $321 million, or $0.63 per share, for 2009. PSE&G's earnings were driven by the electric and gas rate settlement, an increase in investment, and a reduction in operating and maintenance expenses.

An increase in electric and gas rates of $73.5 million and $26.5 million, respectively, that went into effect on June 7 and July 9, added $0.01 per share to earnings in the quarter. The improvement in earnings for the quarter was not as great as you would expect if revenue increased -- if the revenue increase was distributed evenly throughout the year. The rate schedule for residential electric customers is designed to provide a larger percentage of revenue during the summer -- the period of peak electric use, as opposed to the winter period, which is more weighted to gas consumption.

An increase in revenues associated primarily with investments for capital infrastructure, renewables, and transmission investments added $0.02 per share to earnings. A reduction in operation and maintenance cost of $0.02 per share was offset by an equal increase in depreciation and amortization expense.

PSE&G experienced an increase in demand from all customer classes during the fourth quarter, reflecting weather that was colder than normal and colder than last year, and more stable economic conditions. Electric and gas sales increased 2% and 3.4%, respectively, during the fourth quarter. The increase in demand during the fourth quarter resulted in electric sales growth of 4% for the full year. Gas sales declined 4.4% for the year, reflecting last winter's -- the 2009-2010 winter's -- net warm weather.

The impact on earnings in the fourth quarter from the mostly weather-related increase in gas sales was limited by the implementation of a weather normalization clause, as part of the gas rate settlement. Just to remind you, the weather normalization clause allows PSE&G to collect its margin, without being subject to the impact of weather on its gas business. So, when it's colder, our gas margin will not go up by as much as in the past. Similarly, warmer -- if the weather is warmer than normal, we will not be as adversely affected.

The improvement in PSE&G's operating earnings in 2010 resulted in an earned return on the equity invested in the Company's electric and gas distribution assets of 9.7%. PSE&G earned an average return on the equity invested in transmission of 10.7%. PSE&G's operating earnings for 2011 are forecast at $495 million to $520 million. Operating earnings will be influenced by a full year of electric and gas rate relief, and a $45 million increase in transmission revenues, effective on January 1, 2011, and increased investment. With the forecast improvement in earnings, PSE&G would represent approximately 38% of enterprise's forecast 2011 operating earnings.

Let me now turn to PSEG Energy Holdings. Energy Holdings reported operating earnings for the fourth quarter of 2010 of $0.01 per share, compared to operating earnings of $0.03 per share for the fourth quarter of 2009. The results for the fourth quarter brought Energy Holdings' full year 2010 operating earnings to $0.10 per share, which was a slight improvement on 2009's operating earnings of $0.09 per share. And the decline in Holdings' operating earnings for the quarter reflects a reduction in gains reported on lease terminations and lower project earnings of $0.03 per share, as well as the impairment of an asset, which reduced earnings by $0.01 per share. These items more than offset the benefit of lower interest expense and other items, which improved earnings by $0.02 per share.

Energy Holdings successfully terminated the last remaining LILO/SILO leverage lease during the quarter; and this termination reduced Holdings' net cash exposure to $260 million at the end of December of last year. As of -- just a reminder, Holdings has $320 million on deposit with the IRS, to defray potential interest cost associated with the tax matter. Energy Holdings' operating earnings for 2011 are forecast at between $0 million to $5 million. The lower earnings guidance for 2011 reflects the absence of $20 million in gains on lease terminations, since they're now all terminated, net of impairment of assets; lower earnings in the remaining Holdings portfolio, due to asset sales; and lower solar-related tax benefits, due to lower megawatts expected to enter service in calendar 2011.

Just a brief word on financing before we go to your questions. As many of you are aware, we capped a fairly active year with two financings in the fourth quarter. In October, at PSE&G, we refinanced $100 million of 6.4% tax-exempt debt, with a mandatory put due December of 2011, and an initial term rate of 1.2%. And in December at Energy Holdings, we redeemed the remaining $127 million of 8.5% senior notes due on June of 2011, using cash on hand. And we're in good shape entering 2011.

As Ralph mentioned, PSEG Power announced earlier this year that it has reached agreement to sell its Texas gas-fired combined cycle capacity in two transactions with a value of $687 million; and these transactions are expected to close in late March or early April. We also expect bonus depreciation to improve cash by about $900 million over the period 2011 and 2012; and of that total amount, we expect to see about $750 million in 2011. We're very pleased with the condition of our balance sheet, and of course, all of our credit metrics. With that, I'll now turn it back to the Operator, and we're ready for your questions.

Ladies and gentlemen, we will now begin the Q&A session for the members of the financial community. (Operator Instructions). One moment, please, for your first question. Your first question comes from Daniel Eggers.

Good morning. On the migration issue, kind of the pickup of migration from previous expectations, if you could shed a little more color on how much of that -- the incremental increases are coming from the residential side. And what's your level of confidence that the 38% to 40% switching by the year end is a good number?

Sure. Thanks, Dan. Yes, you know, we try to look at this and forecast it, based on the best information that we have. Just to give you a little more color there on the migration, we talk about the 30% -- remember we talked about 24% at the end of the third quarter. We also talked about the fact at the end of the third quarter there was more of a push for the residential, and we hadn't seen too much effect at that point in time.

What we're seeing right now in terms of our estimates of migration at year-end, about 55% of the commercial and industrial customers who can be served by the BGS product have migrated. And for residentials, we see about a 7% net migration for those customers at year-end. In terms of forecasting, obviously, it's something we spend a lot of time internally looking at, with a variety of models to try to triangulate it. And so, we're giving you that guidance range of about 38% to 40%, as reasonable. Keep in mind, there's a bit of a lag in the data. So we're working with data that comes to us through about November; and then, we're estimating it out during the period.

Okay. And then, on the switching potential, are you guys re-evaluating, maybe, your retail strategy, as far as trying to retain more of those customers or pursue them another route, as this number gets bigger with time?

So, Dan, this is Ralph. We're not reconsidering our retail strategy. It's a very difficult business, with razor-thin margins, where one mistake wipes out a year's worth of effort. But what we are doing on the wholesale side is, of course, we are working with third-party suppliers to meet their needs, and remaining active in that regard. The -- remember, over time, as BGS begins to more closely mirror the market, we at Power will be in -- somewhat indifferent as to whether our customer's a BGS customer or a third-party customer. Right now, the effects are painful, because of the rapid drop in market prices. I think Caroline may want to add to that.

And Dan, one other thing to keep in mind, relative to the retail strategy. One of the things that we've talked about during the year -- and as we saw with very, very warm weather and higher prices, is that effective head room does tend to move around quite a bit. And so, to the extent that you think about the business being predicated on a certain amount of head room that you might forecast based on, say, normal forward curves, we did see periods during the very hot summer and the very cold winter where that effective head room collapsed to a very small number. And so, the economics of those migrated versus the price that we achieved by selling through the market became much reduced in terms of a loss for us. And that's something that -- those dynamics would continue to happen, because they are really the realities of the market, as you're doing pricing.

Okay. And I know I'm supposed to be done, but just one tie-on question. When you give your 2012 forward Power sales, the hedge numbers you had, are you assuming kind of a 38% to 40% shopping number in that hedge percentage, when you think about pricing and volumes?

We did forecast -- I won't go into those numbers at this point, but we did forecast a small amount of incremental migration in 2012, just consistent with the deltas that we see.

Okay. Thank you.

Next question?

Your next question comes from Paul Peterson.

It's Paul Patterson. Can you hear me?

Yes, we can, Paul.

Just on the customer migration issue, the 38% to 40% -- that's customers, correct? As opposed to megawatt hours?

No, no, it's megawatt hours.

That's megawatt hours? Now, that's considerably less than what we see in Connecticut. And I know you guys operate in Connecticut. Is it because you see a difference in head room there? And, could you give us just a little bit of a flavor for what head room is in 2011, that you're looking at here versus retail? Just sort of the economics we're looking at?

Relative to head room, we track head room on a month-by-month basis, and you have to work it up, based on looking at what the price is that you would achieve in the market versus the price that you achieved from your BGS. But you have to subtract all those things that are costs, that a retailer would also have to look at.

And so, what I can tell you is we've seen that number be in a mid-double-digit to as low as almost zero, depending on the month-to-month variation of the prices in the marketplace. But you would have to work that up. I mean, everybody, I think, can work that up independently, using the prices in the market, the costs that are associated, the net margin that is actually left to someone who would go into that business, and then compare it to that same calculation, looking at the BGS price.

So, for 2011, you guys are estimating low double digits to -- I'm sorry, low -- is it low double digits, you said, to zero?

Well, we -- so, we're not giving the particular number for migration. But let me see if this helps you think about it. In 2011, -- in 2010, because of the way in which we saw weather, warm summer weather, cold winter weather, earlier in the year, you saw that head room collapse in some periods to a very low number, a number that we don't think would support being in the retail business.

In 2011, what I'm signaling here is, we're not forecasting higher weather. We usually just forecast normal weather. So, we're forecasting the normal amount of head room that you would get if you just worked up from using the current BGS price, and the new one that cleared, that rolls in in June, comparing it to the forward curve, and then -- and working that up. And you could work that up based on normal weather, and come to your own estimates of what that would be.

Okay. When we're looking at the customer migration issue, there is some legislation, I guess, dealing with municipal -- I'm not sure if it's municipal aggregation, or what the actual -- I looked at the legislation, but I was a little confused by it. That was being reported about in New Jersey. Do you see any customer aggregation issues? And also, just in general, like I said, you guys work in Connecticut as well as New Jersey. And I guess, the differences between those markets seem pretty substantial. If you could give us just any flavor for the differences between those two things, and opt-out aggregation, maybe.

So Paul, I'm not familiar with the specifics of the retail markets in Connecticut, to be candid. In New Jersey, there has been an ongoing bit of aggregation that's taken place among schools and municipalities, so that's been an active market for years. The legislation you're referring to relates to multiple systems -- municipal systems, as opposed to anything that customers have not already been empowered to do in New Jersey. So, I don't see it as having a major impact on BGS.

Thanks a lot.

Your next question comes from Leslie Rich.

Hi. You said that CapEx would be $6.7 billion over the 2011 to '13 time frame, and I think that's up about $800 million. I wondered if you could walk through -- not to steal your thunder from the Analyst Day, but walk through, just broadly, where that capital is being allocated.

Sure, Leslie. Good morning. Happy to do that. We did give the numbers, you're right, for 2011 through 2013. And as you know from the disclosures that we've given out before, relative to where most of that capital is going to be spent, it will be at the utility, as we implement the key programs at the utility. And so, as you look out in '11, '12, and '13 -- and you'll see this as the 10-K is filed, what you see for capital spend for PSE&G is approximately $1.5 billion in each of the three years of 2011, '12, and '13.

And you know from the conversations we've had before, that the single biggest piece of that, by far, is what we're doing in transmission. And then, for Power, you see numbers for Power that's basically the delta. There's a small piece, clearly, of non-utility renewables as well. But Power's numbers in '11, '12, and '13 are about $670 [million] in 2011, slightly less than $500 [million] in '12, and about $340 [million] in '13. And then, there's a small piece for non-utility renewables. And these numbers that we just described don't include the numbers that Ralph just mentioned, relative to the opportunity for new filings that we're looking at for -- potentially, for the electric that we just mentioned.

So, when you think about these numbers, we're always looking at those opportunities for more investment on the utility side, subject to getting contemporaneous return. I think the other thing to point out we've talked about before. But just to remind everyone, because we have the back-end technology going into effect, when you look at our total profile here in terms of the amount we're spending in total in excess of $2 billion each of the next three years -- when you look to the environmental and regulatory and Power, you're seeing numbers that are less than $100 million in each of those years, because of so much of that spending already being behind us. Hope that's helpful.

Yes, it does, thank you.

Next question?

Your next question comes from Jack [D'Angelo]. Hi, good morning.

Good morning.

Can you guys provide any color as to what sort of step-up in O&M you expect to see in '11 at Power?

Sure. So, at Power, we see a small step-up in O&M, low single-digit number, based on the fact that we have, obviously, the back-end technology going into effect, some small incremental costs there. But consistent with our theme that we've talked about for a long period of time, O&M control is a critical thing that we focus on in the Company. And so, we'll continue that strong O&M control at the utility, such that we continue to have a very low growth rate in O&M for the Company on a three-year basis.

So we can think of '11 as maybe a little higher than usual step-up, because the items you just spoke about?

No, no, I would say, small step-up for Power, that low single-digit number. We've got some major maintenance on the combined cycle units. That sort of thing happens on a scheduled basis, but you don't build it into the base, because after it occurs you don't have it in the subsequent year. So, you've got a little more cost for Power in this year, because of that. But our overall focus is strong O&M control across the Company on a multi-year horizon, and we're committed to that.

Great. Thank you. Your next question comes from Paul Fremont.

Thank you very much. The -- on the bonus depreciation, you talked about $900 million for total. How much of that is utility, and how much of that is unregulated?

Yes, good question, Paul. I think the way to think about it -- because this is a bit of a moving target, as we finalize and understand all the IRS rules. But, slightly more than half of it is in the utility, and the remainder's at Power. So, there's a significant amount for each of our Companies, a little more in the utility than in Power.

And between that cash, and also the cash that you're getting from the sale of the Texas plants, we should assume that most of that is being reinvested into utility infrastructure projects?

That's right, Paul. I think we have some great uses for the capital, and we think that we're getting a reasonable risk-adjusted return for that. And as long as we have those good ideas, we'll continue to reinvest that capital. If we don't have those good ideas, we won't be shy about returning it to shareholders. But right now, we think there's some good uses for it.

Thank you.

Next question?

Your next question comes from Jonathan Arnold.

Hi, good morning.

Hi, John.

My question's just on the migration topic again. Got from your comments, Caroline, you think head room not being as tight as it was in the fourth quarter, that the impact would have been less. Is that in terms of seeing less customers switch, or your ability to sell the power at better prices, or a combination of those two? And is there embedded within your statement some view of what switching would have been if you hadn't had the weather we had in Q4?

No, I'd say, Jonathan, if the head room -- you know, if the head room had been greater than we saw it in the fourth quarter, because of the higher market prices, based on the cold weather, you would have had a higher impact than our $0.01 per share, right? So, I think there's also a bit of a lead lag effect as well, right? So, you've got head room moving, with how the weather -- or demand changes market prices. And therefore, the net effect to us, that's going to have a feedback effect on how retailers think about being in this market longer term.

Those two things wouldn't happen in exactly the same month. But as the dynamics of head room have suggested, that it really does move quite a bit in our market, as it probably does in every market, it makes for some different choices, presumably, for retailers, about how aggressively to think about this market. But in general, think about it as higher market prices, reduced head room. Reduced head room means lower net impact for us, for every customer that has migrated, in terms of our bottom line.

Less migration, I guess.

No, no, less impact in terms of the dollar impact to our bottom line from that customer having left. Because, keep in mind, if that customer has left BGS, they're still ultimately buying power from a retailer who is, in most cases, not a generator, and has to buy from the market, and we supply the market. So, the question is, what's the price that we achieve when we supply the market? If we supply the market through BGS, it's the BGS price.

If we supply the market through PJM or through other hedges or directly into the market, we're getting the market price. To the extent that pressure, because of weather, pushes that market price up and the BGS price is fixed, the gap between BGS and market shrinks when there's pressure. And therefore, it costs us less to have lost the customer than it would otherwise cost us.

Okay. Thank you.

Sure. Next question?

Your next question comes from Ashar Khan.

Good afternoon, how are you doing?

Good.

Can I just get a little bit of perspective -- I'm trying to figure out the drop in earnings from '10 to '11. And you mentioned, if I'm right, there's some depreciation from the plants, and of course, lower margin. Is there something that you could give us, which would break down those items precisely from the 109.1 to, say, the 805 midpoint, as to the impacts of the items that you kind of pointed out?

So, we don't do that breakdown precisely. But let me just remind you of a couple of the factors that hopefully should help you in the modeling. So, you're right -- on the back-end technology going into service, that's sort of an easy one to specifically identify. Remember, we've talked about the fact that we've spent about $1 billion on the back-end technologies for Hudson and Mercer. That incremental depreciation for Power, on a year-on-year basis, almost all of which relates to BET, is about $45 million. That's a pretax expense hit.

We also just talked about the fact that there's a small -- again, low single-digit impact on O&M on a year-on-year basis, combined cycle, major maintenance -- again, that's something that you should bake in on a year-on-year basis, but it's important for 2011. And then, the two things that I would focus you back on in terms of doing the calculations when you think about margin, is the hedge price that we talked about. So, recall that we said that we are 95% hedged for our coal and nuclear generation, about 40 terawatt hours, at a $68 per megawatt hour price. And that compares to, in 2010, hedges of about 91% at $72 per megawatt hour. So, you've got a $4 per megawatt hour differential on 95% or 91% of 40 terawatt hours. And if you do the math on that, you'll obviously see that that's a significant contributor to the year-on-year.

The other thing to keep in mind with that is, we're 95% hedged now. We were 91% last year. That left us a little bit more open to the market. And as we just talked about, the market had some hot weather and higher prices that enabled us to capture a little bit more from the open position. Now, we don't know what this year's weather will be; but when we forecast, we always forecast for normal weather.

And then, the last piece, just to remind you, as we talked about the capacity price. So, something that occurred a while ago, we haven't talked about -- we don't talk about it as near-term as migration in BGS. But we do have that roll-off of that higher capacity price, the $191 that rolls off in mid-year this year, and is replaced by the $110, which was the clear for mid '11 to mid '12. That's how we get paid for a significant portion of our 10,000 megawatts that don't embed that price in the BGS. Outside of BGS, that's a direct payment that Power's generation receives.

And that downdraft of about $81 per megawatt day, if you calculate that back through the proportion of Power's assets that are entitled to now that lower payment for about 58% of the year, you would have another big piece of the picture. So, I hope that helps just in giving you the pieces. You obviously have to embed your own assumptions for how you think about forward prices, if you think about them at the forward curve or differently, and how you think about weather. But that's how we come up with the guidance that we're providing.

Okay. If I could just follow up, based on previous slides that you have provided in the decks, am I right that coal costs are expected to be like lower in '11 versus '10? Meanwhile, nuclear fuel costs are expected to be higher versus '11 versus '10?

Yes, so nuclear fuel costs have been going up. And you're right, we have talked about that in our prior decks. Relative to coal, a couple of things. So, we do have some of the higher-priced Adaro coal, as you probably recall, that we used at Bridgeport. But in Hudson, because of the completion of the back-end technology, we now no longer have to use Adaro at that location. So, if you think about overall, through our coal fleet, total coal costs are down about $1 per megawatt hour. So, not dramatically different when you do a weighted average and you recognize that Adaro is no longer required for Hudson.

The other thing to keep in mind as we think about coal dispatch within our region is, don't forget that the BET costs, obviously, will get folded into how we think about our dispatch. And that increases the cost for those units, Mercer and Hudson, on a megawatt-hour basis. So, net-net total, slightly up per megawatt hour in total coal dispatch cost, when you think about those economics.

Okay. Thank you so much.

Next question?

Your next question comes from Julien Dumoulin.

Good morning. Thank you. I just wanted to ask more on the capacity market expectations. What are you guys thinking for this upcoming auction -- latest thoughts, in light of the latest revisions? And then, also, with respect to PS North, is that something that you would anticipate potentially clearing separately? And I'll begin there.

Julien, as you know, we don't forecast the results of the auctions -- not for BGS, nor for RPM. I do believe PJM came out with their latest load forecast, which is available on Oasis. It's modestly less robust than prior forecasts, but -- I don't mean to be disrespectful. We just don't like to forecast what those outcomes might look like.

No worries. Any comments would be appreciated. And then, beyond that, as I can tell from your comments, it seems as if you're looking at participating in the New Jersey auction itself, or New Jersey participation, for the new capacity. Is that operating simultaneously with your litigation? How are the various pieces moving there, with regards to your decision to participate on that side?

Yes, the answer to that is, they are operating simultaneously. We don't think that having government-managed supply is the best way to go, and we're making that case both in the courts and at FERC. Having said that, if people disagree with us, we have to make sure the lights stay on, and that we participate in whatever mechanism policymakers choose to provide supply. So, unfortunately, these things cannot happen sequentially. They're all going on at the same time. So, yes, we are participating in the New Jersey process.

Great. Thank you.

Your next question comes from Brian Chin.

Hi. Good morning.

Good morning, Brian.

So, you've raised the transmission CapEx outlook, while at the same time PJM lowered the load forecast a little bit, and then New Jersey did the power plant legislation. If you could give a little more color on how much of the '11 through '13 CapEx is locked in, versus how much is potentially subject to delay -- if you could kind of clarify that, or maybe give some color on that?

So Brian, we -- I don't think we lowered the transmission forecast, if I'm not mistaken. I'll go back and double-check that number. But as you know, our transmission forecast is a direct offshoot of the PJM RTEP process -- the Regional Transmission Expansion Planning. So, that has multiple elements that go into it. One element, of course, as you pointed out, is what's happening to demand. But a second component is what's happening to supply, both additions and retirements. And then, single, double, and subsequent contingency analyses.

So, I won't bore you with the rigorous engineering analysis of why certain 69KV projects are needed, versus 230 versus 500. But we don't make up that transmission capital program -- it's a direct offshoot of PJM's RTEP, which factors in their demand forecast. With regard to any substantial increase in generation that results from the New Jersey process -- well, we'll just have to see where that pans out.

Our position has been, and remains, that the market has not been calling for the need for 2,000 additional megawatts, and that this will be subsidized oversupply circumstance if it does go through to completion. And I think that PJM is being consistent in its view of the world. They have filed at FERC something similar to the P3 group filing, which really says that a lower-cost way to make sure that reliability preserved right now, is through RPM and the RTEP, and that would best meet the needs of customers in the near and long term.

Okay, great. And then, one extra question. On that court challenge versus the New Jersey legislation, can you just give us a sense of time line, and what sort of things to expect over, say, the next six months or so?

So, I think from the point of view of the court challenge, that is very difficult to do. I would like to have you join me when I talk to our attorneys in-house, to force them to give us just that answer. But of course, no one is willing to predict court schedules or court outcomes. But we do believe that in the other venue -- namely, at FERC, which is obviously a regulatory discussion -- there, the timetables are a bit more predictable. And we're believing a mid-April timetable for FERC to respond to our pleading and the PJM pleading.

Okay, great. If that was an offer for me to join you with your attorneys, I'll take it. Just give me a call any time, Ralph. Thank you.

Thanks, Brian. But Brian, I think from the FERC perspective, what's really important is, it will be prior to the RPM auction in May.

Right. Thank you.

Your next question -- your next question comes from Michael Lapides.

Hi, guys. Questions on the regulated side -- two pieces. One, what's the latest, just in terms of the siting and permitting side for Susquehanna-Roseland? That's question one. And question two, what are your thoughts about when you're going to file another distribution rate case?

Oh, Michael -- so, Susquehanna-Roseland remains with the critical path item of the National Park Service, and I don't believe we have anything new to report in that regard. So, it's looking like a decision from them late in 2012, with in-service dates of the eastern part in 2014 middle of the year, and the western part in 2015, middle of the year. And then, a distribution base rate case, not as far as the eye can see. So, we would like to control costs and manage our CapEx in a way that we avoid having to seek rate relief.

Got it. And is there a kind of a rule of thumb of -- you mentioned you're just under 10% earned ROE. Is there a rule of thumb, though, kind of what's your typical trigger point -- meaning, when you reach below a certain level of earned ROE, where you say okay, now it's time?

No, there is no -- there is no magic number or bright line. Remember, that 9.7% was because we had rate relief for half the year. So, we would expect, with our cost control, to do modestly better than that this year. And also, we are making sure that any capital expansion programs that we have -- and we've talked about several of them, both in transmission and distribution, have clause-like treatment that avoided the regulatory lag that can be so harmful to our shareholders. So, I think we're -- just let me repeat, as far as the eye can see, we're not anticipating a base rate case proceeding.

Got you. Thank you. Much appreciated.

Operator, I'm just going to turn the call over to Ralph Izzo at this point, if I may. Thank you.

So, let me express my thanks to all of you for joining us today, and your many questions. And allow me to remind you that on March 7, we will have our investor conference in New York City. If you need the specifics of that, Kathleen and Carlotta will be happy to make that known to you. And, we hope to see you there. If there are additional questions that arise between now and then, we'll have plenty of time to spend with you to go over that. And again, thank you for being with us today, and hope to see you on March 7. Take care, everyone.

This concludes today's conference call. You may now disconnect.