公共服務電力與天然氣 (PEG) 2012 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. My name is Keisha and I will be your event operator today. I would like to welcome everyone to today's conference, Public Service Enterprise Group's second-quarter 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 reminder, this conference is being recorded today, July 31, 2012, and will be available for telephone replay beginning at 12 PM Eastern today until 11.30 PM Eastern on August 14, 2012. It will also be available as an audio webcast on PEG's corporate website at www.pseg.com.

I would now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Keisha. Good morning, everyone -- or, good afternoon. We appreciate you participating in our call this morning. As you are aware, we released second-quarter 2012 earnings earlier today. You can find the release and attachments posted on our website, at www.pseg.com, under the Investor section of the website. We have also posted a series of slides that detail operating results by company for the quarter. Our 10-Q for the period ended June 30, 2012, is expected to be filed shortly, before the end of this week.

I'm not going to read the full disclaimer statement or the comments we have on the difference between operating earnings and GAAP results. But as you know, the earnings release and other matters that we will discuss on today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although we may elect to update these forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if our estimate changes, unless we are required to do so.

Our release also contains adjusted non-GAAP operating earnings. Please refer to today's 8-K or other filings for a discussion of factors that may cause results to differ from management's projections, forecasts, and expectations; and for a reconciliation of operating earnings to GAAP results.

I am now going to turn the call over to Caroline Dorsa, Executive Vice President and Chief Financial Officer. At the conclusion of Caroline's remarks, there will be time for your questions. We ask that you limit yourself to one question and one follow-up question. If you do have follow-ups beyond that, we hope to get to you later in the queue. Thank you. Caroline?

Thank you, Kathleen, and thank you, everyone, for joining us today. I'll say we appreciate your patience with us as we adjusted the timing of the earnings conference call. This change provided flexibility for Ralph to join Governor Christie at a press conference this morning to break ground on the renewable energy site in Hackensack, New Jersey. I hope you've also seen the announcement of PSE&G's proposed plans to increase spending on solar energy by up to $883 million. Our proposed investment, if approved as filed, will add 233 megawatts of renewable energy to the grid over the next five years. And when added to our existing $700 million commitment to solar energy, PSE&G will have added approximately 395 megawatts of solar capacity to the system, and will move closer to meeting the state's goals for renewable energy. The program will assure the continuation of PSE&G's successful organic growth strategy in this area. And, as we will discuss later, our balance sheet enables us to consider additional investments to grow the utility in other ways that benefit our customers.

Before we talk more about our proposed spending program, let me address earnings for the quarter. Earlier this morning, we reported operating earnings for the second quarter of 2012 of $0.43 per share, compared with operating earnings of $0.59 per share in the second quarter of 2011. The results for the quarter bring operating earnings for the first half of 2012 to $1.28 per share compared with operating earnings of $1.44 per share earned in 2011's first half. Slides 4 and 5 of our webcast package contain the detail on the results for the quarter and the first half.

Our results for the quarter and the first half of the year are in line with our expectations; and, I think you will find, showed that our strategy is on track. You could say that the results are strong in the face of issues which we don't control, such as the weather. This year started off as one of the warmest on record. And the mild weather conditions continue to define our experience for the second quarter, although our weather normalization clause in our gas business enabled us to learn our authorized return.

Credit for meeting our operational and financial objectives goes to our employees. Their dedication is evident in the continued availability for our gas-fired combined cycle fleet and the strong performance from nuclear, which together support Power's market position. The importance of setting and meeting high standards for reliability is also recognized by our utility customers, as PSE&G moved to second place on the J.D. Power and Associates 2012 Electric Utility Residential Customer Satisfaction survey for large utilities in the East, from 10th place a year ago.

Let me now address the earnings for each company in a bit more detail. The earnings contribution from each of our two major businesses is almost equal in both periods. We have provided you with the waterfall chart on slide 10 that takes you through the net changes in quarter-over-quarter operating earnings by major business. And a similar chart on slide 12 provides you with the changes in operating earnings by each business, on a year-to-date basis.

Let's start with Power. PSEG Power reported operating earnings of $0.22 per share for the second quarter of 2012, compared with operating earnings of $0.36 per share for the second quarter of 2011. PSEG Power's earnings declined, in line with our expectations, given lower prices for energy and capacity during the quarter. Operations were aided by the availability and increased dispatch of the combined cycle natural gas fleet; continued strong contribution from the nuclear fleet (technical difficulty). Lower realized price increases reduced Power's earnings by $0.05 per share, quarter over quarter. The decline reflects lower prices under the BGS contracts, as well as lower wholesale prices. The contract price for one-third of the BGS-related load declined from $104 per megawatt hour to approximately $84 per megawatt hour on June 1 of 2012.

The impact on earnings from the overall decline in price incorporates the impact of customer migration away from the BGS contract. For your information, customer migration levels were at about 38% during the quarter, in line with our expectations, and consistent with our full-year guidance. The market price for power in the quarter was often set by low gas prices in the East -- where power units are located -- as opposed to coal in the West. Basis, however, has improved from first-quarter levels. The return to service of the transmission lines and co-units in western PJM, which had experienced outages in the first quarter; as well as an increase in the price of gas versus coal, had a favorable impact on basis, which remains positive as we look into the forward market.

A decline in average capacity prices reduced earnings in the quarter by $0.03 per share. Although, quarter over quarter, we saw a decline in earnings from capacity, recall that the weighted average price for capacity on our fleet increased from $152.60 per megawatt day on June 1 of this year from $110 per megawatt day earlier this year. This increase in capacity prices will be in place through May 31 of next year. Thus, revenue from capacity on a full-year basis is expected to be essentially flat versus 2011. You may want to keep that in mind as you model the rest of the year.

Power cleared approximately 9000 megawatts of capacity at a price of $167 per megawatt day for the 2015-2016 years, as part of the RPM auction conducted by PJM. Several new combined cycle units, to be built by other generators, cleared the auction at that price. Efforts to improve the minimum offer price rule, prior to the next auction, are ongoing.

The output from Power's fleet declined 4.6% in the quarter from year-ago levels. This reduction in output was primarily influenced by a decline in the dispatch of our coal units. The decline in output reduced earnings by about $0.02 per share.

The nuclear fleet experienced a 3% decline in output during the quarter from year-ago levels. A planned refueling outage at the Hope Creek nuclear station is [born] completely by power, given 100% ownership of the unit, compared to the impact in the year-ago quarter of the refueling outage at the 57%-owned Salem 2 unit. The nuclear fleet operated at an average capacity figure of 92.7% during the first half of the year, and is consistent with our expectations for the fleet to operate at approximately 91% to 92% of capacity for the full-year 2012.

Production from the natural gas combined cycle fleet increased approximately 10% in the quarter, and now represented 32% of generation. Output was aided by continued strong availability of 88%, as the fleet's capacity factor in expanded from 52% to 57% in the quarter. Power's 270 megawatts of new, efficient, peaking capacity at Carney went into service on June 1 and was picked up by PJM on day one to assure reliability. And they have been available to meet the summer demand. An additional 130 megawatts of new peaking capacity at New Haven, Connecticut was also brought into service by Power to be ready for the summer season.

And the market experienced an improvement in gas prices toward the end of the quarter, in response to demand. During the quarter, however, our dual-fueled Hudson and Mercer units continued to be dispatched primarily on gas when called upon to run. An increase in the price of gas in early July narrowed the cost discrepancy between operating our coal and natural gas units. In fact, Hudson and Mercer have been running on coal in July, given weather-related demand and higher gas prices.

In general, gas prices would need to improve further, by another approximately $1.50 to $2 per MMBtu, for coal to be competitive with the dispatch economics of our combined cycle units. A net increase in O&M costs, associated with the planned refueling outage at Hope Creek, reduced Power's earnings in the quarter by $0.02 per share. Power continues to carefully monitor its operating expenses, and benefits from its ability to optimize its labor force in reaction to market conditions.

For the full year, Power still expects to capture most of the value of the O&M savings it realized during the first quarter, predominantly at the fossil stations. And year to date, O&M is still lower than last year's levels. Several miscellaneous items combined to reduce Power's earnings in the quarter by $0.03 per share.

Power continues to forecast total output for 2012 of 53 to 54 TWh. And approximately 70% to 75% of output for the remainder of the year is hedged at an average price of $58 per megawatt hour. For 2013, Power has hedged approximately 55% to 60% of its forecast output of 52 to 54 TWh, at an average price of $54 per megawatt hour. And for 2014, Power has hedged approximately 25% to 30% of its forecast output of 53 to 55 TWh, at an average price of $54 per megawatt hour. Remember that average hedge prices exclude the price for capacity embedded in our full requirements contracts.

We continue to forecast operating earnings in 2012 for Power of $575 million to $665 million. The year will be influenced by a decline in average realized energy prices. Full-year capacity revenues, however, are expected to be generally flat with 2011, given the increase in capacity prices on June 1 of this year. Power's results will also be aided by its control of O&M and strong performance from the nuclear and combined cycle assets. Let me also remind you that Power continues to have solid investment grade credit ratings from all the agencies, and ended the quarter with a debt to capital ratio of 34%.

Let me now turn to the Utility. PSE&G reported operating earnings for the second quarter of 2012 of $0.20 per share, compared with $0.21 per share for the second quarter of 2011. And results for the quarter are shown on slide 23. PSE&G's results were influenced by an increase in transmission revenue and warmer-than-normal winter weather. An annualized increase in transmission revenue of $94 million, effective on January 1 of this year, added $0.02 per share to earnings. Warmer-than-normal winter weather conditions early in the quarter, and weather which was unfavorable compared to a year ago, reduced electric demand and earnings by $0.01 per share.

On a weather-normalized basis, residential sales increased about 1.8% in the quarter, as extreme weather fluctuations may have encouraged the use of air conditioning. A small decline in weather-normalized electric sales from commercial and industrial customers together resulted in only a nominal overall increase in total weather-normalized electric sales.

Although decline in demand for gas reduced earnings quarter over quarter by $0.01 per share, this was fully offset by an accrual of revenues under the gas weather normalization clause, which continues to support PSE&G's ability to earn its authorized return in our gas distribution business. An increase in PSE&G's O&M reduced earnings in the quarter by $0.03 per share. This increase, which was in line with our expectations, reflects higher pension expense -- which we've talked about this year -- and the work associated with the Company's expanded capital program. An increase in depreciation expenses, also associated with the expanded capital program, reduced earnings by $0.01 per share. And other miscellaneous items added $0.02 per share to the quarter-over-quarter earnings comparisons.

During the quarter, PSE&G obtained important milestones related to the $390 million North Central Reliability transmission line. We received approval from both the New Jersey Board of Public Utilities and the New Jersey Department of Environmental Protection for construction of the 230-Kv line. The line is scheduled to enter service in mid-2014. And construction has started. The north-central line is one of several major transmission projects comprising PSE&G's $3.5 billion investment in new transmission capacity over 2012 to 2014, a pillar of the Utility's organic growth strategy.

As I mentioned earlier, PSE&G announced today that it will be filing shortly for New Jersey BPU approval to increase spending by up to $883 million under its existing Solar 4 All and Solar Loan programs. This continues our investment program in renewable, which is the second key part of the Utility's organic growth strategy, and provides our customers with increased levels of clean energy. Governor Christie recently signed into law the Solar Energy Bill, requiring electric power suppliers to increase renewable energy as a percent of total energy requirements.

Our proposal calls for spending up to $690 million under the Solar 4 All program over a five-year period, to add solar capacity on landfills and brownfield sites. The plan also calls for spending up to $193 million over a three-year period under the Solar Loan program to support the financing of solar by businesses and homeowners. The two spending programs will support the addition of 233 megawatts of solar capacity, and bring PSE&G's total investment in solar to approximately 395 megawatts.

The filing is based on an extension of the supported incremental rate mechanisms of our existing programs, namely an authorized return on equity of 10.3%, and annual review by the BPU. We continue to have investment capacity to support additional significant investments by PSE&G in the areas of energy efficiency, and the replacement of aging infrastructure, including cast-iron gas distribution maintenance. Both of these, along with our proposed solar investments and transmission, can help grow our Utility by providing significant benefits to our customers. PSE&G's growth is benefiting from increased investment in transmission, and an investment program emphasizing a clean, efficient and reliable network.

Year to date, both are transmission business and our renewables business are positive contributors to our bottom line, after all costs. And in our distribution businesses, we continue to earn our authorized return in both electric and gas. PSE&G's results for the first half of the year are consistent with our forecast operating earnings guidance for the full year of $530 million to $560 million.

I will now turn to PSEG Energy Holdings and the parent. Operating earnings for PSEG Energy Holdings and Enterprise in the second quarter of 2012 were $4 million, or about $0.01 per share, versus operating earnings of $10 million or $0.02 per share earned during the second quarter of 2011. The results were in line with our expectations and reflect expected lower earnings on leases. PSEG Energy Holdings remains focused on the startup of its $75 million investment in the 25-megawatt Queen Creek solar plant in Arizona, scheduled for operation later this year; as well as transition activities in support of the Long Island Power Authority services contract. The 10-year contract to manage LIPA's electric distribution system received final approval during the quarter. The contract, which is scheduled to begin in January of 2014, represents an opportunity to improve returns, and is a recognition of PSEG's history of strong reliability and customer satisfaction.

PSEG Energy Holdings and Enterprise operating earnings for the second quarter are consistent with our forecast of operating earnings for 2012 of $35 million to $45 million. The results for the full year include the benefit associated with the IRS tax settlement in the first quarter and the expected decline of lease income. And we plan to continue our successful efforts to date to de-risk the holdings business.

Finally, our capital position remains strong. We ended the quarter with over $750 million in cash, and total debt at 41% of capitalization. During the quarter, PSE&G sold $450 million of 30-year medium-term notes at a cost of 3.95% to finance its capital program, in line with authorized rate loans. Power continues to generate significant operating cash flow, given its low-cost position, while its capital needs remain modest. As we remain focused on maintaining solid credit metrics, the strength of our balance sheet and cash flow supports the proposed increase in capital spending, with room for possible new programs in PSE&G without the need for additional equity.

Finally, we remain, with our operating earnings guidance, in line with our expectations for the full year of $2.25 to $2.50 per share.

With that, I'll turn it back to Keisha, and we welcome any questions you might have.

(Operator instructions) Dan Eggers, Credit Suisse.

Caroline, with the RPM option having taken place since the last earnings call, can you share the corporate strategy around addressing the MOPR ruling? And any thoughts you guys might have around the LCAPP lawsuit that's, I guess, in court today; and what strategies might occur if you do not get a successful outcome in that case?

Sure. Thanks, Dan. Relative to capacity -- as you know, as we mentioned, there are efforts underway with PGM, as I mentioned, to improve the understanding and transparency relative to MOPR prior to next year's auction. It's really too soon to comment on that, because those discussions are just underway, and that is a confidential process. So I can't really talk more about that except that we recognize the value in trying to improve that transparency.

Relative to the court case -- obviously, today, court is in session. And I think the perspective I would share with you on the court case is similar to what we have been talking about all along. We do think that it makes sense to preserve the viability of markets. And that has always been our position, relative to the court action. We did file a motion for summary judgment. And, as you know, the other side did the same. Oral arguments are, as I best understand it before I got on this call, still underway. And we look forward to that outcome.

It's too soon to speculate, of course, on what might happen if there is outcome on either side at this point. We remain committed, of course, to the concept of supporting markets. But it's really too soon to have any speculation on what's going on in court. Our position is really the same as it has been before.

Paul Patterson. And, sir, please state your company name.

Glenrock Associates. Just in terms of -- I just wanted to clarify the sales growth. It sounded like, I guess, it's kind of neutral. There wasn't really much of a change; maybe a slight positive -- is that right? On a weather-normalized basis, for the quarter and year to date?

Yes, that's right, Paul. When we look at overall between residential, commercial and industrial, it's a very modest, less than 1% growth. We continue to talk about low growth in that 0.5% to 1% range, over the period. It was pretty modest in this quarter.

And then in terms of peaks, looking at PGM and what have you, we've had really hot weather, as you know, most recently. And I haven't seen any announcement of new peaks, really, in PJM. I was wondering if you guys -- have your market people or whatever -- are seeing any change in demand response. I know we've got new energy demand response tariffs in PJM. Just in general, if you could give us a flavor for any change in consumption pattern that you might be seeing. Considering that that we have really hot weather, and I don't think we see much in the way of any new peaks.

Yes, that's a good question, Paul. You're right. So, we have had pretty hot weather, as you know, as you were just commenting. We have not hit the historical peaks that we have seen previously; you're right. It's too early to know, specifically, what that relates to. Obviously, demand response could be a factor. And that's a little hard to measure at this point in time. Or whether part of what we're seeing in response to warm weather is some curtailment of demand that comes from people just conserving because of their economic situation or whatever. So you're right; we haven't hit the peaks. It's just a little early for us to assess whether it was specifically demand response programs versus just the overall economic conditions. But you're right about the fact we haven't hit our peaks to date.

Travis Miller, Morningstar.

I was hoping you could quantify a bit the earnings benefit that you are seeing from the increase in combined cycle generation. You talked about it a lot. Is there an earnings offset that you are realizing? And could that change as gas prices move?

So, Travis, I guess I think of it this way -- so, combined cycle generation is up 10%, right, as we mentioned; just about 10%. Of course, coal generation is down, as I mentioned before. And, of course, this particular quarter, we have the Hope Creek outage. So, while we certainly are pleased and benefit from the efficiency of our combined cycle, there are obviously offsets that go there as well.

As it relates to, if you think about our overall position, our combined cycle units, part of what we offer into the market. But also keep in mind that BGS provides a significant portion of our pricing and our hedging, in terms of providing the overall prices. So it's good to have the combined cycle availability. We are very pleased. We have the largest combined cycle fleet in PJM. The capacity factor was 57% in the quarter.

But obviously, when you look at it all together, we balance it out relative to coal. And of course, nuclear continues to be highly available as well. So I wouldn't try to split out profitability by the type of unit. I'd rather look at the fact that we have a whole dispatch portfolio, which we can effectively put into the market to optimize our total profitability; and a reasonable hedging strategy which, I think, gives us the opportunity to take advantage of some of those fill requirement contract prices.

Kit Konolige, [EFC Financial].

So, on the segment earnings, Carolyn -- as you noted, they are running about the neck-and-neck between the utility and power, year to date. You, I believe, were maintaining the guidance for the year, which would result in Power ending the year a little above PSE&G. Can you give us a perspective on the rest of the year, segment-wise? And then maybe looking forward over the next couple of years? That was a perspective that I think you gave us at the analyst day.

Sure, Kit. So, a couple of things -- so you are right, we are very close on a six-month basis between Power and PSE&G, $0.60 per share for Power and $0.59 for PSE&G. And then, of course, if you look at our guidance, obviously which we reaffirmed for both businesses, I think as we think about the period coming up -- of course, we are into the summer quarter now. So that's important, relative to thinking about the summer and the demand that we see, which obviously has benefits for both businesses.

The other thing I encourage you to keep in mind, as you look at year to date being relatively similar; and then compare it to guidance, which is not right on top of each other -- as I mentioned, capacity prices. Keep in mind, capacity prices are now up for the second half of the year. Which means that, as I've mentioned, they would be essentially flat if we looked at the full year in terms of capacity revenues. And when you think about that, I think that's valuable to keep in mind. Because, if we think about capacity prices on a year-to-date basis, they are $0.11 lower. But what we were signaling was for the full year, they'll basically be flat. That's going to be a differentiator for Power as you think about the go-forward.

That's probably the single-biggest thing I would point to, on the margin line for Power, that's a differentiator that's not just the weather and the summer.

For the Utility, I'd point to, obviously, continuing our transmission investments. Obviously, the announcement that we made on solar today would not be a 2012 earnings effect; that would be a filing that would be affecting future periods. So just keep in mind utility transmission. And, as we come into the later period, as we get into the fall and to the winter -- obviously, the winter weather would have an impact. Although, keep mind, for the Utility the winter has the gas weather normalization clause, which allows us to earn our authorized returns. Of course, for Power, it would be more at market.

So I think about capacity and summer weather and continued transmission investments as the differentiators, as we think about the rest of the year. In terms of the outlook for the longer-term, as you know, we are not giving guidance beyond the current year, 2012. I would say just keep in mind some of the hedging data, which I gave you earlier, for Power. Power is relatively well-hedged as we come into 2013, and less so for 2014, consistent with what we've done in the past. We are a little more hedged, at this point in the year, for the subs for the upcoming year than we were last year at this time. So we've done a little more of that hedging. But we still have, obviously, more to go in both quarters, relatively consistent with prior.

And for the UTILITY, going forward I would just keep in mind the ongoing investment program that we have, $3.5 billion of transmission spending over the three-year period being an important part of our growth. And then those new filings that I just mentioned, which are new. And keep in mind, if you are modeling them into the out-years, they are not part of the previous disclosures we've given you on our capital expenditures. Because we've only put in those slides things that have been approved. So this is new and incremental, things that you should think about for the Utility in the upcoming years.

Great, thank you. And one other area, just to clarify -- I think you mentioned that gas prices would need to be $1.50 to $2 higher for coal to be competitive. So we're talking about gas prices would have to get above $5 before the coal plants run some more, basically?

So, gas prices about $5 is about right, Kit. So you are right on. Relative to the coal units running, it's not about their running when there's the strong demand that we would see in the summer. It's about that would be the trade-off price where they would become equivalent in the dispatch with the gas units, the combined cycle units. It's not about the fact that coal can't run the summer. Because, as I said, we are already running them this July because the warm weather has pulled the demand through. I'm really talking about the equivalents to combined cycle. But your number is right.

And obviously the flatness, shall we say, in peak -- i.e., absence of a whole lot of growth in demand, would tend to not change that dispatch order very quickly?

Yes, I think it's fair. But I would say, even though we have not hit the peaks -- as we were just talking about a few minutes ago -- we are having enough demand in the warm summer days that the coal units are running, and running on coal.

Stephen Byrd, Morgan Stanley.

We have an upcoming court decision on the cross state rule from EPA. And there has been a lot of debate about how that may come out. If the court were to uphold that rule, what is your general view on power market implications and implications to PSEG in that event?

So good question, Stephen. Right now, a lot of what we're seeing in the markets is more focused, really, on the MATC rules than the CSAPR rules in terms of having that significant impact. And you may remember, obviously, it was a hiccup in the market in CSAPR late last year. So we're hopeful, relative to CSAPR. We still think it's the right way to go. But if you look at where people are making decisions and announcements, and where things tend to be trending, it tends to be more focused on the Mercury rules, at least as we see the markets at this time.

Okay, understood. And I just wanted to build on Kit's earlier question on coal plants and capacity factors. Relative to last year, the New Jersey coal, Hudson and Mercer, I guess the second quarter of 2011 capacity factor was around 33%. And this year, it's at 14%. Are these plants, given the commodity environment that we are now looking at -- are these plants that are likely to be MPV-positive over the long-term in terms of having them continue to run? Or, similar to what we've seen with other companies, where they've looked at coal plants that are less competitive than others, that these are potential candidates for shutdown over time?

So, good question. Relative to our coal plants, we see them as providing value over the long term. As I just said, they are running now. And remember, these plants -- now I'm talking about Hudson and Mercer -- these are dual fuel plants. So they have, actually, some embedded optionality that not every coal plant in the system has. So we have the ability to run them on gas; which is where, when they ran, that's most of how they ran in the second quarter. In July, they are running on coal.

So we do see these units as valuable over the long-term, and as units that we like having in our fleet dispatch. And, frankly, as you've seen over the years, as you know well, having that dispatch flexibility has always turned out to be, over the long-term, an advantage. So we do see them as long-term valuable assets. And we are pleased to see them, frankly, running on coal as we come into the summer.

Michael Lapides, Goldman Sachs.

Hi, Caroline. Can you address the timeline for both the filing on the solar plant that has been proposed today, as well as the timeline on during the course of that five years, what the spending profile would look like?

Sure, Michael. Thanks for your question. So, relative to the timeline for the program, as we've said before, we didn't expect, even considering these filings, that there would be any incremental spend in 2012. And I still think that's accurate. So we'll be filing shortly, so you can watch for that. Obviously, that's following today's announcement and press conference with Governor Christie and with Ralph.

In terms of approval period, I would encourage you to think about these as early 2013, in terms of when the spending would start. As I think we mentioned in the call -- and I know it was in the release -- there are a little bit different timelines for the total spend. So Solar 4 All, Solar 4 All two, is a program that we think we would expect to spend a dollars over the next five years; and for the Solar Loan Program, about three years, in terms of when the loans would go out. And, obviously, they may pay back over a longer period of time.

I think that's relatively consistent with what you've seen with our existing programs. Because, if you think about our existing programs, they've taken some years to roll out. When we had Solar 4 All in July of 2009, the spending is total expected about $456 million. We still have about $95 million to go, so that's sort of consistent with a three- or four-year program. And in the Solar Loan Program, we actually had two programs, as you may recall -- again, they take a multi-year period. So I think three years to five years is the right way to think about it; a little shorter for the loan program, a little longer for the Solar 4 All 2 program. Both of them are filed, generally, consistent with our existing programs, i.e., contemporaneous returns, 10-3, very similar to what you have seen before. That's why we are very pleased to file them. Because, I think, our first programs -- we were judged to be pretty successful.

And do you see this potential uptick in capital spending as requiring incremental capital infusions into PSE&G? Do you still see those coming primarily from PSEG Power? And, finally, there had been some discussion about a gas distribution, kind of an Ohio-like distribution upgrade program. Can you give us an update on where that stands?

Sure, Michael. So, two things -- first, relative to the financing, right, for the PSE&G programs -- so I think you may recall, we've talked about before that because Power's capital needs are relatively modest, right, as we've talked about the environmental spending essentially behind Power. That enables us to have PSE&G, which is now a relatively significant generator of operating cash flow -- not as much as Power, but more significant than it has been in the past -- that allows PSE&G to essentially keep its cash from operations; raise its debt, consistent with its capital structure; while Power can be the cash flow generator that dividends up to the parent to support the shareholder dividend.

So, given the nice cash generation coming from PSE&G, keep in mind things like the renewables with contemporaneous return, and the transmission programs with formula rates and consistent rate base for some of our major programs, start to generate cash relatively quickly. That supports our ability to have the Utility be able to keep its cash and have adequate financing. So everything we are doing -- the bottom line, as we've said before -- there's no need for equity issuance, because the balance sheet and cash flow generation of the two companies is strong.

From the perspective of incremental programs, you are right. We have mentioned that gas disk program a number of times before. And we still have the opportunity for the gas disk program as well as some energy efficiency. We have not announced any filings of those programs. But cast-iron gas main replacement is something that we are obviously interested in. And we understand the state is, as well. It's something that you could see be a program in the future. That's why we continue to put it in our materials. And remember, we've talked about that program as multi-year as well, like a five-year program like a Solar 4 All could be, with spending in the range of about $250 million per year, that we could logistically do well.

That is kind of thing that our balance sheet still provides room to do, even on top of the $883 million that I just mentioned, because of the strength of the credit metrics that I mentioned earlier, with Power's debt-to-cap in the low 30s, and the overall company in the low 40s. Again, without any equity, we can do the programs we've just mentioned. We can do the $3.5 billion transmission that we know we have in front of us, as well as consider more programs. So we kind of like the position we are relative to the ability to do more for the utility.

Paul Fremont, Jefferies & Company.

First question, I guess, is a clarification. Did I hear you earlier say that the weather-normalized sales growth in the quarter was up 1.8%?

So let me clarify that, Paul, for you. So whether-normalized sales growth and residential was 1.8%, but for commercial and industrial it was down. Such that when you roll the utility together for its electric sales, it was up less than 0.5%, which is why we said, essentially, de minimis growth this quarter.

So less than 0.5% for the total, company-wide?

That's right, for electric weather-normalized for the quarter.

Is it fair to say that the impact of shopping was roughly the same this quarter as it was a year ago?

So the impact of price overall for power, as we said, was $0.05. And the impact within that for migration was about $0.03 of the $0.05. In terms of where migration is right now, as I think I mention of the remarks, it's about 38% for the quarter. Recall our guidance for the year is between 36% and 40%. And we're staying with the guidance; we still think that's appropriate. And the reason I'll indicate that for you is one of the things we look at, as you know, when we look at migration -- we always look at headroom.

So, because at the end of the day the driver of migration over the long-term is always headroom. And every time we've seen headroom collapse or shrink, you've seen the pace of migration slow. So, while we had increased headroom earlier this year, when I look at the headroom based on our estimates -- when I look at the headroom for June, for example, as we got a little bit firmer prices with weather, and as the new BGS price came in and reduced the BGS price going forward, right, starting in June, we see headroom levels coming back to levels that we saw, actually, in the third quarter of last year. And that's when you really saw migration slow down.

So the impact is embedded in the $0.05. The PGS price is down. Market price is, obviously, up a little with the weather. We are still comfortable with the guidance range. And we always watch that headroom on a month-to-month basis.

And you brought up the basis differential earlier, and talked about seeing some improvement in the second quarter. Can you give us a sense of where you expect to see basis for the full-year 2012?

Sure. So yes, basis obviously has some challenges, as I mentioned earlier, particularly given some transmission outages and some coal plant outages -- not our coal plants, obviously, coal plants in the West. And they had the impact of reducing the differential; and, in some cases, changing the flow direction of various points in time.

With those being resolved -- as where we are now, as well as with the warmer weather a little firming of gas prices -- we see the return of basis. And in the forward market forecast, as we see basis, we see positive basis for our region. It's not at the level it was years and years ago; we are still talking in the single-digit, modest single-digital levels. But keep in mind, of course, we do monetize basis through BGS. And that's obviously something that continues to remain important.

So it was challenged earlier. It appears to return (technical difficulty) We see it in the forward markets at levels that are positive for us, but not at levels that we had experienced a few years ago.

So is it safe to say, a couple dollars is what you would expect for this year?

Yes, a couple dollars is about right. $2, $3, $4, for the year, is about the way to think about it.

Andy Levy, Avon Capital.

I'm sorry, I'm all set. Thank you very much.

Andrew Gay with UBS.

Hi, good morning, it's Julian here. Actually, most of my questions have been asked and answered already, as well. Perhaps I'm just curious with regard to outside of the court case right now with regards to MOPR, broadly speaking FERC policy. Where you guys looking to do in terms of revising MOPR? What would be the goal there? Obviously, a number of different things have been thrown out there by various companies. What would, ideally, a MOPR look like to you guys?

Well, I think, given the process that's underway at PJM, as I mentioned, it's a confidential process. It's probably not appropriate for us to use the call to speculate on what we would like to see. I think, though, some core principles, things that we've talked about before, are logical to mention. And, of course, one that's transparent for all players, right, for all participants in the market that people can understand readily; and, therefore, it really helps the efficiency of what we think is very valuable and well-functioning capacity market, which we want to see continue.

In terms of specifics, in looking at alternatives and things like that, I think it's just too soon to start to talk about that in public. And we really should let the PJM process, I think, take its course.

Do you have any sense on the timeline for that?

No, I don't have any sense relative to any key dates. One of the things that obviously is something that I think PJM recognizes, as we've all discussed, is to provide some clarity for all market participants before the next auction in May. I think that's the right way to think about the timeline we would shoot for.

Steve Fleishman, Bank of America.

First, clarification on the new solar program -- thank you for giving the rough years for both Solar 4 and Solar Loan. What would be the split, roughly, of the $883 million between the two?

Sure. So for the Solar 4 All 2 program, this new Solar 4 All 2 program, up to $690 million extending out over a five-year period. And for the Solar Loan 3 program, up to $193 million over about a three-year timeframe. I mentioned the up-tos just to provide some clarification on what that means. So this is how we will file. And, of course, we will discuss with the BPU the final dollars. Keep in mind that, also, we're talking about a particular amount of megawatts. And so, depending on how the filing proceeds and is ultimately adjudicated -- as you may recall in Solar 4 All 1, on the current program, we had an approval for 80 megawatts and up to a certain amount of spend. And so, as the price of panels has come down, the total spend came down as well.

So that's why we cite up-to at this point, really because we need to understand and go through the BPU process. But that's how the two split out. And so overall, it's up to the $883 million.

Okay, and what's -- I know you've talked about programs like this as being a focus. Should we expect that there will be more things like this that pop up over the next year or so?

So, the way I would think about it, Steve, in terms of the more -- these are obviously two pretty significant programs in solar, following our existing solar programs. In terms of what's next for the Utility, I would encourage you to think about what we've talked about in terms of energy efficiency and gas disk. And probably, gas disk really being the biggest one; because that's one where, obviously, in the state's energy master plan they talked about gas investment. There's a lot we can do. As I said, we could spend about $250 million a year over a multi-year horizon. That's a per-year amount, on top of the things that we've -- are in the process of filing these solar programs.

So that's really where we would turn to next, is these two programs, if approved, would give us a nice incremental renewables investment in solar. And I think gas disk would be the next place that we will turn our attention, and look forward to potentially some investments there as well. Again, our balance sheet and our capacity for investment really gives us the opportunity to do these in ways that are good for customers and that are shareholder friendly, because there's no need to issue equity by the Company for any of our undertakings.

And then one other question, just on the -- you mentioned the RPM megawatts that cleared in the latest auction. And then you talk about the optionality of the HEDD sites being preserved. Could you maybe give a little more color on what you mean by that?

Sure. So, we had about 9000 megawatts clear, as I mentioned, at the $167 per megawatt per day price. We had announced previously plans to retire some of megawatts that we had notified, right, the 283 megawatts of ICAP. And then we had the peakers that came online that I just mentioned that have already been called, as I mentioned as well.

We also had a big some of our capacity that did not clear, as you can tell from the total. But remember, some of that capacity is capacity that gives us flexibility to rebid in future of auctions for the period; which you know, if you bid in the current auction, if you don't clear but you the reserve the optionality to bid in later auctions. In addition, we are looking at whether some of these HEDD units would still be valuable to that region for their ancillary capabilities, like BlackStar. So all of those things are things that we're looking at right now, relative to those units.

Okay, so there's no new update on the official, quote, retirement, so to speak?

No, that's right, no new update on official retirements. We announced already the ones that we said we would retire. But because of where we are right now, we have optionality on these units for the future; but no updates at this point. If there are any future retirements, obviously you would see that on the PJM website. Right now, we like preserving this optionality for a while, and we have the ability to do so.

Greg Gordon, ISI Group.

It's actually Jon Cohen; I'm stealing Greg's question, borrowing it. I guess, two questions -- first of all, on the last point -- can you tell us if there were any non-HEDD-compliant megawatts that did clear? So in other words, plants that you plan on upgrading by 2015?

No, no. So everything that cleared, I think, are the things that you would recognize in our dispatch, so nothing like that.

Okay, and the second question is, on the cost parity for Hudson and Mercer, you mentioned that $5 gas is required for those to be bid in and clear on the baseload basis. What is the cost parity? So, at $3 gas, you are burning coal and not gas; is that correct? Does that mean that the cost of running those units at coal is now cheaper than running those units and gas?

No, no, no. So I think it's just the opposite. If you think about what was happening earlier this year with the Hudson/Mercer units. So I'm not talking Bridgeport here. Hudson and Mercer run on either gas or coal. So when we ran them earlier this year, we were running them on gas. For a large portion of the period, they didn't run because the weather was pretty mild. So they were running on gas.

The comment that I was making is if you think about gas prices going up above $5, then when you do the parity for the economics for them to run, running on cold would be equivalent in the dispatch to running on gas because gas would be higher-priced. That's when we think about equivalents in their dispatch position. The fact that we were running, they had been running in July, as I mentioned, and running on coal, is not a function of that dispatch position parity, but a function of the demand in the market, given the weather and the prices and the need for more generation.

So it's really two separate comments. One is, there running more on cold now because the weather, and the demand is there. The other is, when you just think about them in kind of a neutral dispatch, not a weather pull of demand, the parity between gas and coal would be equivalent and slightly over $5 gas price environment.

Yes, I guess I asked my question poorly. If they are running on coal now, doesn't it behoove you to bid in your lowest cost for the unit? So does that mean that, at whatever gas price is now, $3 gas, that dispatching coal is less expensive than dispatching on gas?

Yes.

On a cost per megawatt hour -- your cost per megawatt hour, yes.

Right, all-in. But, exactly; and we always look at the all-in best economics for the business.

Andrew Gay, UBS.

Julian here. Carolyn, if you think strategically about the Company, I noticed the line with regards to the LFA, expand the capabilities of the business. Is that an indication that you are thinking about eventually broadening out the regulated business in any kind of meaningful way? I'm just thinking a la M&A, but willing to interject whatever you think?

Sure, thanks, Julian. So I think LIPA was a great opportunity for us; again, capitalizing on the reliability and the good work that the folks do at PSE&G. It obviously give us the opportunity to bid and, then, ultimately win, which was terrific. There's a lot going on right now, and the transition will start in 2014 at LIPA.

So as we think about opportunities that the Utility, I'd say they really are into two categories. But this first category, LIPA, is relatively small. As you know, the earnings opportunities from LIPA, as we've talked about before, is about $0.03 a share starting in about 2014. So ways to use those capabilities to expand beyond PSE&G, with the capabilities we have in the Company, are always good. But I'd say, as you think about the Utility and growing that business, we have been really pleased, frankly, with the organic growth results that we've seen. Because, of course, they come with providing shareholders with the regulated rate of return, and doing it without paying a premium that would come from a utility acquisition.

Frankly, given where we are with PSE&G, where we've really doubled the size of the Utility over the last few years, what I would like now is that we continue to have more opportunities to grow the rate base. So we have a 13% CAGR in the rate base in our numbers through 2013. That doesn't include the solar programs we just announced, which would obviously be on top of that. Although with a -- we'd have to time out the spending profile, and the opportunity for more investments. So LIPA-like things, if they come along, we'd always look at. But I think the real focus of the Utility is organic growth that we have demonstrated, and the significant opportunities we have for more organic growth, with programs here that to that we know how to do, that we've demonstrated we can do well, and that improve reliability for the key customers in our service territory.

So I think the balance is, whether you are organic, opportunistic -- we'll always be opportunistic, but organic has plenty of room to play out.

Operator, we are at the full hour. But I'd like to turn the call back to Caroling right now for some concluding comments.

Thank you, Kathleen. And thank you all for your questions. I appreciate the chance to chat with you today. I'll just sum up by saying that we were very pleased with the ability that we have to proactively and aggressively invest in our infrastructure to improve our liability, improve the environment as our solar programs, I hope, demonstrate to you, and improve our local -- and support our local economy in terms of job creation.

We've been pretty successful, I think, in focusing on operating successfully in an environment of low power prices for several years, and operating efficiency has improved. And reliability remains strong. Our investment program continues to be supported by a strong balance sheet, and regulatory mechanisms that provide our shareholders with the opportunity to earn reasonable, risk-adjusted returns and growth. And the energy markets, as you know, are in the midst of major transformation. We believe, at the end of the day, our actions and our opportunities place us in a strong position to meet the needs of customers, employees, and shareholders.

So with that, I thank you for your time and look forward to talking to you all again. Thank you.

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