Public Service Enterprise Group Incorporated (PEG) Q2 2012 Earnings Report, Transcript and Summary

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. [Operator Instructions] As a reminder, this conference is being recorded today, July 31, 2012, and will be available for telephone replay beginning at 12:00 p.m. Eastern today until 11:30 p.m. Eastern on August 14, 2012. It will also be available as an audio webcast on PSEG's corporate website at www.pseg.com. I would now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Keisha. Good morning, everyone or good afternoon. We appreciate your participating in our call this morning. As you are aware, we released the second quarter 2012 earnings earlier today, and you can find the release and attachments posted on our website at www.pseg.com under the Investors 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 statements 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 in today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. And although, we may elect to update 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. [Operator Instructions] Caroline?

Thank you, Kathleen, and thank you, everyone, for joining us today. 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 a 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 5 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 we'll 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'll 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 -- show that our strategy is on track. I 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 continued to define our experience for the second quarter. Although, our weather normalization costs in our gas business enabled us to earn our authorized return. Credits 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 2 major businesses is almost equal in both periods. We have provided you with a 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. So 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 and continued strong contribution from the nuclear fleet. Lower realized priced reduced Power's earnings by $0.05 per share quarter-over-quarter. The decline reflects lower prices under the BGS contract as well as lower wholesale sales prices. Contract price for 1/3 of the BGS-related load declined from $104 per megawatt hour to approximately $84 per megawatt hour on June 1, 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's units are located, as opposed to coal in the West. Bases, however, has improved from first quarter levels. The return to service of the transmission lines and coal 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 bases 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 9,000 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 clear 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 rate 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 borne 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 sale on 2 units. The nuclear fleet operated at an average capacity factor 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 expanded from 52% to 57% in the quarter. Power's 270 megawatts of new efficient peaking capacity at Kearny went into service on June 1 and was picked up by PJM on Day 1 to assure reliability and they've 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 has 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 terawatt-hours 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 terawatt-hours 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 terawatt-hours 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, a 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 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 attained 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 Utilities' 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 and renewables, which is the second key part of the Utilities' 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 5-year period to add solar capacity on landfills and brownfield sites. The plan also calls for spending up to $193 million over a 3-year period under the Solar Loan program to support the financing of solar by businesses and homeowners. The 2 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 supportive 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 mains. Both of these, along with our proposed solar investments and transmission, can help grow our utility, while 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 our 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'll 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's Holdings remains focused on the startup of its $75 million investment in the 25-megawatt Queen Creek solar print plant in Arizona scheduled for operation later this year, as well as transition activities in support of a 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 levels. 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 at PSE&G without the need for additional equity. Finally, we remain within 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 may have.

[Operator Instructions] Our first question comes from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Caroline, with the RPM auction having taken place since the last earnings call, can you just share kind of the corporate strategy around addressing the MOPR ruling in any thoughts you guys might have around the LCAPP lawsuit that's, I guess, in court today? What strategies might occur if you do not get a successful outcome in that case?

Sure. Relative to capacity, as you know, as we mentioned, there are efforts underway with PJM as I mentioned to improve the understanding and transparency relative to MOPR prior to next year's option. 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'd share with you on the court case is similar to what we've been talking about all along. We do think that it makes sense to preserve the viability of markets, and that's 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, or 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 an 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's been before.

And our next question comes from Mr. Paul Patterson.

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

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

Okay. And then in terms of peaks, looking at PJM and what-have-you, we've had really hot weather as you know, most recently, and I haven't seen any announcement new peaks really in PJM, and I was wondering if you guys have, your market people or whatever, seeing any change in demand response? I know we've got a new energy demand response tariff 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 we have really hot weather, and I don't think we've seen 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 in that. It's a little hard to measure at this point in time, or whether part of what we're seeing in response to peak is response to warm weather to some curtailment of demand that comes from people just being -- conserving because of their economic situation or whatever. So you're right. We haven't hit the peaks. It's 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.

Our next question comes from the line of Travis Miller with Morningstar.

I was hoping you could quantify a bit the earnings benefit that you're seeing from that increase in combined cycle generation, I mean, we talked about it a lot. But is there an earnings offset that you're 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 PGS provides a significant portion of our pricing and our hedging in terms of providing the overall price. So it's good to have a combined cycle availability. We're very pleased. We have the largest combined fleet in PJM. Our capacity factor was 57% in the quarter but, obviously, when you look at it all together, you balance that 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 at reasonable hedging strategy, which I think gives us the opportunity to take advantage of some of those full requirement contract prices.

And our next question comes from Kit Konolige with EPC financial.

So on the segment earnings, Caroline, as you noted, they're running about neck and neck between the Utility and Power year-to-date. You, I believe, are 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're right, we're very close on a 6-month basis, right, 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're 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'd 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 mentioned, they would be essentially flat if we look 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're $0.11 lower. But what we were signaling is for the full year, they'll basically be flat. So that's going to be a differentiator for Power as you think about kind of the go forward. That's probably the single biggest thing I'd 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 might point to obviously continuing our transmission investments. Obviously, the announcement that we made on Solar today would not be a 2012 earnings effects, that would be a filing that will be affecting future periods. So just keep in mind Utility transmission. And then as we come in to the later period as we get into the fall and into the winter. Obviously, the winter weather would have an impact. Although, keep in mind for the Utility, the winter has the gas weather normalization clause, which allows us to earn our authorized return. 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're 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 in to '13 and less so for '14, consistent with what we've done in the past. We're 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, that is relatively consistent with prior. And for the Utility, going forward, I just -- keep in mind the ongoing investment program that we have, $3.5 billion of transmission spending over the 3-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're 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. And one other area, just to clarify. I think you mentioned that gas prices would need to be $1.5 to $2 higher for coal to be competitive. So we're talking about gas prices would have to get above $5 before that the coal plants run some more, basically?

So gas prices above $5 is about right, Kit, so you're right on. Relative to the coal units running, it's not about their running when there's a strong demand that we would see in the summer. It's about -- that would be the trade-off price where they would become sort of equivalent in the dispatch with the gas units, right, the combined cycle units. It's not about the fact that goal can't run in 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 equivalence 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 and demand, would tend to not change that dispatch order very quickly?

Yes, I think that's fair. But I would say even though we've 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.

Our next question comes from Stephen Byrd with Morgan Stanley.

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

Yes, so good question, Stephen. Right now a lot of what we're seeing in the market is more focused really on the mercury rules than the CASPR rules in terms of having that significant impact, and you may remember, obviously, it was a pickup in the market in CASPR late last year. So we're hopeful, relative to CASPR, 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 just want to build on Kit's earlier question on the coal plants and capacity factors. Relative to last year, the New Jersey coal, the Hudson and Mercer, I guess the second quarter of 2011 capacity factor is around 33% and this year it's at 14%. Are these plants, given the commodity environment that we're now looking at, are these plants that are likely to be NPV [ph] 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 shut down 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're running now and, remember, these plants, and 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 the 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 advantage. So we do see them as long-term valuable assets, and we're pleased to see them. Frankly, we're running on coal as we come into the summer.

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

Can you address the timeline for both the filing on the Solar program that's been proposed today, as well as kind of the timeline on, during the course of that 5 years, what the spending profile would look like?

Sure, Michael. So relative to the timeline for the program, as we've said before, we didn't expect even, as we were considering these filings, that there'd be any incremental spend in 2012 and I still think that's accurate. So we will be filing shortly. 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 suspending would start. And 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, right? So Solar 4 All, Solar 4 All II is a program that we think we would expect to spend the dollars over the next 5 years and for the Solar Loan Program about 3 years in terms of when the loans would go out and, obviously, they'd 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 '09, the spending -- total expected about $456 million. We still have about 95 to go. So that's sort of consistent with the 3-, 4-year program and in the Solar Loan Program, we actually had 2 programs as you may recall, again, they take a multi-year period. So I think 3 years to 5 years is the right way to think about it: A little shorter for the loan program, a little longer for the Solar 4 All II program. Both of them are filed generally consistent with our existing programs, i.e. contemporaneous return 10 3, very similar to what you've seen before. That's why we're 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, where -- there had been some discussion about a gas distribution kind of a, an Ohio-like distribution upgrade program. Can you give us an update on where that stands?

Sure Michael. So 2 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 talked about the environmental spending being 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's been in the past. That allows PSE&G to essentially keep its cash from operations, raise 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, the transmission program with formula rates and flip in rate base for some of our major programs start to generate cash relatively quickly, that supports our ability to have the Utility, to be able to keep its cash and have adequate financing. So everything we're doing, at the bottom line, as we said before, there's no need for any equity issuance because the balance sheet and cash flow generation of the 2 companies is strong. From the perspective of incremental programs, you're right. We've mentioned that gas disk [ph] program a number of times before, and we still have the opportunity for the gas disk program as well as some energy efficiency, we've not announced any filings of those programs but cast iron gas main replacement, something that we are obviously interested in, and we understand the status as well. It's something that you could see via program in this picture, that's why we continue to put it in our materials and remember we talked about that program as multi-year as well and of like a 5-year program like Solar 4 All could be, with spending in the range of about $250 million per year that we could logistically do well. That is the kind of thing that our balance sheet still provides room to do even on top of the 800 -- up to $883 million that I just mentioned, because of the strength of the credit metrics that I mentioned on 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 just mentioned. We can do $3.5 billion transmission that you 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.

Next question comes from Paul Fremont with Jefferies & Company. Paul B. Fremont - Jefferies & Company, Inc., Research Division: 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 weather-normalized sales growth in residential was 1.8%. But for commercial and industrial, it was down, such that when you roll the Utility together for it's electric sales, it was up less than 0.5%, which is why we said essentially de minimis growth this quarter. Paul B. Fremont - Jefferies & Company, Inc., Research Division: Okay. So less than 0.5% for the total -- company-wide?

That's right. For electric weather normalized for the quarter. Paul B. Fremont - Jefferies & Company, Inc., Research Division: 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, I think I mentioned on the remarks, it's about 38% for the quarter, recall our guidance for the year is between 36% and 40%. We're staying with that 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. 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. BGS price is down. Market prices is obviously up a little weather. We're still comfortable with the guidance range and we always watch the headroom on a month-to-month basis. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And you brought up the Bases differential earlier and talked about seeing some improvement in the second quarter. Can you give us a sense of where you expect to see Bases for the full year 2012?

Sure. So yes, Bases obviously had 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 that had the impact of reducing the differential and in some cases, slowed direction at various points in time. With those being resolved as where we are now as well as [indiscernible] with the warmer weather and a little firming of gas prices, we see the return of Bases. And on the forward market forecast, as we Bases, we see positive Bases for our regions. It's not at the levels it was a year [indiscernible] ago, we're still talking in the single digit; modest, single digit levels. But keep in mind, of course, we do monetize basis through BGS, and that's obviously something that continues to remain important. So was challenged earlier. Here's the return. Stayed in the forward markets at levels that are positive for us but not at levels that we had experienced a few years ago. Paul B. Fremont - Jefferies & Company, Inc., Research Division: So is it safe to say, I mean, a couple of dollars is what you would expect for this year?

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

Our next question comes from Andrew Gay with UBS.

It's Julien here. Actually, most of my questions have been asked and answered already as well. Perhaps just curious with regards to perhaps outside of the court case right now with regards to MOPR. Broadly speaking for policy, what are you guys looking to do in terms of revising MOPR, what would be the goal there? And obviously, a number of different things have been thrown out there by various companies. What would you -- 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 kind of speculate on what we would like to see. I think just some core principles, things that we've talked about before, I think are logical to mention here 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 a very valuable and well functioning capacity market, which we want to see continue. In terms of specifics and looking at alternatives and things like that, I think it's just too soon to start to talk about that in public as we really should let the PJM process, I think, take its course.

Do you have any sense on timeline for that or just...

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

Our next question comes from Steve Fleishman with Bank of America.

Just first a clarification on the new Solar program. Thank you for giving the rough years for both the Solar 4 and the Solar Loan. What would be the split, roughly, of the $883 million between the 2?

Sure. So for the Solar 4 All II program, this new Solar 4 All II program, up to $690 million spending out over a 5-year period. And for the Solar Loan III program, up to $193 million over about a 3-year timeframe. I mentioned the up to's [ph] , just to provide some clarification on what that means. So this is how we will file and of course we'll 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 I, the current program, we had approval for 80 megawatts and up to a certain amount of spend, and so as the price 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 2 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'll 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 2 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, I 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 per year amount. On top of the things that we've -- the process of filing these solar programs. So that's really where we would turn to next. These 2 programs, if approved, would give us nice incremental renewables investment in solar, and I think gas disk could be the next place that we can -- 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 and ways that are good for customers and that are shareholder-friendly because of no need to issue equity by the company for any of our undertakings.

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

Sure. So we had about 9,000 megawatts clear, as I mentioned, that's the $167 million per megawatt per day price. We had announced, previously, plans to retire some megawatts that we had notified, the 283 megawatts of ICAP, and then we have the peakers that came online that I just mentioned that have already been called as I mentioned as well. We also had bid some of our capacity that did not clear, as you can tell from the totals, but remember some of that capacity is capacity that gives us flexibility to rebid in future auctions for the period, which you know if you bid in the current auction, if you don't clear what -- you reserve the optionality to bid in later auctions. In addition, we're looking at whether some of these ATDD units would still be valuable to the region of their ancillary capabilities like Black Star. So all of those things are things that we are looking at right now relative to those units.

Okay. So there's no new update on official coal retirement, so to speak?

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

Our next question comes from Greg Gordon with ISI Group.

It's actually Jon Cohen. I'm stealing Greg's question, or borrowing it. I guess 2 questions, first of all, on that last point, can you tell us if there were any non-HID [ph] 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 discussion. Nothing like that.

Okay. And the second question is on the sort of cost parity for Hudson and Mercer, you mentioned that $5 gas is required for those to be sort of bid in and clear on a base load basis. What is in the cost parity -- so at $3 gas, you're burning coal, and then not gas, is that correct? Does that mean that the cost of running those units at coal is now cheaper than running those units at gas?

No. So I think it's just the opposite if you think about what was happening earlier this year with the Hudson and 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. Now for a large portion of the period, they didn't run because 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, coal -- running on coal would be equivalent in the dispatch to running on gas because gas would be higher-priced. That's when we think about equivalence in their dispatch position. The fact that they were running -- that they've 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 2 separate comments: One is they're running more on coal now because of the weather and the demand is there. The other is when you just think about them in a kind of neutral dispatch, not a weather pull of demand, the parity between gas and coal would be equivalent in slightly over $5 gas price environment.

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

Right, all in. But exactly, we've always looked at the all-in best economics for the business.

And we do have a follow-up question from Andrew Gay with UBS.

Julien here. Caroline as you think strategically about the company I noticed the line with regards to LIPA expand the capabilities of the business. Is that kind of an indication that you're thinking about eventually broadening out the regulated business in any kind of meaningfully, I'm just thinking ala M&A but willing to interject whatever you think.

Well, 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 gave us the opportunity to bid and then ultimately win, which is terrific. There's a lot going on right now in the transition. We'll start in 2014 in LIPA. So as we think about opportunities at the Utility, I'd say they really are in 2 categories, but this first category LIPA is relatively small. As you know, the earnings opportunity from LIPA, as we've talked about before is about $0.03 a share starting in 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've been really pleased, frankly, with the organic growth results of that we've seen because, of course, they've come with getting -- providing shareholders with a 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 Utility over the last few years, what I'd 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 2014. That doesn't include the solar programs we just announced, which would obviously be on top of that although the [indiscernible] time out the year for the spending profile, and the opportunity for more investments. So LIPA like things, as they come along, we'd always look at, but I think the real focus of the Utility is the organic growth that we have demonstrated and the significant opportunities we have for more organic growth with programs here 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 more to the organic. Opportunistic, we'll always be opportunistic. But organic has plenty of room to play out.

Operator, we're at a full hour. But I'd like to turn the call over -- back to Caroline 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'd just sum up by saying that we're very pleased with the ability that we have to proactively and aggressively invest our infrastructure to improve our reliability, improve the environment as our solar programs I hope demonstrate to you and improve our local -- and support 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 remained 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 and we believe that 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.