Good morning. My name is Brian, and I will be your conference operator today. At this time, I would like to welcome everyone to the Public Service Enterprise's Third Quarter 2013 Earnings Conference Call. [Operator Instructions] Ms. Lally, you may begin your conference.

Thank you, Brian. Good morning, everyone. Thank you for participating in our call this morning. We understand it's a very busy day for earnings. But as you are aware, we released our third quarter 2013 earnings statement earlier today, both the release and attachments are posted on our website at www.pseg.com under the Investors section. We also posted a series of slides that detail the operating results by company for the quarter. And our 10-Q for the period ended September 30, 2013, is expected to be filed shortly. I won't go through the full disclaimer statement for 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. Although we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if our estimate changes, unless we are, of course, 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 the factors that may cause results to differ from management projections, forecasts and expectations, and for a reconciliation of operating earnings to GAAP results. I would now like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. And joining Ralph on the call is Caroline Dorsa, Executive Vice President and CFO. At the conclusion of their remarks, there will be time for your questions. [Operator Instructions] Thank you. Ralph?

Thank you, Kathleen, and thank you, everyone, for joining us today. It's hard to believe that it was 1 year ago when we were reporting results for the third quarter of 2012, while we were responding to the damage to our system caused by Super Storm Sandy. Our Utility PSE&G restored service to 2.1 million customers within 10 days, and PSEG Power's assets, you will recall, was severely tested as well, but performed so as to ensure that electricity was available to every one of those 2.1 million customers as they were being restored. Both companies in the past year have embarked on programs to strengthen their systems. But enough of the past. It's with great sense of satisfaction and, in fact, it's somewhat remarkable when looking back at what we faced at that time, that I can report to you strong operating earnings for the quarter -- third quarter 2013, and in fact, the 9 months of 2013. And on top of that, I can report to you this morning an increase in our operating earnings guidance for the full year from what had initially been $2.25 to $2.50 per share, to our new guidance range of $2.40 to $2.55 per share. So earlier this morning, we reported operating earnings for the third quarter of 2013 of $0.76 per share, compared with operating earnings of $0.75 per share earned in 2012 third quarter. We've delivered solid results that are consistent with our operating objective. And once again, it is due to the tireless efforts of a dedicated workforce that we are on track to meet our near- and long-term targets for capital investment and operational efficiency, and that we can raise our guidance for full year operating earnings. Our shareholders continue to realize the benefits earnings from the expansion…

Thank you, Ralph, and good morning, everyone. I'll review our quarterly operating earnings, as well as the outlook for full year operating results by subsidiary company. As Ralph said, PSEG reported operating earnings for the third quarter of 2013 of $0.76 per share versus operating earnings of $0.75 per share in last year's third quarter. For the 9 months ended September 30, we reported operating earnings of $2.09 per share versus $2.03 per share last year. Slides 4 and 5 in our webcast deck provide a reconciliation of operating earnings to income from continuing operations and net income for the quarter and the year-to-date. We have provided, as always, 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. I'll now review each company in more detail, and I'll start with Power. As shown on Slide 14, PSEG Power reported operating earnings for the third quarter of $0.43 per share, compared with $0.43 per share 1 year ago. Power's third quarter earnings benefited from higher PJM capacity prices, an improvement in the market price of energy, a decline in the supply cost of gas, and a strong operating performance. Before reviewing the earnings in detail, I want to spend some time on Power's gas position. Power currently sells wholesale natural gas under a full requirement Basic Gas Supply Service, or BGSS contract with PSE&G to meet the gas supply requirements of PSE&G's residential customers. Power has configured its contractual arrangements with interstate pipelines over the years, which amount to $1.3 billion cubic feet per day of firm transportation capacity to meet its obligations under the BGSS contract. Approximately…

[Operator Instructions] And our first question comes from the line of Kit Konolige of ETC Finances (sic) [BGC Partners].

A couple of areas. On the decline in demand, 2.3% in the third quarter. Can you give us what that is year-to-date? And a little color maybe on what you think is going on there and what the outlook is going forward from here?

Yes. So year-to-date, it was 2.7%. Remember, these are weather-normalized numbers, and I think I've done 26 of these quarterly calls and I always give this same caveat, which is weather-normalization is as much art as it is a science. But we've had some extreme weather conditions, so trying to back that out is not always easy. The big change this quarter was in the residential sector, that was down 2.9%. The good news, if you will, is we're primarily a commercial sector-driven service territory, and that was down 1% in the third quarter which is a little bit stronger than -- which is less of a down that it had been prior year to date. It's a combination of a slowly recovering economy. The unemployment levels in New Jersey are well-published at about 8.2%, 8.3%. We've seen some modest recovery in housing starts, but the status didn't go down as far as others in 2008 and hasn't sprung back as quickly as others. But it's a combination, we think, of economic factors and just greater use of energy efficiency.

And Ralph, do you see that? Is there a -- some kind of structural change going on here where the new normal is going to be that there's negative sales? Or do you expect this to be cyclical and bounce back? And what do you see as the, say, 3- to 5-year growth rate?

Yes, so what we've told regulators is that we think that the -- certainly, the old days of loan growth being proportionally GDP are gone. And the more recent year of load growth being half of GDP are likely to not be the case anymore. And that is an important part of why we are so insistent upon contemporaneous returns on our significant investment approach in Utility. Remember, as you well know, Kit, PSE&G's earnings growth are not driven by load growth. Our earnings growth are triggered by reliability enhancements, infrastructure replacement and enhanced resiliency, and the old system of regulatory lag, giving you some load growth to kind of carry you into the next rate case, is one that doesn't work when you have 0-ish load growth as we've been experiencing, and 0-ish is obviously being a little bit kind when we've just reported negative numbers. So whatever the future holds in terms of load growth, which looks to be something that is less than it has been in the past, I think that buttresses our argument for the need for clause recovery mechanism while we're making significant and necessary capital investment. So PSE&G is not about load growth. It's about rate-based growth. And the regulatory system has to reflect the new load growth paradigm.

Great. And one other area, if I could. Can you just give us a little more color, obviously, you mentioned on Energy Strong, the resolutions that have been passed by the local governments. Clearly, you're getting a lot of support there. Is -- has it become -- been mentioned at all in the gubernatorial race? And assuming it's not going to get done until after the election, when -- what kind of timing do you think we have on getting approval?

Sure, Kit. So remember that 2 of the last 3 major storms occurred within 1 week of election day. They were the Super Storms Sandy and the Halloween snowstorm of 2012, and third storm, I think that was Irene, which was in August. So mayors and elected officials know only too well the inconvenience and problems associated with local residents being without power. So as a result, we've had these 81 jurisdictions, a combination counties and municipalities rally to show up at public hearings, which went extremely well, I would characterize it, in the months of September and early October. But it wasn't limited to local jurisdictions that showed up in support. We had strong support from a myriad of business associations, hospital associations and labor union. The schedule now calls for evidentiary hearings to take place, I believe, it's in February through the beginning of March. So on a fully-litigated track, this won't be resolved until the end of March in the first quarter. But we remain hopeful that we could settle this because the conversations with the staff have been very, very reasonable. I mean, this is a big investment and they're asking good questions about engineering studies and expectations for what might be the range of cost associated with some of the proposals that we've made. I am not aware of comments that have been made by the candidates. I think early on, the governor said he expects the BPU to give us the full and thorough review, kind of the sort of reasonable and rationale approach that you would expect from this governor, just in light of the complexity of it, and the fact that he has a full BPU that's supposed to look after this. And I don't believe it's hit the radar screen of his opponent. I'm looking around the room here, and everyone's shaking their head, no. So I don't think I missed the article that might have mentioned it. So seeing that, we're still hopeful that we'll come through some settlement agreement around the end of the year. And as long as you allow me to define the end of the year as possibly including January, I feel very confident of that. That's where things stand right now.

And our next question comes from the line of Dan Eggers of Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: I guess, thanks for all the detail on the gas positioning and kind of the benefit you guys are seeing from basis differentials. But Caroline, I prefer to think about this a little more. What is the full year benefit you guys are seeing? If you got about $0.04 in the third quarter, if you look at kind of the basis over the year, how much accumulative benefit have you guys seen this year?

Yes. Well thanks, Dan. So you remember some of the things I said in my remarks, because of the way in which our contract structure works and the primary benefit is always to the PSE&G residential customer, you're going to see us get these benefits when they're available in those sort of shoulder seasons or seasons where the residential customer doesn't need a lot of heat, like the summer. So we saw the Marcellus prices really come down this summer. That was sort of the single biggest drop we saw, and that -- it lies immediately right into our shoulder summer period. So the $0.04 I just described in this quarter, the majority of it is coming from the Marcellus, is the quarter in which you saw the gas to electric benefit from Marcellus have the biggest impact on us this year. So that's the way to think about it from sort of a gas to electric has primarily been this quarter, and you wouldn't expect to see on the gas to electric a lot of benefit in the winter, because the benefit's going -- the pipeline is going to the residential customer. That being said, remember, in the first quarter, we talked about the fact that some of the volatility that was happening in gas, given our position and given our ability to sell off capacity and off-system sales when there is a need, actually contributed $0.04 per share quarter-over-quarter in the first quarter. But that was not the gas to electric, right? That was the BGSS itself in terms of its ability to cover -- recover our fixed cost, which we hadn't in the first quarter of '12, because you may remember, it's so mild that winter. So the way to think about it going forward, the way I'll encourage you to think about is you'll see us to the extent that this differential persists. And again, we don't know how long it will persist, but we have probably the single best positioning to garner it when it persists. It's going to be in shoulder periods through summer periods, where the residential customer doesn't have that gas demand. We didn't see it as much this spring because that Marcellus price drop really happened in July. So going forward, I'd encourage you to look for it in the sort of spring and fall periods, or shoulder periods, but from gas to electric, it's been this quarter that you've really seen it come through the P&L.

I think one of the other things we've noticed, Dan, that's been quite favorable, and is difficult to quantify, is that to the extent that, that benefit is not available to Power, that's because residential gas demand is high, which would tend to mean that we have some severe weather conditions, which benefit Power and Utility in other ways. And to the extent that there is not a strong demand, which would suggest that there's a weather condition that is not beneficial to Power and Utility, then the basis differential seems to expand, which offsets that negative outcome. So there's also this kind of natural hedge phenomenon taking place that seems to work to our favor. Dan Eggers - Crédit Suisse AG, Research Division: Okay. So just done with it, your $0.04 benefit, if spreads stayed where they are today, kind of in the second quarter, we could replicate something like we saw in the third quarter of this year because that'd be another low gas demand period. Is that a reasonable way of thinking about things?

So I don't want to forecast the specific, right? Because it depends on what happens to that differential, and of course, recognizing, as we said, there are some lines that are coming in, right, into the New York region, the Spectra line, the Williams line. So not certain how that basis will actually move in the future. But to the extent the basis is there, we think we're well-positioned to capture it, but I wouldn't want to get specific on a number because that all depends on weather conditions and everything else. Dan Eggers - Crédit Suisse AG, Research Division: Okay, that's fair. And I guess, just along those lines. Is that going to -- with this opportunity or maybe a more obvious of an opportunity, are you guys going to reevaluate how you hedge the gas generation in the future, maybe the structuring of the hedges or the magnitude of the hedges?

So I don't think so, Dan, for this reason, right? Because if you think about where I was citing the benefit, it's the spark spread widening that we received, the realized spark spread at that 40% to 45% level. Remember, as we look at our hedge table, as we always break out for you, the base load versus the intermediate, this combined cycle, that's the part of the fact that you see us do very little hedging in advance of the current year. So for example, it's about 10% hedge, that whole category right now for next year, that's typically what you see us optimize in the year. So to the extent that we see combined cycle has opportunities here, those opportunities are still going to be available to us, and we're going to hedge in, essentially, the same way for that part of the stack, which is in the year. And in the year is where we tend to have some visibility.

Our next question comes from the line of Neel Mitra of Tudor, Pickering. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I just wanted to understand the contract structure of the Marcellus gas at Power. Is the way to look at it that the firm pipeline capacity cost is borne by the PSE&G ratepayers and the -- that off-system sales when the gas isn't needed for them kind of accrues to Power as a variable cost with no operating cost associated with it?

Sure, Neel. So good question. So the cost of the pipeline is passed through to the residential customers. So it's not a net cost to power, so the residential customer is covering the full cost of distribution, as you would expect, nor is the pass-through of the gas to the residential customer a profit center for Power. It simply goes through to the residential customer. When there is excess beyond what the residential customers need, then we have the ability to make off-system sales, and when we make those off-system sales, the value that's garnered there is shared with the PSE&G customer. In fact, the majority goes to the PSE&G customer and then there's a small amount that's left for Power. So think of Power as providing this on a pass-through basis to the customer, covers -- customers covers the cost. Power doesn't make money on the actual throughput. Then to the extent there's excess, there's value garnered from the off-system. Majority goes to the customer, residential customer, and a minority of that comes to the bottom line for Power. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, great. So is the way we should think about it is that as these contracts kind of roll off, you'll re-contract them just from the perspective that PSE&G needs Marcellus gas to supply LDC and customers? Or is it more of a kind speculative bet that Marcellus pricing is lower?

No. So good question as well. It's not a speculative bet. So if you remember, I think Ralph said this in his remark. We set up this network of our contracting about 15 years ago. And it was designed and developed to cover the PSE&G load from liquid sources. So it's not speculative, but it's also not short term. These are actually very long-term, evergreen-like contracts that we have the rights to, together with the contracts we have for storage. The entire design was to support our PSE&G customers. The real story and then the story we've been telling this quarter is, as has always been the case, when the customer needs are lower and the excess can be used for PSEG Power, we do that. It turns out this summer that, that's turned out to be very beneficial because of Marcellus, but the original design and purpose, which has been for many years and will continue to be for many years, is to pass this value through to our customers, and then if there's excess, and only then if there's excess, we use it for PSEG Power.

Our next question comes from the line of Julien Dumoulin-Smith of GPS (sic) [UBS].

So switching topic a bit, if you will. I wanted to focus quickly on this switching phenomena you described. And I suppose the question is, is it yet just fundamentally the offers out there is just less competitive and there's less headroom in a rising capacity price environment? Or is it rather that we're reaching some sort of floor in customer migration and there's something of customer lethargy to be explained [indiscernible]?

Julien, as you know, we're not in the retail business. But our response would be that this is probably a combination of those 2, that your most price-sensitive customers were the first to go. And now, just having folks switch is a bit more of a challenge. [indiscernible] a decline in BGS prices, so our headroom has been single-digit delta throughout the year. And that headroom has to be something that your cost of customer acquisition lives under. So it's not a business position that we're in. But I think it's a combination of 2 things you mentioned.

And just to be clear, what level of switching did that correspond to for '14? I'm not sure I caught that.

As a percentage basis?

Yes, if you don't mind.

Yes, percentage basis, we don't forecast that any longer. But I can tell you the numbers that we see in terms of this is the overall aggregate switching from BGS, right? Or in that sort of mid-high 30 percentage point range, and that has not really changed in the past few quarters. So we used to try and track it every quarter and give you targets for it. What we think makes more sense is to give you those targets we now give you for BGS, which is, you may remember from my remarks, we just raised by 1 terawatt-hour for next year. So it's not just coming through to be that much more switching. And the reason really is, as Ralph said, the headroom just isn't that large. Whatever the retailers are doing on those dynamics in their profitability, obviously, a question for them. But it appears to have leveled out and, of course, as BGS prices have come down, right, the average price came down $1 when we started this year's BGS season. Given was what was rolling off and rolling on, there's just not that much difference.

Okay. And then looking at the Long Island opportunity here. Just to think about perhaps beyond the fees that you could receive here, can you be a little bit more explicit about the investment opportunities, perhaps rate based-like or otherwise, that you can earn on?

Sure. So Julien, so let's count -- and I try to point out the $0.03 in '14 grows to $0.07 to $0.08 by '16. And then there is a provision in the contract that requires that we propose a concept. It really is just a concept by July 1, '14 on the Utility 2.0. But what's interesting about it is that it describes in the contract, in words that are similar to many of the things that PSE&G has done successfully in New Jersey under various clause mechanisms, and those are renewable energy resources, energy efficiency and behind-the-meter services. So we have a team of people looking at that. That's not something that we can forecast a number right now or even a time frame. But the proposal is due from us to the LIPA Board on July -- by July 1 of next year. And we're excited about that because there are some good things we've been able to do for customers in New Jersey that we'd like to do for customers on Long Island, and I'm sure they get fair treatment as a compensation for doing so.

Great. And then lastly, not to beat up the subject one more time, but on the gas issue, looking towards '14 rather than '13, I presume a full year of sort of wider gas basis deposit to positive, but meanwhile, you could have some offsets from new gas infrastructure reducing that basis. Is that the right -- a fair way to characterize full year impact in '14?

Yes, I think that's very fair, Julien. I guess the way that I think about this all-in is we don't know what the basis will turn out to be. Obviously, that's determined by the market. We -- obviously, we serve our residential customers first. But we have a large position, as you saw from what we put in the slides here, right, of 0.6 Bcf per day of shale supply. So we have nice opportunity. And to the extent that, that opportunity presents itself in terms of a differential, we think we're actually pretty optimally-positioned to take advantage. And so in those periods where the customers need the PSE&G are low. To the extent that basis is still there, we're going to be able to capture it. So I think that -- I think all-in, that's the way I encourage you to think about it. We can't predict it anymore than you can predict it, but when it's there to be garnered, we garner it. We garner it first for our E&G customers, but after that, we garner it for Power. And we're pretty pleased about that opportunity of positioning, which wasn't developed for that reason, but has now given us a real opportunity.

And our next question comes from the line of Greg Gordon.

Guys, your balance sheet capacity is still quite robust and all the more so, by this -- bolstered by the strong performance you're seeing at PEG Power. If you don't get approval for the full $3.8 billion of Energy Strong, would that spare balance sheet capacity then be redeployed into perhaps some more robust growth in the dividend?

Yes so Greg, so we maintain that our #1 priority is reinvesting in the business. As you know, in addition to Energy Strong, we have some transmission resiliency programs that we are in pursuit of with PJM. So you would see us make sure that we're exhausting all regulated growth opportunities. Then we've been talking to PJM, as is everyone else, and very publicly about the 2012 RTEP enhancements that were pushed forth. That was grandfathered on the FERC Order 1000, so those projects would come to us as an incumbent. We proposed some projects coming out of Artificial Island as on FERC Order 1,000 basis as well. So I'm running through a laundry list of regulated Utility investments that are beyond Energy Strong. But of course, our primary focus right now is, over the near term, getting Energy Strong. Having said that, yes, #2 on the hit parade is the dividend. And then #3 on the hit parade, in anticipation of somebody else following up, would be share repurchase. But I would put, far and away, #1 is reinvesting in the business and then, #2, would be dividend growth.

Great. Two more questions. First is with the decision on LCAPP, does that change your calculus on whether or not you would bid sea worn[ph] into the next PJM base residual auction?

So partially, right? What it does is it reduces the risk of a competitively-bid unit having challenges come through subsidized plants. We would do the same kind of return analysis, we use the forward price curve for the near term and then we use our fundamental models over the longer term, and then we have our own internal hurdle rate that, I think, we've been applying in a fairly disciplined way. So those numbers have to pass muster first and foremost. And then of course, there's the qualitative discussion, which is all around, "Well gee, what do we think the rules will be like x years from now." And the recent court decision helped mitigate some of that risk, but they don't help in terms of the market fundamentals. By the way, Greg at the risk of beating a dead horse, I want to go back to your first question. Even with all of the Energy Strong and transmission opportunities that we see, at the risk of stating the obvious, the balance sheet is strong enough to support modest and sustain growth in that dividend. I think just your question was sort of without those things, would you do more, and I was responding in that vein earlier.

No, that was clear. Last question. Is the lack of load growth in the service territory, perhaps to some degree, related to the very high degree of rooftop solar penetration you have in the state? And if so, can you comment on trends in further penetration of distributed generation, mainly rooftop solar? And I guess that dovetails with the commentary on how the abstract markets are performing?

Yes, so clearly, all of these things are contributing factor. To Kit's point before, I mean there's energy efficiency, there's lack of a very strong and robust economic response. There's distributed generation. I think we're still the #1 developer of solar energy in the state. And when the program is finished, it's about 200 megawatts or so -- 180 megawatts, with a capacity factor of about 12%. So from an energy sales point of view, it's really fairly miniscule, which is kind of the challenge, right, around solar, that when you take that numerator, which is sizable in terms of the capital invested, and you divide by energy output, which is not so sizable, you get a pretty high cost of solar electricity, which is something that we're very clear with our regulators. That in pursuit of these RPS spends, that one has to be mindful of the rate impact to the customer from the point of view of cents per kilowatt-hour. So short answer, of course, will be yes, it's a contributor. Longer answer would be, if you do the arithmetic, it's not that big a contributor.

And going forward, do you see penetration continuing at the current sort of rate? Or do you see solar investment, both from utilities like yourself and independents declining?

Yes, I think that the real challenge -- that's a tough question to answer. The real challenge is, if we're determined to live by the Renewable Portfolio Standards, then the question I would pose to the policymaker is, when we originally test that standard, it's under the assumption that as we nurture the industry in the early stages, it would then achieve certain economic efficiencies either in the form of lower cost of panels or in the form of higher efficiency rates, that it would become kind of self-sustaining and after it, prices would come down and probably, the ITC would go away at the federal level. We've seen those panel prices come down, but it has not come down -- those prices have not come down enough to be economically competitive with $4 gas. And I think they're beginning to see the first example of that reflected in our own solar filing, right? We went in and asked for $800 million plus over 5 years, and we got $440 million over third -- 3 years. And I think, based on conversations I had with policymakers, that was kind of a reflection of, yes, we can't do this forever. We need to start seeing some of those expectations be realized in terms of the economic viability of the technology. And that makes perfect sense. I mean, it's just -- I'm a huge solar fan. We've invested over $1 billion in solar. But we can't keep doing this at the price point that it's been achieving and do it at the RPS levels that we hope to see in 2020 or 2023[ph].

And our next question comes from the line of Paul Fremont of Jefferies and Company.

So if I look at the -- you're expecting, I think, $85 million to $95 million of uplift at PEG Power versus where you had been previously. If I look at the $0.04 in the third quarter and then the other gas-related item in the first quarter, that makes up roughly, I guess, $70 million. So what makes up -- would gas, in some way, shape or form, also make up the remaining piece of the $85 million to $95 million? Or is that coming from somewhere else?

So Paul, in terms of the -- you've correctly pointed out the factors that we've highlighted and some of which we talked about today, gas in the first quarter and in terms of BGSS and then the $0.04 this quarter. Remember that one of the things we have also talked about during the year is we have had some higher market prices than original expectation. So on a year-over-year basis, that's given us some uplift a little bit different than what we expected. So prices have come up, and that you see that, of course, across the fleet in every quarter, offset by the hedges, but a little bit more positive than our expectation. So I think it's been -- we've got great operational performance. Now, we do expect that, but it's certainly come through. We did have weather that was warmer than normal this summer. Cooler than last year, but warmer than normal, and you know we always plan on normal weather. So when you put all those factors together, with the benefit we've actually seen on those specific things that I called out and you just called out, that's, overall, what really lifts us across the fleet. So it's a confluence of factors that have all worked in our direction. But of course, which we've been able to take advantage of because of our good operational performance.

And then if I look at the BGSS volumes, I guess, on a steady state throughout the year, roughly 75% is residential, roughly 25% is nonresidential. Would you not get the benefit for the nonresidential portion, even in the winter month in terms of pipe usage?

So the -- so just to clarify, right, for the residential customer, right, it's a pass-through cost. So there's no profitability kind of either way relative to that. And for the commercial customer that uses some of that gas and territory, I think we've gone specifically into all of that. But really, think of it is, in general, it's sort of a formula based on market prices in a competitive market. So I wouldn't look to that, frankly, as a significant source of overall earnings going forward. Think of that as a little bit more on just a competitive market basis.

I'm still not sure. In terms of my question, my question just relates specifically to winter month. On another word, in winter month, should we allocate some benefit because there's a roughly 75%-25% split, where 25% of the cost -- of the volumes, at least, are going to customers on which you are able to make a margin.

Yes, that's right. So again, a competitive, sort of a market-based approach for BGSS for the nonresidential customer. I just want to be sure to distinguish between the residential and nonresidential because there isn't margin in the structure for the residential customer. There is some margin for us under the contract for the nonresidential customer. But again, I wouldn't look into that as a significant source of earnings, and that's something we've been getting overall all the time, right. That's something that's been baked into our numbers, so baked into our year-on-year.

Right. But the -- I think the price differential at -- in the Marcellus is a recent phenomena. But what you're saying is even in months where you're at peak usage, you are still -- there will still be benefit that is essentially going to benefit PEG Power from the lower cost gas.

Yes. That's right. That's exactly right, yes.

And then if I look at third quarter, I would assume third quarter would be less of a profit opportunity for you than fourth quarter because you also are dedicating a certain amount of pipe to storage delivery, correct?

So we are dedicating pipe to storage delivery, as I mentioned. But keep in mind, you've got some going into storage, but you don't have the residential customer draw. So actually, from -- if you're just looking at the issue of what kind of benefit does Marcellus give to the combined cycle, the best opportunities for that are in the shoulder period where the customer demand, residential, PSE&G customer, is pulling less of the pipe, right? So we definitely are filling storage. We absolutely do that. But given the flow that we have, that you've seen in the slides in our deck, we fill the storage, but we still have extra room. And so, we typically fill the storage earlier in the summer month, and then when we -- the storage is essentially filling up, we have that extra flow on the pipe. We can use it for our own generation or we can sell that pipe capacity to others. So I would say, when you think about the gas pipeline and the benefit, you think about the potential benefit for us is the least in the winter and the most in the seasons other than the winter because you've got the least draw on the 1 class of utilization of the pipe that isn't a profit opportunity, and that's the PSE&G residential customer.

And then my last question just has to do with -- for the LIPA contribution, you say it's $0.03 in '14 going to $0.07 to $0.08 in '16. So in '15, should we just pick something like a nickel contribution. In other words, it goes -- I assume it goes up from the $0.03 but not quite to the $0.07 to $0.08.

That's exactly right. You should add another $0.02....

I think, operator, that brings us to the noon hour. And I know everyone's busy with earnings calls today. So if Ralph...

Yes. So thanks, Kathleen. So hopefully, you'll notice that Carol and I and the team are quite pleased with our quarter. We're pleased with the year-to-date. And moreover we're greatly encouraged by our opportunities and the fact that we have the financial strength to take advantage of those opportunities and have demonstrated the execution when the opportunities come our way. So we hope to see you all at EEI. Thank you for joining us today.

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

Thank you, Brian.