Kathleen A. Lally - Vice President of Investor Relations Ralph Izzo - Chairman, Chief Executive Officer, President, Chairman of Executive Committee, Chairman of PSEG Power LLC, Chairman of Public Service Electric & Gas Company, Chief Executive Officer of PSEG Power LLC and Chief Executive Officer of Public Service Electric & Gas Company Caroline D. Dorsa - Chief Financial Officer and Executive Vice President

Travis Miller - Morningstar Inc., Research Division Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Gregg Orrill - Barclays Capital, Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Anthony C. Crowdell - Jefferies LLC, Research Division Shahriar Pourreza - Citigroup Inc, Research Division

Ladies and gentlemen, thank you for standing by. My name is Nick, and I am your conference operator today. I would like to welcome everyone to today's conference call, Public Service Enterprise Group Second Quarter 2013 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, July 30, 2013, and will be available for telephone replay beginning at 12:00 p.m. Eastern today until 11:30 p.m. Eastern on August 8, 2013. 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. Kathleen A. Lally: Thanks very much, Nick. Good morning, everyone. Thank you for participating in our earnings conference call this morning. As you are aware, we released second quarter 2013 earnings statements earlier today. And as mentioned, the release and attachments are posted on our website, www.pseg.com, under the Investors section. We also posted a series of slides earlier this morning that detailed operating results by company for the quarter. Our 10-Q for the period ended June 30, 2013, is expected to be filed shortly. I'm not going to go through 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 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 our 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 would now turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. Joining Ralph on the call is Caroline Dorsa, Executive Vice President and Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions. Thank you.

Thank you, Kathleen, and thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the second quarter of 2013 of $0.48 per share compared with operating earnings of $0.43 per share in 2012 second quarter. The results for the quarter bring operating earnings for the first half of 2013 to $1.33 per share, and that's compared with operating earnings of $1.28 per share earned in 2012's first half. Slides 4 and 5 contain the detail on the results for the quarter and the first half. We are very pleased with our results. All of our businesses performed well, and once again, demonstrated the ability to succeed against the background of slow growth in the economy at large and lower power prices. Our earnings results for the quarter were once again based upon our employees' efforts. We are realizing the benefit to of earnings from the expansion of our investment in transmission, which remains on time and on budget. Our earnings are also supported by our employees' focus on controlling the growth and operating expenses. Lastly, our financial results were aided by the restoration, post Sandy, of most of our peaking generating stations to assure their availability during the key summer period. But strong execution above all means providing a level of service expected by our customers. We would not be able to deliver this level of service at all times, and especially during periods of extreme weather, as we have experienced, without our daily focus on maintaining, as well as improving through ongoing investment, our electric and gas system. Earnings for the second quarter also continued to be supported by the locational advantage enjoyed by Power's assets, the dispatch capability of Power's portfolio of assets and Power's open position on its intermediate and peaking generation. As a result of PJM's latest auction of capacity, that is the RPM auction, Power's assets will receive an average price of $1.66 -- $166, that would be terrible, $166 per megawatt day for the 2016, 2017 year. The results for the latest auction are essentially inline with the average price of $167 per megawatt day received in last year's auction, but it remains above the average price received for capacity within the PJM region. The price for capacity in Arizona will stay at a similar level from mid-2014 through mid-2017. Auction results yielding prices for that period have incorporated many pushes and pulls, including the impact of new transmission transfer capability, the addition of subsidized generation, the impact of environmental rules on capacity and the tightening of regulatory oversight over new options, such as demand resources. Over the past few years, we have all seen administrative design elements within the capacity market create some volatility in pricing as PJM continues to address improvements in market efficiency. But upon more careful scrutiny, it is quite clear that stable capacity-related parameters exist in our zone and have for the past 3 years. We also benefit from our close proximity to low-cost shale gas in the Marcellus basin, which has resulted in lower gas cost of PSE&G's customers and provides our large fleet of gas-fired combined-cycle generating assets with a source of low cost fuel supply. This profile allowed us to capture value by managing volatility in the energy marketplace, while minimizing downside risk through the hedges on our base load fleet. In short, this past quarter, the combination of returns on new investment and the capable management by our employees of each business demonstrated PSEG's ability to perform well, even against the backdrop of slow economic growth and low power prices. But we remain equally focused on meeting our long-term growth objectives. The New Jersey Board of Public Utilities, the BPU, approved our plans to invest up to an additional $446 million in renewable energy through our Solar Loan and Solar 4 All programs. This investment will fund up to 143 megawatts of new solar capacity. We are making progress with key stakeholders on explaining the importance of strengthening our infrastructure and improving system resiliency through our proposed Energy Strong program. Nine months have passed since Superstorm Sandy devastated New Jersey, but it remains very much on our minds and on the minds of regulators and other policymakers. Public support for Energy Strong has grown since we proposed the investment program back in February. As of today, 55 municipalities and 5 county governments have passed resolutions in support of our investment program. The BPU has appointed a lead commissioner and we are in discussions regarding the scope and timing of the work to be performed. As a reminder, we have asked the BPU to approve spending for the first 5 years of the 10-year program. This would amount to $2.6 billion of the $3.9 billion program. It would represent approximately $2.2 billion of capital spending to strengthen the distribution through 2017, which is the timeline we've outlined previously for our capital program. All of these statistics are independent of additional transmission investments we would make. So we expect the program to receive careful consideration, given the opportunity to improve the resiliency of the distribution system with little net impact on the customer's bill due to the coincidental expiration of various other charges. Separately, in New York State, we are discussing the final terms of a renegotiated contract to operate the Long Island Power Authority's distribution system at the start of 2014. These actions will strengthen the infrastructure and improve our system reliability throughout the region. In the true spirit of how PSEG has operated for a century, this will enable us to serve customers better while providing reasonable returns to our shareholders. We aren't changing our guidance for full year operating earnings of $2.25 to $2.50 per share. However, given the strength of our results for the second quarter and the first half of the year, we do expect our full year operating earnings to be at the upper end of our guidance, assuming normal weather and normal unit operations for the remainder of the year. So with that, I'll turn the call over Caroline, who will discuss our financial results in greater detail, and then I'll join her at the end for Q&A. Caroline D. Dorsa: Thank you, Ralph. Thank you, everyone, for joining us today. As Ralph said, PSEG reported operating earnings for the second quarter of 2013 of $0.48 per share versus operating earnings of $0.43 per share in last year's second quarter. We provide you with the reconciliation of operating earnings to income from continuing operations and net income for the quarter on Slide 4. We've also 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. And I'll now review each company in more detail starting with power. PSEG Power reported operating earnings of $0.22 per share for the second quarter of 2013, compared with operating earnings of $0.22 per share for the second quarter of 2012. Power's second quarter earnings benefited from higher 2013 realized PJM capacity prices and a quarter-over-quarter improvement in the market price for energy with an increase in the price of gas from last year's second quarter levels. Market prices for energy were influenced by a higher price for natural gas, quarter-over-quarter, and an improvement in the premium on power sold in the PS zone which, of course, we know is basis. These conditions were similar to, but not as extreme as, the market conditions Power experienced in the first quarter and you would expect that moderation in a shoulder quarter. The market price for Power is influenced by the movement in the price of gas and it's also influenced by constraints on generation and on the transmission system. This upward movement in realized wholesale market pricing quarter-over-quarter increased Power's earnings by $0.04 per share, an increase in the average price received on PJM capacity to $183 per megawatt day from $124 per megawatt day improved Power's quarter-over-quarter earnings by $0.07 per share. And as a reminder, PJM capacity prices increased to $244 per megawatt day on June 1 of this year, and that price factors into 1 month of the average price realized in the second quarter, but that $244 price will be in place through May of 2014. This improvement in wholesale market pricing offset the impact on earnings of an approximately $9 per megawatt hour decline in average contract prices on energy hedged through the BGS, Basic gas Generation Service contract, as well as other wholesale contracts. PSEG Power's operation and maintenance expense was unchanged from year-ago levels. An increase in O&M at fossil associated with planned outage work was offset by a reduction in outage-related work at nuclear. An increase in depreciation expense related to the installation of 400 megawatts of new peaking capacity and low pressure turbines at Peach Bottom was offset by a decline in interest expense. PSEG Power's output during the quarter was basically unchanged from the 12.7 terawatt hours generated in the year ago quarter, an increase in output from Power's base load nuclear and coal fleet offset a decline in production at Power's New Jersey-based coal units. The nuclear fleet operated at an average capacity factor in the quarter of 87.9%, bringing the capacity factor for the fleet in the first half of the year to 94.4%. The fleet's performance in this quarter was influenced by a refueling outage and main generator repair work at Salem 1, which, as you know, is 57% owned by us and operated by PSEG Power, versus a refueling outage in the second quarter of 2012 at Power's 100% owned and operated Hope Creek unit. Power's base load coal units in Pennsylvania increased their generation. The combined cycle gas-fired fleet ran at levels equivalent to their strong performance in the year-ago period, with a 57% capacity factor. The location of PSEG Power's generating and natural gas assets provided with access to low cost gas supply in the Marcellus basin to partially fuel the combined cycle fleet. The combination of price and operating performance supported gross margins of $43 per megawatt hour, similar to the level realized in the year-ago period. Power continues to forecast output for 2013 of 53 to 55 terawatt hours. Output for the remainder of the year of 26 to 28 terawatt hours is 70% to 75% hedged at an average price of $51 per megawatt hour. For 2014, forecast output of 53 to 55 terawatt hours was approximately 55% to 60% hedged at an average price of $49 per megawatt hour. Power has hedged 30% to 35% of its forecast generation in 2015, that total forecast generation of 52 to 54 terawatt hours, at an average price of $49 per megawatt hour. The increase over the last quarter in the percentage of generation hedged through 2014 and 2015 reflects an increase in the level of hedges on our base load generation, consistent with our ratable hedging program. Power's intermediate and peaking generation remains open and the data by year is provided for you on Slide 20. Average hedge prices continue to reflect assumed BGS volumes of 12 terawatt hours in 2013, and 10 terawatt hours in 2014. Power's hedging profile is very consistent with our prior practice, and as we have demonstrated, ratably hedging our base load while some intermediate and peaking remains open, even in the current year, reduces Power's downside risk by recognizing the need to meet demand requirements of full load contracts, like BGS, while minimizing the risk of a unit not being available. It also provides Power the opportunity to optimize the portfolio under the right set of market conditions. The forecast of Power's operating earnings for 2013 remains unchanged at $535 million to $600 million. However, given Power's strong results in the first half of the year, we expect operating earnings for the full year to be at the upper end of Power's guidance. Results for the remainder of the year will continue to be influenced by a decline in the average price of our hedges and higher capacity prices. Remember that the average price for Power's capacity in PJM increased to $244 per megawatt day on June 1 from the prior $153 per megawatt day. We also continue to forecast an increase in Power's O&M in the second half of the year, given major maintenance planned at 2 of the combined cycle units and a fall refueling outage at Hope Creek. The forecast for Power's operating earnings, as we have indicated, doesn't include the cost of storm-related repair. Power expensed approximately $200 million pretax on storm recovery activity in the second quarter of 2013. This brings the total pretax storm-related expenditures to $135 million. Of this amount, Power recognized an additional $25 million of insurance proceeds in the second quarter for a total of $44 million in insurance proceeds to-date. Let's now turn to PSE&G. PSE&G reported operating earnings for the second quarter of 2013 of $0.24 per share compared with $0.20 per share for the second quarter of 2012. And results for the quarter are shown on Slide 23. PSE&G's second quarter results reflect the contribution to earnings from the increased level of transmission investment. The execution of our transmission program added $0.04 per share quarter-over-quarter. PSE&G experienced weather conditions in the second quarter, which were favorable both relative to normal conditions and in comparison to weather experienced in the year-ago quarter. As compared with normal temperatures, weather was colder than normal in April, normal in May, and warmer than normal in June. Electric kilowatt hour sales declined approximately 2.5% in the quarter. Demand for electricity from the residential sector grew by about 0.8%. However, demand from the commercial and industrial, or C&I sectors, remained weak. Demand for electricity continues to be affected by customer conservation in the face of a slowly improving economy. PSE&G's margin on electric sales was flat quarter-over-quarter, despite the decline in sales, as margin from C&I customers is based on demand levels, more than on volume. Sales of gas increased 17% quarter-over-quarter, reflecting primarily more normal winter weather versus 2012. Consumers of gas after years of responding to high commodity prices by reducing consumption appeared to have adjusted their behavior to reflect an expectation of lower commodity prices, and we see a small uptick in the weather normalized gas sales. The net impact on PSE&G's earnings from weather and the change in sales was a reduction in quarter-over-quarter earnings of $0.01 per share. The earnings comparison reflects an increase in weather-related demand for gas of $0.01 per share, which was offset by the absence of $0.02 per share of revenue accrued under the gas weather normalization clause in the year-ago quarter. PSE&G implemented cost controls throughout the quarter in response to lower demand growth. As a result, distribution-related O&M expense was unchanged quarter-over-quarter. For the remainder of the year, distribution-related O&M is expected to be lower than levels realized in the prior year, given expectations for a decline in storm-related restoration expense. Recall that PSE&G incurred approximately $0.05 per share of O&M in the fourth quarter of 2012, related to Superstorm Sandy-related restoration work. These expenses, unlike the treatment for power storm restoration work, are reflected in operating earnings, as you recall, we discussed last year. PSE&G's tight control of operating expenditures continues to allow it to earn its authorized return. As Ralph mentioned, the New Jersey BPU approved the settlement authorizing an increase in PSE&G's spending on Solar by up to $446 million. We have, as a result, adjusted our forecast level of capital spending. PSE&G is projected to spend approximately $215 million over the 2013 through 2015 period on the Solar 4 All extension and Solar programs, resulting in total capital expenditures over this period for PSE&G of $5.1 billion versus the prior forecast of $4.9 billion. Spending on these 2 newly approved programs will continue beyond 2015. Slide 26 outlines the updated capital expenditure program for 2013 through 2015. These new programs will bring PSE&G's investment in Solar to $1.1 billion. Our forecast of PSE&G's operating earnings for 2013 remains unchanged at $580 million to $635 million. Results will be influenced by a full year increase in transmission revenue and the absence of the negative impact of Superstorm Sandy on both sales and O&M. Let me now turn to PSEG Energy Holdings and parent. Operating earnings for PSEG Energy Holdings/Enterprise in the second quarter of 2013 were $8 million, or approximately $0.02 per share, versus operating earnings of $4 million or $0.01 per share earned during the second quarter of 2012. These results were in line with expectations and reflect a gain on the sale of a commercial office complex in the second quarter. Holdings remains focused on monetizing key assets as it also builds a portfolio of Solar projects. The expected fourth quarter operation of a 19-megawatt solar project in Arizona will bring holdings portfolio to 6 solar projects, with a total capacity of approximately 90 megawatts. We continue to forecast full year operating earnings for PSEG Energy Holdings/Enterprise of $25 million to $35 million. The results will include the contribution from Holdings legacy investments, a full year of operation at the Milford and Queen Creek solar facilities, which entered service in the fourth quarter of 2012, and the commercial operation of a 19-megawatt facility in Arizona in the fourth quarter at a cost of approximately $50 million. Our forecast level of consolidated capital spending has increased by approximately $215 million over 2013 through 2015 related to the solar approval to bring us to $6.4 billion. PSE&G's capital program represents approximately 80% or $5.1 billion of our planned investment. We're in a strong position to finance our capital program. PSE&G issued $500 million of 10-year medium-term notes at 2 3/8% and retired $150 million of 5% medium-term notes in the quarter. At the end of June, debt represented 41% of PSEG's consolidated capital, with debt at Power approximating 28% of the capital base. Power's cash flow remain strong and PSE&G's cash generation has improved with its ability to earn return on increased levels of capital investment. As we have said, we can finance our existing capital program without the need to issue equity, and we can finance an expanded capital program that includes spending on Energy Strong-related projects without the need to issue equity. And this still leaves us with the opportunity for modest and sustainable growth in the dividend as we look out to the future. We continue to forecast operating earnings for the full year of $2.25 to $2.50 per share. And as Ralph indicated, we expect results for the full year to be at the upper end of our guidance, assuming normal weather and unit operations in the remainder of the year. With that, we're now ready to take your questions. And I'll turn it back over to Nick to introduce the Q&A.

[Operator Instructions] Your first question is from Greg Gordon from ISI Group. Caroline D. Dorsa: We can go onto the next one. Greg can call in again.

Our next question is from Travis Miller from Morningstar. Travis Miller - Morningstar Inc., Research Division: I was wondering if you could talk a little bit about the coal to gas switching environment. And how much of this increase in coal and flat at least to gas gigawatt hours was related to economic switching? How much was just related to how the load distribution fell out?

So Travis, we'll team up on that one. Our New Jersey coal units need gas to be at about $5.50 to $6 to be dispatched on coal. So they, year-to-date, run probably 2/3 more often on gas than they have on coal. So that low teens capacity effect that you see for the year is probably running at 2:1 gas to coal for our Hudson and Mercer units. Having said that, our Keystone economy units have been dispatched quite a bit more this year than they were last year, given the slightly higher gas prices as compared to the 2012. But you'll recall, 2012, we had 0 winter, and gas, at one point, it was down to $1.90. So Caroline, did you want to supplement that? Caroline D. Dorsa: Right. And you recall, as we talked about in the first quarter, we had our units, Hudson and Mercer, running on both gas and coal. Mercer actually more on coal than gas. Hudson wasn't ready to run on coal, given the Superstorm Sandy-related remediations that were coming online in the first quarter. In this quarter, the units ran, but they ran entirely on gas, given those economics that Ralph just mentioned. So the good news for us is the ability to have those units, which are now available to run on coal, and of course, all the environmental spend already done. But having that inherent fuel flexibility to move between coal and gas has provided us with value as we look at those assets. Travis Miller - Morningstar Inc., Research Division: Was there any kind of weather impact year-over-year on that -- on your fleet, in terms of generation? Caroline D. Dorsa: No. Not second quarter in terms of generation. Remember, we talked about much stronger generation in the first quarter because we had a real winter this quarter as opposed to last year. Generation this quarter was essentially flat, a little more than 12 terawatt hours, as I mentioned on the remarks, versus last year's second quarter. So kind of pretty much normal in terms of how to think of quarter-over-quarter for this quarter.

Brandon Blossman from Tudor, Pickering. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Kind of a follow-up question on the New Jersey gas units, you'd mentioned, Ralph, in your prepared comments about taking advantage of less expensive Marcellus gas. And we've seen some pretty dramatically low pricing kind of day-to-day in the Marcellus at certain trading hubs. Are you able to take full advantage of that? And is there any kind of plan for kind of going forward to be able to maybe contract for some of that gas at below NYMEX prices?

Well, I'll let Caroline chime in on this one. Caroline D. Dorsa: Yes, so a good question. As we said, we are positioned to be able to access Marcellus gas. And we do access some of our gas through Marcellus, and obviously, we have some storage capability that enables us to do that. Then, of course, we bid the units into the market in the normal bidding process. So we're always looking for the best sources of gas relative to our units. We follow all the normal practices in terms of how we bid into the market in terms of how those units are compensated. Of course, that's a very competitive sort of situation, so I don't want to give too much detail here. But you're right to point out, we do have access to both sources of gas as we bid the units in. Brandon Blossman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. Helpful and very interesting as we go forward. And then, kind of as a follow-up, last couple of PJM, RPM auctions, we've seen some new build CCGTs clear. Do you guys have any insight on whether or not those get built and is the financing available for those projects?

So our focus has been primarily in the Eastern Max zone. And to the best of our knowledge, there is a new unit that is being built in Eastern Mac, owned and operated by LS Power consortium of companies. All indications are that it has proposal for a power plant, which is now calling to someone else, the northern PS Zone is moving ahead. There are 2 other plants that we know a little less about. And as a matter of fact, we believe that a plant that was proposed in the Somerville area is not going forward. That would have been in the Eastern Max zone as well. As a matter of fact, there was a filing made by PSE&G about -- with that developer regarding the terms and conditions of their standard offer contract agreement. And in fact, that developer agreed that they were no longer going to honor the conditions of that standard offer contract agreement. One other plant had cleared the auction last year and that one we simply have been told through public comments that it is at least a year delayed and -- but it's still intending to go forward. So everything I just told you is out in the public domain and it's the best information we have at this point.

Question comes from Gregg Orrill from Barclays. Gregg Orrill - Barclays Capital, Research Division: I was wondering if you could talk a little bit more about the process at the New Jersey BPU around the energy hardening program that you proposed. And when you'll be able to update us on more accurate CapEx forecast over the next few years versus the one that doesn't include elements of your proposed program?

Sure, Greg. So where things stand right now is Commissioner Fiordaliso has been named the hearing officer for the filing, the filing is complete, although we do keep getting some additional discovery questions and are responding to them. Hearing dates have been announced for September and October. Now what happens after that is a little bit flexible. We've proposed a schedule that would result in a fully litigated decision being the December 18 meeting of the BPU. Others are proposing a different schedule and Commissioner Fiordaliso hasn't ruled on that. We anticipate his ruling on the schedule to be imminent, less worried about the schedule because, as you know, we tend to try to move on this and other issues in the settlement route [ph], which is what we did with Solar and what we've done in prior infrastructure programs. So I still remain hopeful and optimistic that we'll have some things resolved by the end of the year. It's pretty clear we've missed taking any action for this storm season, that doesn't mean I'm expecting or hoping for any storms but quite the contrary. Our hope though is to be able to get things resolved by the end of the year so that we can begin the engineering and design work to get some infrastructure hardened prior to next year's storm season. And -- but we just don't have anything more definitive on that. Rest assured, Greg, we will tell you and everyone else everything we know as soon as we know it and as the BPU will release information. None of that has any impact on our plans to spend an additional $1.5 billion on transmission over that 10-year period, with about $500 million of that taking place over the first 5 years. Gregg Orrill - Barclays Capital, Research Division: Okay. And separately, on the insurance proceeds at Power, what are you expecting in terms of the timeline to get that recovered? And I guess, the comment on guidance? Caroline D. Dorsa: Sure. So this is Caroline, Greg. So relative to the insurance, as we mentioned, we had an additional $25 million recovered this quarter. So total recoveries under the insurance for Power, $44 million, and there's about $6 million for the utilities. So total recoveries for the company, about $50 million. In terms of timeline, we don't have a timeline for anything for future. As you know, we have filed litigation relative to the parties, the underwriters relative to coverage terms. And of course, since we are in litigation, we can't comment on the progress or status of litigation, and of course, that means that the timeline is really subject to the outcome of that litigation. What I can tell you is that we continue to make the repairs that we have discussed and we'll continue to report them on an actual basis as Power's O&M below for operating earnings purposes as we've updated this quarter. Just a reminder, that was $135 million for Power in the aggregate that was spent, and from that, you subtract the $44 million for recovery that we received from the insurance companies for a net $91 million. So can't forecast exactly how that will play out, given litigation. We will, of course, report it to you on an actual basis.

Question is from Michael Lapides from Goldman Sachs. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: Can you talk a little bit, when you look across the fleet and really look across not just your fleet, but the industry, kind of think about the competitive positioning of your company versus others. In terms of the economics for some of your coal units, whether it's Bridgeport up in Connecticut or even Hudson and Mercer over a long period of time, as well as there's been a lot of discussion about the economics of nuclear, of existing nuclear. And just kind of talk about what you're seeing and how it impacts your company, as well as how it impacts the industry as a whole?

Sure, Michael. So we've talked a bit about the dispatch curve, right, and the fuel flexibility we have and the technology flexibility we have. By and large, the nuclear units dispatched ahead, and except for that one, anomalous situation we had our base load coal is always called upon to run. But then the Bergen and Linden units swapped places with the Hudson and Mercer units for the past few years and who knows what the future will bring. So I feel good about the fuel and technology flexibility we have as it pertains to the dispatch curve. And I think, one obviously needs to consider any capital improvements that need to be made when thinking about the overall economics of plants, and really, that comes in 2 forms for all of us. One is just sort of Clean Air Act rule capital investments. And as you know, all of those are behind us with some SERs and as we put on our Conemaugh plant being the one exception. So we're in great shape from a HAPs-MACT compliance point of view, and you can expect us to continue to operate and run our plants based on just a marginal cost basis here because there is no additional sudden cost that needs to be made. The post-Fukushima drivers for the nuclear plants are still undetermined at this point. However, we do have quite a few changes -- differences in our plants that are different from the typical design of other units. For example, all of our spend fuel pools are behind concrete reinforced buildings. So we don't have butler buildings, stainless steel buildings that are protecting our spent fuel pools. We have different designs in our vents that we are going to argue before the NRC are already hardened. So we're in a good shape from a point of view CapEx going forward. As a matter of fact, we're still going ahead with Exelon and our Peach Bottom upgrade. We feel that strongly about the dispatchability and economics of our nuclear units. So I don't know what to say about others, they can speak for themselves, but I feel pretty good about the fleet that we have. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: Okay. And just maybe one for Caroline, an unrelated question. When you think about the lease exposure, the Edison Mission bankruptcy, how should investors quantify the potential risk to PSEG, whether it's from a tax perspective or kind of other perspective in terms of your being one of the lessors? Caroline D. Dorsa: Thanks, Michael. So relative to the lease exposure, we've talked about that, and of course, disclosed that for a pretty good amount of time in our financial statements. I think the way to think about it is when you look at the exposure amounts, typically think of that total exposure as we talked about, and for Edison Mission, it's about $220 million. Think of that as the pretax amount of the maximum amount of a write down, but also remember that, that's not cash, right? That's the write-down amount. We've talked about the cash exposure related to the taxes. But I think the -- one thing to keep in mind for this is this has been deferred again in terms of any decisions related to rejection of the lease until September. And we are obviously representatives for our share and our rights in that process. The deferral continues, which apparently is, obviously, from the lessors -- from the lessee's perspective on their decisions on what to do in that regard. In terms of the other leases that we have, they continue to be current on payments. Obviously, the Edison case is different, but that's why we're in this process right now. So if we think about the write-off exposure, it's that amount, as I mentioned, on a pretax basis, and then you put it on an after-tax basis. Michael J. Lapides - Goldman Sachs Group Inc., Research Division: And is the tax exposure -- I'm just trying to think about going back and thinking about leases and kind of back taxes and that type of stuff. Is the tax exposure, could it any way be more significant than the $220 million? Caroline D. Dorsa: No. The tax exposure is less than that. I can tell you that for sure. And then, of course, that would be process relative to our rights from the lessee in terms of any recapture.

Your next question is from Anthony Crowdell from Jefferies. Anthony C. Crowdell - Jefferies LLC, Research Division: A question on, I guess, the Energy Strong initiative. I think, your comments earlier, Ralph, you had said that you've kind of missed the window to maybe reinforce the system for this storm season. Is it the weak industrial load, and it looks like weak demand, maybe a headwind of getting a large project approved in the state?

No, I don't think so, Anthony. This is a big capital program. And the BPU staff understandably is doing a very thorough job of trying to assess, from their point of view, whether or not we prioritize things the way they think maximizes benefits for customers. Not surprisingly, the consumer advocate wants us to do it for free and that's kind of a tough thing for our shareholders to accept and for us to accept this measure. So really doesn't have anything to do with demand at all. As a matter of fact, all of our infrastructure programs, transmission, Energy Strong are completely decoupled from demand growth and really have much more to do with either a replacement of an aging infrastructure or the desire to move from best-in-class reliability, which truthfully say, we possess, to just greater resiliency. And in fact, probably no one has felt the damages associated with storms more so than our commercial and industrial sectors. Anthony C. Crowdell - Jefferies LLC, Research Division: When do you expect the, I guess, final decisional approval, is this, this calendar year? Or does it potentially carry over to '14?

Yes, I mean, we are hopeful and still confident that it will be this calendar year, but you never say never, so it could spill over into next calendar year, I just cannot imagine it spilling deeply over into next calendar year, if it were to do so.

Question is from Shahriar Pourreza from Citigroup. Shahriar Pourreza - Citigroup Inc, Research Division: Most of my questions have been answered, but maybe I could just ask a question on gas. Over the past several weeks, we've seen a negative basis with gas into east relative to the Henry Hub. How has this -- have you seen an impact with Power's hedges, especially if you hedge gas, which is tied to Henry Hub, and you've hedged the heat rates for Power on using eastern gas -- on eastern prices? Have you seen an impact in any of your hedges at Power?

Shahriar, we deliberately keep our load following in intermediate assets open, certainly out beyond the current year. We've seen tremendous volatility in basis, the $3 or $4 number that we see in the future has little bearing on the day-to-day or day ahead or real-time basis differential. And so we don't make a habit of hedging the fuel separating apart from the electric output. We match that. And from that point of view, sparks have been pretty robust and the basis has been pretty robust for us. And you've seen an effort 2 quarters in a row, right, for different reasons. And that's one of the themes we're trying to highlight in our discussions with investors and here on this call, that it goes to the question that Michael asked before, our competitive positioning is one of having good assets in good locations that could take advantage of the volatility in the market through our natural long position. And it's not just as simple as, okay, power prices at the western hub of $39 and PEG has got this amount of open position and let's multiply it by those 2 numbers. Caroline, chime in here as well. Caroline D. Dorsa: And one other thing to keep in mind, Shahriar, we've talked about this, as you may recall, earlier this year, when you look at and try to estimate approximate forward basis, you can get to some numbers that we see as well in the low single-digits, but when the demand has been there and there's been issues of congestion, you've seen that basis be higher in the closer to real time. And so by having the assets open in our positioning, we've been able to capture some of that volatility in basis. And we have a slide in some of our investor materials that talks about that in terms of seeing how volatile that basis has been, our ability to capture that volatility as we make our assets available is something else that our team is very focused on. Shahriar Pourreza - Citigroup Inc, Research Division: Got it. And then just maybe just one last question on that. If you get to a period where Marcellus just keeps producing and you don't really get a lot of gas being shipped from the Gulf in that basis of what you're seeing sort of expands because we've seen an expansion over the past several weeks. Is there a potential impact that you can see on Quarks and some of the nuclear economics, if you get to a period where the forward curves continue to trade at a discount?

Yes, I think that there's no denying that. I mean, clearly, our gas fleet will do better, but to the extent that overall prices come down and Quarks compress, then you'll see an impact on our nuclear fleet.

There are no further questions at this time. Please continue with your presentation or closing remarks.

Okay. Thank you, everyone, for joining us. So just to recap, another strong quarter, we believe. Power actually eked out a couple million dollar improvement over last year, which is a nice change in the trend line of Power. And utility, right on track with the double-digit earnings growth that we've talked about, largely driven by great progress on the transmission construction program. And looking longer term, we're pleased with the dialogue we have with BPU staff on the Energy Strong proposal. We're pleased with the dialogue we're having with folks over at LIPA on how we might be able to enhance that relationship even before it begins. And with that, well, we look forward to seeing many of you in several of the upcoming conferences that we'll be at in August and in September, so we'll see you in person very soon. Thanks, everyone. Caroline D. Dorsa: Thank you, operator.

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