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

Paul B. Fremont - Jefferies & Company, Inc., Research Division Julien Dumoulin-Smith - UBS Investment Bank, Research Division Ashar Khan Dan Eggers - Crédit Suisse AG, Research Division Paul Patterson - Glenrock Associates LLC Andrew Levi - Caris & Company, Inc., Research Division Stephen Byrd - Morgan Stanley, Research Division Travis Miller - Morningstar Inc., Research Division Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Greg Gordon - ISI Group Inc., Research Division

Ladies and gentlemen, thank you for standing by. My name would be Tamara, and I am your conference operator today. I would like to welcome everyone to today's conference call, Public Service Enterprise Group First Quarter 2013 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, April 30, 2013, and will be available for telephone replay beginning at 1 p.m. Eastern time today until 11:30 p.m. on May 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: Thank you, operator. Good morning. We appreciate your participation in our call this morning. As you are aware, we released our first quarter 2013 earnings statements earlier this morning. The release and attachments can be found on our website at www.pseg.com under the Investors section. We have also posted a series of slides that detail operating results by company for the quarter. Our 10-Q for the period ended March 31, 2013 is expected to be filed shortly. 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 the factors that may cause results to differ from management's projections, forecasts and expectations and for reconciliation of operating earnings to GAAP results. I'm now going 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 Chief Financial Officer. At the conclusion of their remarks, there will be time for your questions.

Thank you, Kathleen. Thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the first quarter of 2013 of $0.85 per share, which equaled the operating earnings from 2012's first quarter. We are very pleased with our results -- the current quarter's results compared to operating earnings in the year ago period, which benefited from IRS tax settlements at PSEG Energy Holdings and PSE&G by contributing $0.13 per share to consolidated operating earnings. We also achieved these strong results despite a decline in the average price of our hedged energy. The quarter's earnings demonstrate the locational value of PSEG Power's assets, which, along with the strong performance of PSEG Power's nuclear fleet and Power's open position on its intermediate and peaking generation, allowed us to take advantage of a favorable price environment in the energy marketplace, while managing downside risks through the hedges on our base load fleet. Our results also reflect the steady increase in the earnings contribution from PSE&G's capital investment in transmission. Mostly, the quarter's results are an affirmation of our focus on operational excellence and disciplined investment through maintenance of a strong balance sheet to meet the core objectives of our customers and shareholders for reliability and growth. The performance of Power's nuclear fleet was enhanced by record quarterly generation from the Salem station. An upgrade of the equipment and the design of the circulating water intake structure at Salem greatly aided its performance. Power also worked tirelessly to restore critical generating stations to operation in the aftermath of the damage created by Super Storm Sandy. The Linden gas-fired generating station was returned to service on January 11 and was available to meet the increasing demand during the winter months. The Hudson coal facility was also returned to service in January. However, given the dual fuel flexibility at Hudson, this station was able to run on gas until higher gas prices and demand favored its dispatch on coal. Regulatory recovery of PSE&G's investment in transmission under its FERC formula rates increased the earnings contribution from this critical enhancement to PSE&G's infrastructure. PSE&G's investment in transmission will help drive our forecast to double-digit growth in PSE&G's operating earnings in 2013. PSE&G is expected to invest $3.4 billion in transmission from 2013 through 2015. This investment will increase transmission as a percent of PSE&G's rate base to approximately 40% and continues to drive our expectations for double-digit earnings growth at PSE&G over this multi-year period. We benefited from excellent operating performance and an increase in our capital investment this quarter. But as focused as we are on meeting our short-term goals, we are equally committed to delivering on the long-term promise associated with our proposed 10-year $3.9 billion Energy Strong distribution investment program. This program, along with plans to invest $1.5 billion to harden our transmission system over the same period, is a natural extension of our strategy to maintain PSE&G as one of the nation's most reliable utilities. We are seeking approval from the New Jersey Board of Public Utilities for the initial 5-year distribution-related capital program associated with Energy Strong, which would occur during a period of time when some major changes on the customer electric bill are scheduled to expire. On a separate matter, we have reached an agreement with the staff of the New Jersey BPU and certain other parties on our quest to expand our investment in Solar under the Solar Loan and Solar 4 All programs. The BPU is expected to act on the agreement at its meeting on May 29 and issue a final order on May 31. We believe the agreement recognizes the importance of the solar industry to New Jersey and will allow the BPU to focus on our infrastructure filing to make New Jersey Energy Strong. In the meantime, we are responding to the BPU staff's request for additional information on our Energy Strong proposal. We can't provide you with a schedule, but 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. Our financial condition is strong. This was recently affirmed by Standard & Poor's upgrade of the credit ratings for each of PSEG's principal subsidiary companies, as well as the company's consolidated credit worthiness. The upgrade is an endorsement of the strategy we have been focused on, which allows us to leverage the strength of our balance sheet to invest primarily in our stable and regulated business in ways that meet customer needs and state goals, as we protect the upside of the merchant business and provide growth for our shareholders. We remain on track to meet our objectives for full year 2013 operating earnings of $2.25 to $2.50 per share. Our success, as always, is driven by the hard work and dedication of our employees and was amply demonstrated in the first quarter's operating results. With that, I'll turn the call over to Caroline who will discuss our financials in greater detail. Caroline D. Dorsa: Thank you, Ralph, and good morning, everyone. As Ralph said, PSEG reported operating earnings for the first quarter of 2013 of $0.85 per share, equaled to operating earnings of $0.85 per share in last year's first quarter. We provide you with a reconciliation of operating earnings to income from continuing operations and net income for the quarter on Slide 4. And as you can see on Slide 8, PSEG Power provided the largest contribution to earnings. For the quarter, Power reported operating earnings of $0.49 per share compared with $0.39 per share last year. PSE&G reported operating earnings of $0.35 per share compared with $0.39 per share last year. And Energy Holdings and Parent together contributed operating earnings of $0.01 per share compared with operating earnings of $0.07 per share during the first quarter of 2012. We've provided you with a waterfall chart on Slide 9 to take you through the net changes in quarter-over-quarter operating earnings by major business. And I'll now review each company in more detail, starting with Power. PSEG Power reported operating earnings of $0.49 per share for the first quarter compared with operating earnings of $0.39 per share for the first quarter last year. Power's first quarter operating earnings benefited from strong market prices for energy, higher capacity prices and an increase in output. Normal winter weather conditions experienced this year compared to the abnormally mild weather conditions you'll recall in the year-ago quarter, higher market prices for natural gas and market volatility all contributed to stronger energy prices during the quarter in Power's primary PJM market. The improvement in wholesale market pricing quarter-over-quarter offset the impact of an approximately $10 per megawatt hour decline in average contract prices on energy hedged through the Basic Generation Service contract, or BGS, as well as other wholesale contracts. As a result, we saw a net increase in earnings quarter-over-quarter attributable to price of $0.02 per share. An increase in capacity prices on June 1 of 2012 to $153 per megawatt day from the $110 per megawatt day price in the first half of 2012 improved Power's quarter-over-quarter earnings by $0.05 per share. Power's output increased 7.7% during the quarter, as a result of the higher market prices for energy and more favorable weather. The increase in generation added $0.02 per share to earnings quarter-over-quarter. The improvement in pricing and output together led to a $2 per megawatt hour increase in Power's gross margin in the quarter to approximately $48 per megawatt hour. The weather experienced in the first quarter also had a favorable impact on off-system gas sales. The increase in send-out also aided recovery of the fixed expenses associated with Power's gas supply and storage operations. These 2 items together improved quarter-over-quarter earnings by $0.04 per share. The improvement in revenue and margin was somewhat offset in the quarter by an increase in operating and maintenance expense, exclusive of storm-related activity, which I'll mention later, and other items which reduced earnings by $0.02 per share. Higher depreciation expense related to the placing in service of the new peaking capacity and low-pressure turbines at the Peach Bottom nuclear station reduced earnings by $0.01 per share. During the quarter, the nuclear fleet operated at full capacity, slightly in excess of its rated capacity or 101% and provided 57% of Power's output. The fleet's performance was enhanced by the absence of any forced outages and record first quarter generation from the Salem station. The economics of operating Power's coal units on coal improved in the first quarter. Performance was supported by an increase in demand associated with more normal weather conditions and higher gas prices than experienced last year. Generation from Power's coal fleet nearly doubled from the year-ago quarter and provided approximately 16% of Power's output. The increase in output was experienced at all of our coal stations, with the largest improvement at our New Jersey and Connecticut-based coal units, which operated on a very limited basis in the year-ago quarter. Although the dispatch economics of the coal fleet have improved with higher gas prices, gas prices have not reached the level necessary to sustain the dispatch of fully-scrubbed coal ahead of our gas-fired combined cycle fleet. Power's gas-fired combined cycle fleet operated at an average capacity factor in the quarter of 52% compared to 56% in the year-ago quarter. Output at the Linden facility continued to be affected early in the quarter by repair activity in the aftermath of Super Storm Sandy. The station was returned to service in January. The Bergen station, which was not affected by the storm, operated at an average capacity factor of 56% in the first quarter versus 53% in the year-ago period. Slide 16 outlines Power's hedge profile through 2015. Power continues to forecast output for 2013 of 53 to 55 terawatt hours. Output for the remainder of this year is approximately 70% to 75% hedged at an average price of $50 per megawatt hour. For 2014, output is forecast also at 53 to 55 terawatt hours and is approximately 50% to 55% hedged at an average price of $50 per megawatt hour. Power has hedged 25% to 30% of its forecast generation in 2015 of 52 to 54 terawatt hours in total at an average price of $50 per megawatt hour. The results include the impact of the February 2013 auction of BGS load in New Jersey. A price of $92 per megawatt hour for the 3 years beginning on June 1, 2013 will replace the expiring contract for approximately $96 per megawatt hour. Our assumption on the percentage of output hedged and the price of the output continue to reflect BGS volumes of approximately 12 terawatt hours in 2013 and approximately 10 terawatt hours in 2014. The percentage of generation hedged reflect the expectations for the full year across a portfolio of assets consisting of base load, intermediate and peaking capacity. As you can see in Slide 16, our low-cost base load generation is more fully hedged in any 1 year with our intermediate and peaking facilities more open to the market. This practice -- this profile is very consistent with our practice, and we believe it reduces Power's downside risk, recognizes the need to meet the full load requirements of the BGS contract during the important summer months and minimizes the potential risk of a unit not being available during critical periods. It also provides the opportunity for Power to optimize the portfolio under the right set of market conditions as we did in the first quarter. The forecast of Power's operating earnings for 2013 remains unchanged at $535 million to $600 million. Results for the remainder of the year will continue to be influenced by a decline in the average price of our hedges of approximately $10 per megawatt hour and higher capacity prices. Remember that the average price for Power's capacity in PJM is scheduled to increase to $244 per megawatt day on June 1 of 2013 from $153 per megawatt day. We also want to point out that Power's full year expectations reflect the impact of an increase in O&M during the second half of the year associated with plans for the Bethlehem, New York and Bergen-combined cycle facilities, which undergo major maintenance programs as part of normal plant maintenance cycles. This will increase O&M expense for the year above what was incurred during the second half of 2012 and above the expected trend for O&M growth over the long term, but all of this is consistent with and baked into our guidance. The forecast for Power's operating earnings, as we have indicated, doesn't include the cost associated with storm-related repair. Power expensed approximately $28 million, pretax, on storm recovery activity in the first quarter of 2013, bringing total pre-tax storm-related expenditures to $113 million. And of this amount, Power has received initial insurance proceeds of $19 million in the fourth quarter of 2012 to return its facilities to service. Let's now turn to PSE&G. For PSE&G, as shown on Slide 19, we reported operating earnings for the first quarter of 2013 of $0.35 per share compared with $0.39 per share for the first quarter of 2012. PSE&G's first quarter results reflect the absence of $0.06 per share in tax settlement in the year-ago quarter, which more than offset the contribution to earnings in the quarter from PSE&G's increased level of transmission investment. As we mentioned in February, the Federal Energy Regulatory Commission, or FERC, authorized PSE&G's request for an annual increase in transmission revenue under our formula rate filing. The increase in revenue, which was effective on January 1 of 2013, supported a quarter-over-quarter increase in the net bottom line earnings contribution from transmission of $0.03 per share. Electric and gas demand in the quarter was influenced by weather, which was close to normal, but significantly colder than a year ago. And the favorable weather comparison added $0.02 per share to earnings. An increase in distribution-related operation maintenance expense quarter-over-quarter was influenced in part by storm-related repair, but more significantly by normal weather. PSE&G focused on O&M-related work in the quarter, as opposed to a year ago when the abnormally mild weather conditions supported an acceleration of capital-related work. The increase in distribution O&M reduced quarter-over-quarter earnings by $0.02 per share. And an increase in depreciation expense and other miscellaneous items reduced earnings quarter-over-quarter by $0.01 per share. Electric and gas sales grew in the quarter at a rate of 0.9% and 23%, respectively, given the more normal weather conditions versus 2012. We estimate weather-normalized electric sales declined by about 2% in the first quarter from year-ago levels, as weather-normalized gas deliveries increased by about 0.6% quarter-over-quarter. As Ralph mentioned, PSE&G has reached an agreement on its proposed Solar capital investment programs. Under the agreement, PSE&G will invest up to $199 million on 97.5 megawatts of new solar as part of the Solar Loan III program. The agreement also provides for PSE&G to invest approximately $247 million to develop 45 megawatts of new solar capacity with 42 megawatts of this amount developed on landfills and brownfield sites as part of the Solar 4 All extension program. The agreement represents approximately 50% of PSE&G's original request to invest up to $883 million on the 2 programs and provides for a return on equity of 10%. This capital investment is expected to occur over a 3-year period of time instead of the 5-year program we initially proposed. And keep in mind, if approved, this investment of up to $446 million is incremental to the base spending of $4.9 billion for 2013 to 2015 that we discussed on March 1 and appears on our 10-K for PSE&G. The settlement, which is for a 3-year period, provides for essentially the same amount of spending over the 2013 to 2015 period, as we included in our upside case on March 1 for solar. So this continues to support a potential 12% compound annualized growth rate in rate base through 2015 if you include all of our new programs. We're maintaining our forecast for double-digit growth in PSE&G's operating earnings of $580 million to $635 million. Results for the full year will continue to be influenced by growth in the earnings contribution from PSE&G's investment in transmission. And our forecast also assumes that the full year growth rate for distribution-related O&M will be lower than the rate of growth seen during the first quarter, as we don't assume a similar level of storm-related repair work as we experienced at the end of 2012. I'm sure you'll recall that Super Storm Sandy-related repair work reduced earnings by $0.05 per share during the 2012 fourth quarter. Let me now turn to Energy Holdings and Enterprise. Energy Holdings and the Parent together reported operating earnings of $4 million or $0.01 per share compared with operating earnings of $39 million or $0.07 per share during the first quarter of 2012. The results for Holding and Enterprise aren't really a surprise. If you recall, operating earnings for the first quarter reflect the absence of the $0.07 per share tax benefits received in the first quarter of 2012 related to the settlement of the 10 years of IRS tax audits. We're maintaining our estimate of full year operating earnings for PSEG Energy Holdings and Parent at $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 of 40 megawatts, which entered service in the fourth quarter of 2012, as well as the forecast commercial operation of a 19-megawatt solar facility located in Arizona, which is expected to enter service in the fourth quarter at a cost of approximately $50 million. We're very pleased with S&P's recognition of the strength of our balance sheet and the balance provided by the mix of growth and stability incorporated in PSEG's financial strategy. S&P raised its corporate credit ratings on PSEG, PSE&G and PSEG Power to BBB+ from BBB. And the rating on PSE&G's senior secured debt was raised to A from A-. And the rating on all 3 issuers is stable. As we said, we can finance our capital program without the need to issue equity, given the strength of Power's cash flow and our already strong balance sheet. At the end of March 2013, debt represented 41% of our consolidated capital, and we ended the quarter with $420 million in cash. Overall, we continue to forecast operating earnings for the full year of $2.25 to $2.50 per share. That concludes my comments. And I'll now turn the call back over to the operator to open the line for questions. Operator, thank you.

[Operator Instructions] Your first question is from the line of Paul Fremont of Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: I guess, the first question I have is, why did the New Jersey BPU believe that your Energy Strong filing was incomplete? And I guess, what should we assume as the timeframe where you would, I guess, resubmit a more detailed plan?

Paul, hello, it's Ralph. Obviously, you can tell my voice from Caroline’s. We put something in that we believe makes a lot of sense in the point of view of the number of customers that would be affected in a future storm. Over 800,000 fuel would be out. But what the Board is now probing more deeply into, which makes perfect sense, is given the vast size of the program, $3.9 billion over 10 years, with the lines -- with half of that in the first 5 -- a little bit more than half in the first 5, what's the cost benefit associated with each aspect of the program. So they're asking more detailed questions about, "Okay. What does it cost to harden a substation versus to underground certain lines? What is the cost benefit associated with enhancing the SCADA systems on the distribution network versus raising some of the inside plant in the substations." So it's a fair set of questions from the Board staff. We received them -- I think, it was about April 15. And last I checked with Ralph LaRossa, he was reading the draft final response to them yesterday, and we expect them to go back to the Board staff sometime this week. So I view this as normal course of business and prudent regulatory due diligence by the Board staff, and we're ready to answer, as I said, this week their questions. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And then, my follow-up question would be, interveners seemed to have reacted negatively to the tracker clause recovery mechanism part of your proposal. Would the company consider moving forward without that as part of your Energy Strong program?

So let me break that question into 2 pieces because I respectfully will disagree with the characterization of interveners broadly defined, some interveners have. But we have 37 towns and counties that have passed resolutions supporting this. We have countless number of unions and trade associations supporting this. We have the New Jersey Chamber of Commerce supporting this. We have regular letters to the editors supporting this. We have over 5,000 people, who are a blend of employees and customers, who've signed up on our advocacy site who realized the cost of losing power, far and away, exceeds the cost of doing this. Now having said that, a microcosm of interveners have said, "Yes, we don't want this to be done during a tracker -- using a tracker." But let me be very clear. We will not do this without a tracker. These are extraordinary investments, taking the most reliable electric utility in the nation to a higher level of reliability, and we're not doing this with retroactive rate making.

Your next question is from the line of Julien Dumoulin-Smith with UBS. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: First question. On the Power side, could you just talk to what drove the positive basis in the quarter, just the various factors and the sustainability of those factors, if you wouldn't mind?

Sure, Julien. It seems to be largely the changing gas dynamics in the marketplace. So as there’s an increased build of gas gathering and transportation infrastructure, some of that volatility will be diminished in the future. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: So then, what would you expect going forward, just to be clear, because I know there's been a lot of different projects, some of which are going to bring gas to your neck of the woods?

I'll let Caroline respond, but we would expect $2.25 to $2.50 a share this year. Caroline D. Dorsa: In terms of basis, Julien, we don't forecast that. And for sure, we don't see basis levels on a continuing basis the way we saw them years ago. We're still looking at single-digit type bases. But I think the important thing to recognize, as Ralph was mentioning, is when we've seen demand and when we've seen higher prices and when we've seen the weather that we saw, you see basis spike up. And because we're not 100% hedged, we get to take advantage of that, and that's what we did in the first quarter. So long term, similar lower levels like we've talked about before. But when there's spikes, we see them in our region, the locational value is still there and because of the way we operate the units, as you know, and how we sell them in, we try to take advantage of that as much as possible. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: So -- and perhaps, a quick clarification or follow-up, does this relate at all to some of the dynamics that are going on in New England and the very high gas prices we're seeing there? Is there any kind of export opportunity, should we say?

No, I wouldn't see that at all. I mean, at a -- at an 80,000-foot level, it relates to the rise and dominance of natural gas and the infrastructure being a little bit lagging in terms of the dominance. But I wouldn't go any more specific than that. Julien Dumoulin-Smith - UBS Investment Bank, Research Division: Great. And back on the Utility, if you don't mind, again, I appreciate that it's sort of dynamic right now. But at the end of the day what kind of timeframe are we talking to getting across the finish line on some sort of approval for Energy Strong? I mean, what is kind of the timeline from now, if you will?

We don't have a schedule, Julien. But I mean -- yes, there was a 6 month anniversary of Sandy. The Board staff turned around their questions very quickly, and they did that in, I think, 10 or 15 days. Our response was very quick, 15 days. I'll simply say that I would be disappointed if we didn't have something by the end of the year. And I know everyone is working real hard to do something in the fourth quarter timeframe. But it's a complicated set of issues, and -- but one that there's been no diminishing of recognition of the importance of it. In fact, I think it grows with every passing day.

Your next response is from the line of Ashar Khan of Visium.

Can I just -- so one thing isn't clear from the remarks, if I heard them correctly, that positive basis in the first quarter was not anticipated and hence, the Power's good results were better than expectation for the first quarter. Is that a fair commentary?

No, Ashar, I think, maybe you misunderstood. But could you just repeat what you said in the beginning? Was it certainly about congratulations on a good quarter or something like that? Yes, the -- look, if we go back to ancient history of about 36 months ago, you would see basis numbers of about $10 to $20. And if you look at more recent history, you'd see consistent basis numbers of about $3 or $4. And we just had higher basis than that low-single digit numbers in the first quarter driven by a myriad of factors. And I think what Caroline was saying is that our locational advantages remained, we always have some power plants opened and we're never 100% hedged to take advantage of those occasional spiked increases in basis whenever you get these kind of dislocations in gas deliverability.

Okay. I understand, Ralph. But could you just -- give us a little bit more of what the basis has been in January, February, March? And I don't know if there's any data for April?

No, I was about to, and then, like, 3 people sat on my head and said, "No." I'm not allowed to do that. So, no, we won't -- we don't give the specifics on the basis. It's competitive information.

Your next question is from the line of Dan Eggers of Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just on -- congratulations on getting the Solar settlement done. I was wondering if you guys could kind of share the -- kind of where the conversation went, kind of to the scale or to the size you guys ended up with and then accelerating the timeline both what it means to maybe the future of Solar New Jersey. And then, is there a cost or a rate threshold that you're finding amongst interveners that could potentially be reflective in the Energy Strong project?

Sure, Dan. It's Ralph. Those are -- that's a series of excellent questions that I'll try to do just -- do justice in a brief response. So remember, we filed Solar in July of last year, and then we had a major event that occurred just 3 months later in the form of Sandy. So one of the things I think we and the Board are always mindful of is what are the rate effects of investments and what are the benefits associated with those investments. In the case of Solar, we've never ever shied away from the fact that Solar is not the competitive cost alternative for energy supply. This is an industry that we believe has a future. The state Energy Master Plan says it believes it has a future, and we're constantly struggling with how do you nurture it in its infancy to bring about that hope for and successful future. So given some of the promises made by panel manufacturers and people who are prominent in the industry about how the cost curve continues to decline, I think, the Board really said, "Look, in light of the other investments we need to make, does it make sense to have a 5-year program where the regulated utility is a big participant. Let's look out 3 years and let's keep this going in those market segments, where the market clearly is shying away from, that being landfills and brownfields." So you have an investment rate on the settlement that matches the investment rate that was anticipated in the original program, but over a shorter time period. And that seems fair and reasonable to us. And I guess, the best demonstration that the settlement seems fair and reasonable is that the people who didn't sign on have 1 of 2 opinions, either the program is not big enough or the program is too big, which suggests that the Board and we -- and those who did sign on have had a reasonable compromise on it. So I do think you have a situation where we have an ongoing industry that people have confidence in and believe in, but has not achieved the kind of competitive level that it needs to from the point of view of price competition. And then, you have a recognition that given the changing weather patterns of the last 18 months, has really driven home 4 months after the Solar filing that something more needs to be done in terms of grid resiliency and then that has kind of dominated the regulatory landscape since the Solar filing was done. Dan Eggers - Crédit Suisse AG, Research Division: Do you think this is just a prioritization of capital, so you don't think it's a reflection that there's more resistance to another meaningful but important CapEx program in the industry [ph]?

No, I -- yes, I think that's correct. I think that there's just a recognition that you cannot have 3 to 4, and depending on how you count, weather events in the last 18 months knocking out millions of customers, and that's where capital needs to flow first and foremost. I do think, over the long term, and the long term is beyond 3 years, that you will see increased scrutiny to the level of subsidization needed to renewable technologies. I mean, that's just -- I think, it cannot continue in perpetuity. Dan Eggers - Crédit Suisse AG, Research Division: And I guess, changing topics. On Salem's better performance with the mechanical fixes, should we be thinking about you -- kind of a sustained higher utilization rate effectively for the nuclear fleet going forward with these fixes in place? Or is it just a bit of a seasonal benefit to workflow when the weather is cold?

Well, so this -- it is a seasonal benefit insofar as this was the season when we had our biggest problems. The units, I think, are running, if you take out the last quarter, at 91.3% or thereabouts. If you just put in 18-month refueling outages that last 25 days, we may be having additional forced loss rate of anywhere from 1% to 3%. So I hope none of the folks at the nuclear fleet are listening to me say this, but I don't know how much harder I can push them. But we're constantly seeking they continuously improve. I just don't know how much more upside you can expect out of it. Is it -- the 101% capacity factor is a pretty darn good performance there.

And the next question is from Paul Patterson of Glenrock Associates. Paul Patterson - Glenrock Associates LLC: Just to sort of follow back up on Energy Strong -- and it makes a lot of sense what you're saying in terms of the tracker and what have you. Just sort of wondering though, I mean, if -- you mentioned retroactive rate making, which I generally think of being not really legally possible in most jurisdictions. I mean, if for some reason, you were required to engage in a major CapEx program, let's say, outside of Energy Strong, is there some particular retroactive rate making risk or something we should be thinking about?

No, no. So, Paul, I'm glad you asked that question because I used the word retroactive in the Merriam-Webster's dictionary sense of the word. You are seizing upon it in a term of art that is used in our industry whereby people go back and change rates that were previously approved. That's not what I'm talking about here. I'm talking about traditional rate setting where we would deploy hundreds of millions of dollars in capital. And after watching our returns collapse, we go in and seek rate increases subject to prudency review. And what we've said consistently is that PSE&G for the last 11 years in a row was the most reliable electric utility in the mid-Atlantic region, 5 out of the last 8 years is the most reliable in the country by 1 set of measures, and we cannot put forward a $4 billion capital program to take what is arguably one of the most, if not the most, reliable utility in the nation up to a higher level and then later on ask whether or not that was prudently incurred. These are extraordinary investments that we believe are necessary and our customers are demanding but we're going to get approval upfront for that, and we're going to understand the way, in which we are going to get compensated upfront for doing that. What I mean by we'll get paid upfront, that means we'll get paid over the next 40 and 50 years over the depreciable lives of the assets at a fair return. But we're not going to do it with the kind of regulatory lag that is typical of traditional rates. Paul Patterson - Glenrock Associates LLC: Okay. And then, just a follow-up on what -- I think you guys indicated that you hope to have a decision by the fourth quarter, is that the sort of the timeframe we should be thinking about when there might be an actual decision coming out of the commission?

Well, yes. I said it -- I said 2 things. I said, number one, we don't have a schedule. And, number two, I said that we would be disappointed if we didn't have something by the end of the year. I mean, no one wants to have another major storm, whether it's this summer or next summer, and then have to answer the question, "What did you do about it, and the answer be, "Nothing." Paul Patterson - Glenrock Associates LLC: Okay. And just really quickly, the 2% decline in electric sales, is that got to do with leap year? And it just seems like there's a big difference between gas usage, weather adjusted and electric usage, is there some sort of strange thing happening there, or just any quick thought on that? Caroline D. Dorsa: Yes. So -- sure, Paul. It's Caroline. No, it's nothing to do with leap year. We don't make any of those kinds of adjustments. I think what you see in the weather normalization, which as Ralph has always said, is more art than science. So it's not a terrific economy in the state right now. I mean, we struggle like many other states, so economic growth has been a little bit weak. And of course, there is some energy conservation underway. We think those are more of the driving factors, nothing related to calendar-like events. Nothing like that. Paul Patterson - Glenrock Associates LLC: So the fact that we had 1 day left this quarter did not lower -- the 2% takes that into account? In other words, without that, if you didn't have that – it takes into account the fact that we have 1 year less in this quarter, is that correct? Caroline D. Dorsa: It takes a look at the total over the prior quarter. So whether there's any adjustment for that, I don't know. That's the minimus. I think the fundamental driving factors are some of the economic challenges in energy conservation, which is in fact what we've been saying in prior quarters. So this is really consistent with how we've talked about some of the weather normalization in prior quarters. But again, weather normalization is obviously a difficult thing to know with any certainty. But I would not attribute it to a leap day.

Your next question is from the line of Andy Levi of Avon Capital. Andrew Levi - Caris & Company, Inc., Research Division: Just on Energy Strong, just a couple of more questions on that. Could you maybe just discuss kind of where Governor Christie's position is on this given his desire to have lower energy prices in New Jersey? And then, just also, I guess, last week, there was a budget committee hearing at the assembly, where Chairman Hannah discussed Energy Strong and his concerns that, I guess, there would be an 8% increase. So I'm just trying to politically find out, kind of, what's going on.

Sure, Andy. So I -- obviously, I can't speak for the governor. What I can paraphrase, because I don't remember the exact words, were some of these early comments that were quoted in the press, which was "Clearly, we need to do something, but I am counting on the BPU to take a careful look at the cost and benefits associated with this." And that I think is as best a response as we can expect from a governor who's dealing with everything from pension reform to education reform to a whole host of other issues to trust this agency to do the work. With respect to President Hannah, I can't -- we're struggling a little bit to tie to the exact 8% number that he put out there. I'm sure there's a sound basis for it. But the confusion tends to stem from the fact that we had some charges rolling off the distribution bill over the next 3 years. And depending upon the customer class you fall into, those charges can be as low as 4% to as high as 14%. And the average residential bill would come down by about 8.7%, than they would be under the current bill. So if you do our program, you don't see that rolling off of the charge showing up in your bill. You see it being offset by the increase to our program. So we, of course, say your bill will be flat. Others say, "No, no, no. They're increasing your bill by 6% to 8% and then they're just going to chew up the discount. Well, That's true. But I'd rather use less derogatory terms and say that what we're trying to do is save 800,000 customers from losing power in another Sandy-like event. And this is the right time to do it. We've got an improvement in our credit rating. We're borrowing money at 30 years for 3.65%. We have labor available, and we have some charges from restructuring that are rolling off. So no one is saying things that are inaccurate. It's just you need to be careful about how you are rolling off of charges and the layering in of increases that would ever come from this program. Andrew Levi - Caris & Company, Inc., Research Division: And so, we shouldn't be concerned that based on his testimony last week that the president may have some issues with Energy Strong?

No, I think the president will give very, very careful scrutiny to the cost and benefits associated with what we're doing. And I've got a lot of confidence in our team proposing things that make sense to do. I don't -- again, I can't speak for President Hannah. I don't think you should conclude that he is doesn’t think anything needs to be done or that we should put capital at risk without knowing how we're going to get compensated for it.

The next question is from the line of Stephen Byrd of Morgan Stanley. Stephen Byrd - Morgan Stanley, Research Division: I wondered if you could just talk a little bit about the coal dynamics you see. You’ve used a number of different types of coals. Wondering if you're seeing any trends broadly in terms of coal pricing, types of coal that's being consumed, changes over time. Just curious what you're seeing on the coal side of things.

So while Caroline digs out some of those numbers, Stephen, out, you forgot to mention, "Congratulations on the first quarter." But what we've seen generally speaking is that our fuel flexibility in terms of the Hudson and Mercer stations being able to switch has been a big plus for us right now. And we do tend to run them on gas whenever it's $5 or less. But when we've seen some of the spikes in prices that we saw in the first quarter, we did run on coal fairly extensively. I think, probably about half the time, those units ran on coal. But, Caroline, you may want to talk about it. Caroline D. Dorsa: Sure. So -- yes, absolutely, Stephen. And just as Ralph said, so we did have the New Jersey coal units running on coal a little bit more than half the time. And in fact, the Mercer unit ran on coal almost all of the time. Hudson, a little less so, just as it was getting through some Sandy-related repairs. So we have seen the economics and the coal dynamics improve in terms of the ability to run coal, particularly as the prices moved up and gas prices moved up in the winter period. But as we said earlier, as I mentioned in my remarks, we're still not at the point for gas prices where you're seeing our coal with all of the scrubbing that we have from the back-end technologies dispatch ahead of the gas-fired units. That would be more like gas prices of about $5.50 and we're not there, as you well know. But in those periods, where we've had an increased demand, higher near-term prices, higher near-term power prices, the coal units have dispatched and nicely in terms of dispatching on coal. Now of course, Bridgeport Harbor doesn't run on gas. It only runs on coal. And that was running, as we mentioned and as I think you saw in the attachment, that was running more as well. Also, keep in mind, of course, the Pennsylvania units only run on coal, and they were running well. In terms of the types of coal -- now this is news -- this is not news, these are things that I'm sure you know. Once we finished the back-end technologies at Hudson, it no longer had to run on Adaro coal, so it's running on tap [ph] coal, so that's cheaper. Bridgeport Harbor only runs on Adaro, as you know, that continues as we had always had it. Keep in mind, about 2 years ago, we changed that contract. So it no longer has volume requirements for us to build. And then, Mercer, after its back-end technology, still runs on net coal but a less expensive net coal than prior. So through our back-end technologies, we've reduced that really -- the kinds of coal in terms of cost that we need at those facilities, Bridgeport Harbor being the exception. And then, if these market dynamics have come back, we've been pleased to see those units run on coal. We're still very well hedged with coal in terms of what we have in inventory, but it's nice to see that coal being burned. So I think we're in a pretty good position, again, not yet for coal dispatching ahead of gas, but obviously our back-end technologies were done sooner than others, who may have to do that in the future as they make decisions about their units. Stephen Byrd - Morgan Stanley, Research Division: Okay. And just a follow-up on LIPA. I'm just curious if there's any developments there, any evolution of your thinking regarding LIPA.

Yes, Stephen. So 90% of our efforts right now, in terms of personnel, are getting ready for the contract that goes into effect on January 1 of next year. However, we have been approached by the state to have a broader and more expanded role, and we are in conversations with them on what that might look like. But it would be premature to say anything more specific than that at this point.

The next question is from the line of Travis Miller of Morningstar. Travis Miller - Morningstar Inc., Research Division: I wanted to keep going on the utility here. If we ignore the Energy Strong program and look at just core distribution, how are you thinking about -- or seeing the next distribution rate case on a base level? And particularly, as they’re recovering some of those Sandy costs.

Oh, okay. So 2 different things there, Travis. In terms of base rate case, what we've said is that we don't see it in the next 3 years in terms of our kind of expectations for capital deployment and now projections of O&M increases and where demand is going. Now what the Board has initiated is a separate proceeding for all of the utilities, as they pertain to recovery of already incurred expenses associated with Irene and Sandy. And we've deferred about $242 million, I believe, which would be part of that proceeding. But we are in the very early stages of that generic proceeding at this point in time.

The next question is from the line of Neel Mitra of Tudor, Pickering. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: A follow-up on Stephen's question with, kind of, the coal costs and what it takes to switch back to coal. So you put out, I guess, a number of really neat $5.50 gas, and what's driving that? What are some of the levers that you can pull? Could you turn off some of the scrubbers or the back-end equipment to lower operating costs? Could you renegotiate some of the cap [ph] coal contracts? Is -- I mean, is $5.50 something that you think is the long-term price that we need to see switching, or could it come down? Caroline D. Dorsa: So -- sure. So I think the fundamental way to think about this, Neel, is it can move around. But $5.50 and it's been that number for a while we've talked about as the cost where -- the gas price where we would see based on our units, the back-end technologies and their heat rate, they would dispatch ahead of combined cycle. Remember, that would be different depending on your region, but also different depending on your unit. And our units have the back-end technologies that have been in service for a while now. We can't run them without that. We -- that's our commitment, is we only really run the coal. We run the back-end technology. And they had incremental marginal costs that come with running the BET for the inputs that we use for scrubbing. So therefore, they’re marginally factored into the price. That's the fundamental thing that drives the differential. My comment earlier on something to keep in mind, if you think about that price, and it might sound different from other coal units in terms of what their cost would be relative to switching and dispatching ahead of gas. 2 factors to keep in mind: One, of course, every region is different. But also, we've completed all of our back-end technologies to be in compliance with the upcoming naturals and not every one else has done that. So think of us as a little bit sort of a bellwether of where economics for coal would move directionally, not perfectly, but directionally as others make the remediations that they might need.

And, Neel, just to add, this may sound a little strange, so while we have limited flexibility on our variable costs, we have worked hard to manage our fixed cost. And I said that specifically the way I did even though one would normally not assume that the fixed can be variabilized and the variabilized can't -- have to stay fixed. And what we do is we basically take our plant personnel and move them to other outages, specifically in our nuclear fleets, when we see -- when we anticipate protracted periods of no operation at the coal units. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Got it. Great. As a follow-up on the utility, Ralph, you mentioned that you wouldn’t go through with Energy Strong without a tracker, how would you approach a compromise where you could possibly maybe go in for a base rate case, which, in this environment, could maybe lower your ROE and get approval for the spending in replacement of the tracker?

Yes. Neel, I'd rather not get into a telephonic negotiation with the BPU on what's the best way to implement Energy Strong. So I mean, I think we would be open to any kind of discussion that protected our investors, while we deliver the value that customers are begging us to deliver.

The next question is from Greg Gordon of ISI Group. Greg Gordon - ISI Group Inc., Research Division: Quick question. What's the schedule -- the comparable schedule or expected timeline at the FERC to get validation of your desire to spend more in storm hardening on transmission?

So that would just be rolled into our annual formula rate treatment, Greg. That would not be any special rate case or any special event. Greg Gordon - ISI Group Inc., Research Division: So you don't have to get a formal approval from any regulatory agency to decide to spend more?

No. Remember most of that -- most, if not all, of that $1.5 billion was what we call kind of the business-as-usual or I forget -- the no-harm at PJM. So once PJM says, "Okay, if you think that makes sense, as that's not part of the RTEP, go ahead with it." Then we just file it on an annual basis in our formula rate treatment. Greg Gordon - ISI Group Inc., Research Division: Okay. So PJM then is the critical path?

Yes, but it's not the path that includes inclusion in RTEP. It's a different path. These are smaller projects, mostly internal to our service territory, and some less complicated type of analysis goes into it. Okay. So look, we -- hopefully, you realize that every day we strive to do better around here. But I've got to tell you, I couldn't be more proud of our employees and the leadership team, which right now is firing on all cylinders. Our plants are running better than ever. Our utility reliability remains best-in-class. We have the biggest capital program in our history underway. More keeps getting added through the Solar Loan, the Solar 4 All. I do believe we'll see more in Energy Strong. I know we're going to see more in transmission. All of the equity needs for these programs are internally funded. We're still telling you that, despite all of that, we have the opportunity for growth in our dividend. And at the end of the day, the rating agencies upgraded us for a very healthy balance sheet. So we're feeling pretty good around here. We'll work hard every day to feel even better and to do even more for you. But thanks for joining us on the call. Take care now.

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