Public Service Enterprise Group Incorporated (PEG) Q1 2014 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Ali, and I'm your event operator today. I would like to welcome everyone to today's conference call, Public Service Enterprise Group First Quarter 2014 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded today, May 1, 2014, and will be available for telephone replay beginning at 1:00 p.m. Eastern time today until 11:30 p.m. Eastern time on May 8, 2014. It will also be available as an audio webcast on PSEG's corporate website at www.pseg.com. I would now like to turn the conference over to Kathleen Lally. Please go ahead.

Thank you, Ali, I appreciate that. Good morning, everyone. I apologize for the slight delay in our call this morning. I appreciate your patience with us, as there's a lot of earnings calls this morning. We do appreciate your participation in our earnings call, and as you are aware, we released first quarter 2014 earnings statements earlier this morning. And the release and the attachments are posted on our website at www.pseg.com, under the Investors section. We also posted a series of slides that detail operating results by company for the quarter. The 10-Q for the period ended March 31, 2014, is expected to be filed shortly. I'm not going to read the full disclaimer statement or the comments we have made 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 of course, 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 like to turn the call over to Ralph Izzo, Chairman, President and Chief Executive Officer of Public Service Enterprise Group. And joining Ralph on the call is Caroline Dorsa, Executive Vice President and Chief Financial Officer. And at the conclusion of their remarks, there will be time for your questions.

Thank you, Kathleen, and thank you, everyone, for joining us today. Earlier this morning, we reported operating earnings for the first quarter of 2014 of $1.01 per share. That's a 19% increase over the first quarter of 2013's operating earnings of $0.85 per share. I'm extremely pleased with PSEG's results. We delivered on many fronts during the quarter. For anyone on this call listening who resides on the East Coast, I don't need to tell you how cold it was this winter. You experienced the polar vortex and we experienced it as well. The record low temperatures challenged our employees, our equipment and our markets. Our readiness was tested at a critical time, and the effort that PSEG's employees put in to secure the availability of our equipment and maintain the reliability of the system was evident and appreciated by customers. The extreme cold weather caused stress around the system from freezing coal-handling equipment at some facilities and playing havoc with other equipment, which resulted in forced outages at some of our coal, gas and peaking units. And there was a need to response to the stress the weather placed on our electric and gas distribution system with additional repair work. Despite these challenges, the strength of Power's fleet was demonstrated in the first quarter through its dispatch flexibility and diverse fuel mix. Our dual fuel coal units were able to run on gas, and when necessary, our peaking units with dual fuel capability ran on fuel oil when gas wasn't available. And our nuclear fleet continued to perform at high levels, operating at a 100% capacity factor. Even though some of our gas generation was curtailed, we were able to get sufficient gas to operate our units at critical times. Our coal and peaking stations responded to the improvement in market economics, and given the responsiveness of our employees, the impact of outages was limited and the fleet was available to meet the strong demand. The extremes in weather created substantial volatility in the market. PSEG Power's diverse fuel mix and dispatch flexibility allowed Power to capture margin on its net long position as it responded to the increasing demand. The strong interaction between our station managers and commercial teams resulted in the adjustment of scheduled outage work and assured the supply of energy in support of customer needs. We were also able to pull forward major work at our Linden units to upgrade with Advanced Gas Path technology in advance of the summer season. Our access to low-cost gas supplies continued to yield benefits for our customers. During the month of February and March, PSE&G's customers received bill credits amounting to $115 million. That's an important savings at any time of the year. Our operating earnings in the quarter also reflect the benefit of an increase in the capital invested in our stable regulated business. This increased investment continues to drive earnings growth and improvement in reliability of PSE&G as it transforms the profile of our company. PSE&G's capital program remains on schedule. In 2014, PSE&G is expected to invest $2.2 billion in electric and gas infrastructure upgrades to its transmission and distribution facilities to maintain reliability as part of a 5-year $10 billion capital program. We reached a milestone as part of our capital program that we are quite proud of. The first segment of the Susquehanna-Roseland 500 kV transmission line went into service during the month of April. We expect to complete construction of the SR towers and the lines heading west to the Delaware Water Gap this summer. Our section of the line, an investment of approximately $790 million, will eventually connect with PPL's portion. And Susquehanna-Roseland is expected to be fully operational in 2015 when PPL completes construction on the western portion of the line. This will be a major achievement. SR's 2015 operational date would be 12 years after the August 2003 block out and almost a decade after PGM identified the critical system needs required to upgrade aging infrastructure and relieve overloaded power lines. PSE&G energized the Burlington-Camden 230 kV line this week, ahead of schedule, and it is on schedule to energize to address the North Central Reliability transmission line this summer. These projects represent a total investment of approximately $790 million and are designed to improve power [ph] quality and system reliability. All 3 lines are part of PSE&G's ongoing transmission program, representing $6.8 billion of the $10 billion capital program I mentioned a moment ago and providing double-digit growth in PSE&G's operating earnings through 2016. As PSE&G's investment in transmission is expected to drive its earnings growth, it is also expected to further diversify PSE&G's asset base as transmission gross will represent more than 45% of PSE&G's rate base over the next 3 years. Transmission lines and switching stations are the backbone of our electric grid, ensuring that we can transport power to where it's needed safely and reliably. This will assume greater importance as we begin to experience growth, although still modest, in weather-normalized electric demand. The polar vortex exposed the critical need to maintain and improve on the resiliency of our infrastructure, the need to replace aging equipment and maintain the level of service demanded by our customers, and it highlighted the everyday truth that not investing in the system can have a real cost. We expect the Federal Energy Regulatory Commission to rule on PJM's proposed changes for a demand response prior to the upcoming RPM auction as they switch over to Power now. We're supportive of PJM's proposals and believe the rule changes will be a good step in recognizing the need for a more level playing field among suppliers. So as we look ahead, Power has also invested in necessary retrofits to its fossil units to meet existing environmental requirements. Earlier this week, the U.S. Supreme Court issued a ruling upholding the Environmental Protection Agency's Cross-State Air Pollution Rule, or CSAPR as we often refer to. As you may recall, this was vacated by the D.C. Circuit Court of Appeals. We're studying the ruling and await word from EPA and its intention with regard to implementing CSAPR. With its implementation, we would see reductions in NOx emissions in addition to the SO2 reductions achieved through the implantation of the Mercury and Air Toxics rule, commonly referred to as MATS. The Supreme Court ruling validates the investments we made to satisfy of environmental requirements, and supports expectations for the retirement of plants that don't meet EPA requirements. As I mentioned earlier, the first quarter represented a significant challenge. Through it, we demonstrated the strength of our assets and the talent of our employees, their focus on the mission of providing safe, reliable energy allowed us to meet the needs of our customers and shareholders. The first quarter was very strong financially and operationally and we are maintaining our operating earnings guidance for 2014 of $2.55 to $2.75 per share, given the importance of normal weather to third quarter earnings expectations for both Utility and for Power. We have a proven strategy and we continue to reap benefits from our robust business mix. Our strong financial position will allow us to meet our goals without the need to dilute shareholders through the issuance of equity, and our employees provide me with a confidence in our ability to achieve our long-term goals. With that, I'll turn the call over to Caroline who will discuss our financials in greater detail.

Thank you, Ralph, and good morning, everyone. As Ralph said, PSEG reported operating earnings for the first quarter of 2014 of $1.01 per share versus 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. As you can see on Slide 8, PSEG Power provided the largest contribution to earnings. For the quarter, Power reported operating earnings of $0.58 per share compared with $0.50 per share last year. PSE&G reported operating earnings of $0.42 per share compared with $0.35 per share last year. And PSEG Enterprise/Other, or the parent, contributed operating earnings of $0.01 per share compared with breakeven operating earnings during the first quarter of 2013. 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. First, let's turn to PSE&G. As shown on Slide 11, PSE&G reported operating earnings for the first quarter of 2014 of $0.42 per share compared with $0.35 per share for the first quarter of 2013. PSE&G's earnings for the first quarter reflect the benefit of an increase in revenue associated with its expanded capital investment program, an improvement in demand, under-reduction and pension expense. Slide 12 provides a reconciliation of the items that influence PSE&G's quarter-over-quarter earnings. FERC authorized PSE&G's request for an annual increase in transmission revenue under the company's formula rate filing. The increase in revenue, which was effective on January 1 of this year, supported a quarter-over-quarter increase and a net earnings contribution from transmission of $0.03 per share. Demand for electricity and gas in the quarter was influenced by weather, which was significantly colder than both normal weather and the weather of a year ago. The impact of the colder-than-normal weather on electric demand added $0.01 per share to quarter-over-quarter earnings. The impact of weather on gas demand, as you would expect, was recaptured in the weather-normalization clause and didn't impact earnings comparisons. Apart from the weather, an improvement in the weather-normalized gas demand and volumes added $0.02 per share to quarter-over-quarter earnings. Gas deliveries continued to benefit from sustained low commodity prices and slowly recovering economic conditions. On a weather-normalized basis, gas deliveries are estimated to have increased by about 3.4% in the quarter. Earnings also improved by $0.01 per share due to a reduction in the effective tax rate and all other items. And the reduction in PSE&G's pension expense was fully offset by some higher operating and maintenance expense associated with weather-related repair costs, resulting in a flat O&M comparison quarter-over-quarter. Economic conditions in the service area led by the housing market are exhibiting slow but steady signs of improvement. On a weather-normalized basis, electric sales were estimated to have improved by 1.3% in the quarter, led by a 2.9% growth in sales to commercial customers. But this level of growth may be greater than the underlying improvement in economic conditions, given Sandy-related adjustments to billings in the year-ago quarter. And you'll recall we mentioned last year that Sandy impacted normal billing patterns during that quarter and immediately after. Weather-normalized electric sales to residential customers are estimated to have increased by a more modest 0.6% in the first quarter. Turning to investments, despite the extreme cold weather experienced in the quarter, PSE&G has been able to maintain its schedule for capital spending and remains on target to invest up to $2.2 billion on electric and gas infrastructure upgrades during 2014 to maintain reliability. As Ralph mentioned, a portion of the Susquehanna-Roseland transmission line was energized from the new Hopatcong switching station to Roseland earlier this year, and the North Central Reliability and Burlington-Camden 230 kV lines are on schedule to be in service to meet this summer's peak electricity demand. PSE&G is earning its authorized ROE for the 12 months ended March 31, 2014. We're maintaining our forecast for double-digit growth in PSE&G's operating earnings for 2014 to $705 million to $745 million as well as expectations for double-digit earnings growth through 2016. Now let's move to Power. As shown on Slide 15, PSEG Power reported operating earnings for the first quarter of $0.58 per share compared with $0.50 per share 1 year ago. The earnings release and Slide 16 provide you with detailed analysis of the impact on Power's operating earnings quarter-over-quarter from changes in revenue and costs. Power's first quarter results, which are $0.08 per share higher than last year, benefited from an increase in revenue. Higher capacity prices, an improvement in the economic dispatch of Power's fleet, and an increase in output more than offset the impact of higher costs associated with the need to meet the increased demand as well as the need to undertake planned outages and the cost associated with completing the capacity upgrade work at Linden. Now let's turn to Power's operations. Power's output increased approximately 3% in the quarter from the year-ago levels, and Power's assets were well positioned to take advantage of market movements in the quarter, given Power's hedging strategy, dispatch flexibility and diverse fuel mix. The base load nuclear fleet operated at an average capacity factor of 100% in the quarter, as Ralph mentioned, and it produced 55% of Power's total generation in the quarter, or 8 terawatt hours. Production from the combined cycle fleet declined 8% to 3.4 terawatt hours in the quarter, or 23% of total generation. Output at the Bethlehem, New York, facility was hurt by a decline in gas availability and Linden's availability was affected by a decision to extend an outage to complete the AGP capacity upgrade work, actually ahead of schedule. An improvement in dark spreads supported an increase in output from the coal stations, particularly from the Connecticut-based Bridgeport Harbor station, so production from the coal fleet increased 15% to 2.6 terawatt hours, or 18% of total generation. The cold weather and increased demand supported the economic dispatch of the steam and peaking units, which provided 4% of the fleet's output in the quarter. Slide 17 provides more details on the generation in the quarter. The combination of higher capacity prices and an increase in market prices on Power's unhedged position more than offset the impact of lower average price upon hedges and the need to meet the demand under the fixed-price full-requirements BGS contract. For the quarter, Power's gross margin as -- gross margins, as shown on Slide 19, expanded to $50 per megawatt hour from $47.50 per megawatt hour last year. Lastly, impacting electric gross margins, Power has identified that it incorrectly calculated certain components of its cost base bids for certain generating units in the PJM energy market, with resulting over-collection of revenues related to its fossil fleet. Power has self-reported the issue to FERC, PJM and the PJM Independent Market Monitor on this issue. The issue is still under review and we're unable to estimate the ultimate impact or predict any resulting penalties or other costs associated with the matter at this time. The company recognized the liability in the quarter related to this matter, but this impact is included in our calculation of gross margin, which continues to show quarter-over-quarter improvement to the $50 per-megawatt-hour level that I just mentioned. Turning to the gas side, the contribution from Power's firm gas transportation contracts improved quarter-over-quarter earnings by $0.05 per share. The contribution to earnings is from Power's traditional gas supply business and it reflects the positive impact on earnings from higher volumes and the ability to price gas sold to commercial and industrial customers at market. Looking forward, power has increased its forecast generation output for 2014 to 56 to 58 terawatt hours from the prior estimate of 53 to 55 terawatt hours. The revised forecast reflects the increase in output during the first quarter and an expected improvement in the economic dispatch of the fleet. As always, our forecast is based on normal weather conditions for the remainder of the year. Approximately 70% to 75% of anticipated production for the April-to-December period is hedged at an average price of $49 per megawatt hour. Power has also increased its forecast of economic generation in 2015 and 2016 to 54 to 56 terawatt hours from 53 to 55 terawatts hours in each year. For 2015, Power has hedged between 50% and 55% of its forecast generation at an average price of $51 per megawatt hour. For 2016, Power has hedged 25% to 30% of its forecast generation at an average price of $51 per megawatt hour. The hedge data, as we show on Slide 20, for 2014 and 2015 continue to assume BGS volumes will represent about 11 terawatt hours in 2014 and about 10 terawatt hours in 2015. We continue to forecast full year operating earnings for power of $550 million to $610 million. Results for the remainder of the year will be influenced by a decline in the average price received on our PJM capacity to $166 per megawatt day on June 1 of this year from the historically high level we're currently enjoying of $242 per megawatt day, as well as a decline in the average price of our energy hedges. O&M is expected to compare favorably given a reduction in pension expense and the absence of major outage-related work that occurred in the second half of last year, for comparison purposes. Now let me briefly discuss the operating results from Enterprise and Other. For the first quarter, PSEG Enterprise/Other, or the parent, reported operating earnings of $0.01 per share, which compares with essentially breakeven operating results during the first quarter of 2013. Results reflected a steady contribution to earnings from the leased portfolio and a contribution from PSEG Long Island. We continue to forecast full-year operating earnings for 2014 for PSEG Enterprise/Other of $35 million to $40 million. I want to point out that in April, PSEG and Power amended their credit agreements ending in 2017, which has effectively -- does extend the expiration dates from March of 2017 to, now, April 2019. Total credit capacity as of March 31, 2014, was $4.3 billion. PSEG has credit facilities amounting to $1 billion, Power's credit facilities total $2.7 billion. In addition, PSEG maintains a 5-year credit facility amounting to $600 million. A significant portion of our $4.3 billion of credit capacity expires post 2018, $2 billion matures in 2018 and $2.1 billion matures in 2019 with this recent extension [ph]. As we said many times, we can finance our capital program without the need for the issuance of equity given the strength of Power's cash flow and our already-strong balance sheet, with debt at the end of March 31 of this year representing 41% of our consolidated capital. And we ended the quarter with about $655 million in cash. We continue to forecast operating earnings for the full year of $2.55 to $2.75 per share. With that, that concludes my comments and I'll now turn the call back over to the operator and open the line for your questions. Ali?

[Operator Instructions] And your first question comes from Jonathan Arnold with Deutsche Bank.

Just on this reserve, Caroline, you talked about in the quarter, the cost base bidding, et cetera, could you clarify if that -- it -- was that just a first quarter item or was -- did you reserve against something that relates to a longer period of history? How long, perhaps, if that's the case?

Sure. So thanks, Jonathan. So we booked a liability in this quarter based on errors that we identified. And they're in certain bid adders such as emissions, historically, and we've fixed all of the errors that we've identified in the bid adder arena that resulted in any over-collection. So right now, we're assessing all other aspects of our model, any other identified and quantified errors will be fixed. We can't comment any further, really, at this point other than to remind you that we have self-reported, and what we booked as a liability is reflected, still, in those numbers that I gave you that result in gross margin per megawatt hour increasing quarter-over-quarter to $50 per megawatt hour.

Do you give us any sort of insight into what your -- I mean, whether this is, there's some kind of historical liability kind of being booked against the first quarter?

Yes. It relates to errors we've identified historically. That's exactly right. But since we're in the self-report and the appropriate regulatory process, we can't give more details at this time. And when the process is complete, we'll give the full information but we can't do that quite yet.

Okay. But it's safe to say that some element of this unquantified reserve that doesn't just relate to kind of rejiggering how you've presented first quarters, there's some past stuff in there, too?

It relates to the past. Correct.

Okay. All right. When, do you think, we might have a better sense of how much that affected the quarter?

Yes. So we're in this self-report process, discussions with PJM and the Market Monitor and the self-report we just made to FERC. We want to see that regulatory process, of course, through to completion and can't really predict what that timeframe would be, but when we get to that end of that timeframe, we'll disclose it as appropriate, the final results.

Okay. And then I think as we've been -- you've been on the phone, it looks like an 8-K has hit with an information about an Energy Strong settlement.

Yes. Jonathan, so let me talk about that. I want to dispel one rumor and confirm one rumor. The one rumor I want to dispel is that we moved the call up an hour and I couldn't get here on time, so we started 5 minutes late. That's not accurate. But we did have some tremendous progress last night in our discussions with all the interveners, in particular the board staff. And this morning, we were just trying to dot our Is and cross our Ts and have signatures on the settlement agreement, and then of course, to comply with FD, we needed to make sure that, that information was released. The earnings release went out ahead of the dotting of Is and crossing of Ts. And we now have done that. So I am pleased to tell you that we have a settlement agreement with the staff. We expect many of the other interveners to join, but we don't have their signature yet, and I'm okay with that. The staff is -- we'd always want to make sure we have an agreement with. It's a $1.22 billion program, about $820 million of that is electric and $400 million of that is gas. The allowed ROE is $975 million. $1 billion of that will be recovered through accelerated-recovery mechanisms. $200 million of that will be done in the 2017 time frame when we will then file a rate case in November of '17, with a 3-month historic, 9-month look ahead profile. So that will be 7 years plus from our last base-rate case. We would expect the BPU to approve this. They have not as yet, the schedule for approving it will be announced shortly. That will be a partial function of how many other parties sign on, although, as I said, I do expect most of the participants to sign on. So I know that they're not on the phone right now, but I just have to thank the hundred-plus municipalities and counties who supported us, the unions who supported us, the hospitals who supported us, the other parties who engaged in the dialogue of about 15 months and our regulatory team. They just did a great job, and we're just pleased to get this thing going right now. I would view this as an important start to hardening the system. There's nothing in the settlement that says we can do the full $3.9 billion. I don't mean to suggest that. But there's nothing that says we can't. So I just view this as an important start, and we will be measured by our success and effectiveness in hardening the system, as we should be. But I'm glad that we can get underway.

And I guess given it's my question, can I just ask one clarifier on this?

Sure. Sure.

The -- so when you said that $1 billion will be under kind of accelerated recovery and then the balance, $200 million will be -- so the $1 billion is sort of for 2015 and '14 through '16. Is that correct?

Yes, it's unfortunately not quite so simple, Jonathan. Some of the stuff will get done in 2 years. Some will take 3 and some will take 5. The 5 year has to do with the substations that were underwater in Irene and in Sandy. And all of those, even those that go out to 5 years, will be under the accelerated recovery mechanism. So there's $200 million of the program that is going to be done just leading up to the rate case. And what we agreed is, we would just make that part of the prudency review since there's really not a lot of time lag between the prudency review and the capital program. None of this stuff gets recovered until it goes into service. So we thought that, that would be okay. That there would be no lag on that $200 million.

The rate case will be filed with 9 months of 2016, 3 months of 2017 for 1/1/17 rate?

No, no, no. You got it the other way around. So when it goes in November of '17.

November.

There would be 3 months of actuals and 9 months of forecast.

It will go in November of '17. Okay. I got it. 3 months.

Very good. Because if I had to repeat it, I might not say it the same way twice. It's 3 months of actuals and 9 months forward, that's been our practice.

And the next question comes from Kit Konolige with BGC Financial.

Just to follow a little on the Energy Strong, can you quantify how much that -- this deal would be worth, say, in terms of EPS or...

Kit, we've pretty much given you a fairly consistent rule of thumb that at our cap structure with these kind of returns is about $0.01 for every $100 million of investment that needs to be refined frequently.

That's right.

Right. And when would -- under this settlement, when would the investment start to be made and how would the rate base ramp up as a result of this?

So -- I mean, you should not expect a big impact in '14. I don't have in front of me the exact capital program calendar, but yes, most of it will be felt in '15, '16, '17 and '18.

And you may recall, Kit, as we talked about in March, right, we forecast double-digit earnings growth, but also double-digit rate-base growth even without Energy Strong as we talked about. So this enhances that to reinforce the strength of the rate-base growth as double-digit and the earnings. But as Ralph said, not a material item at all for 2014.

Okay. And one other area to go back to, Ralph, your comment on the auction, it sounds like -- do I understand you correctly to say that, you view the demand resources rule changes kind of the key change in the auction?

So we do view it as a key change, right? Because the import issue is more of a Western PJM issue than it is for us. So whether it's the limited DR resources or trying to address some of the arbitrage opportunities available between the base residual auction and the incremental auctions, we think all these are positives for creating more of a level playing field in the market. Now I've been running around trying to find the settlement documents. So I'm just looking around at my colleagues to make sure FERC hasn't acted on this yet, right, it's suppose to happen soon, but we don't have a decision yet.

No. That's right. Not yet.

Right. Okay. And so can you give us any insight into what we should expect from the auction do [ph]? Should we expect the PS and PSEG Zones to separate again? And can you give us an idea of what your thinking is about where the RTO settles?

Yes, Kit, we would never do that. We just -- it's obviously a competitive auction process and to forecast or predictions would not be a good idea. And we've never done that in the past. I will tell you though that we'll know by May 23, if it's going on the 12th, and from the 12th to the 16th, and then PJM takes a week to assess them. So 3 weeks and 2 days from today, we'll all have the answer. I don't want to lead you to think that we don't analyze this. We just don't publicize what we think of that.

You're right. Well, at least you confirmed that we'll know by May 23, right?

Yes, thanks, Kit.

And the next question comes from Dan Eggers with Crédit Suisse. Daniel L. Eggers - Crédit Suisse AG, Research Division: Can you just -- with the settlement, can you just walk through maybe -- because I don't have them side by side yet, I apologize. But walk through what were the big changes kind of from that, maybe the $2.6 billion over the 5 years you had projected or requested and what you guys settled today as far as where dollars weren't spent and how you think about the opportunity to spend those later?

Yes, so Dan, the most important part we view of the settlement was the electric substations. And all of that is covered from the point of view of what was affected by Irene and Sandy. But there were a bunch of other areas that we thought would be beneficial. For example, we had the undergrounding of, I think, 30 miles of circuits -- of overhead circuits, and that was knocked out. We had some improvement to SCADA systems, our data analysis, data acquisition and analysis system that would help us restore those customers who were interrupted more promptly. That was knocked out. On the gas side, we had, I think, 500 miles of cast-iron that was affected or is in now FEMA -- more at-risk areas. And that 500 was cut back to 250. We then had some movement of backyard services to the front of the home. Once again, our backyard service getting knocked out is just that much more difficult to restore. That was knocked out. We had some improvements in construction standards for some of our distribution systems. That was knocked out. So the heart -- I just listed a whole bunch of stuff that was knocked out. I don't want to give the wrong impression. The heart of the program was the substations, and that was fully funded. But we will go back, I mean, I think people are going to see that this has a benefit. We wouldn't have proposed it if we didn't think so. And as we do the work and as we see the system perform, we'll go back and talk to the staff and talk to the other parties. I really do take their reaction to this, not as a no on the other stuff, but as a not yet, and just show me that it's money well spent. And I think that, that's perfectly legitimate and fair on their part, and we will step up to that. Daniel L. Eggers - Crédit Suisse AG, Research Division: Do you have a ballpark maybe of kind of by year how that money is going to get spent over the next...

We'll release further details. I don't -- off the top of my head right now, and I just want to make sure the team has a chance to get the schedules all put together and then we can release that. But as Caroline said, in our March conference, we didn't bake in to our growth projections for the Utility Energy Strong. So that's 1.2 over the next 2 to 5 years. It's really more like 4, will be incremental to that, and we'll give you the specifics. Daniel L. Eggers - Crédit Suisse AG, Research Division: Okay. And I guess one other question that has kind of been out in the market is, your kind of views on remaining an integrated company with the distribution business on the regulated side and the competitive generation business. Can you just remind us how you guys think about combined company and what will be required to maybe how you reevaluate that strategy?

Yes, so Dan, we talk about that often. And there's arguments on both sides of the equation. By and large though, we don't think we're hampered from doing things on either side of the company by virtue of having the other company as part of the family. We kind of like the stable earnings growth of the Utility, providing a really strong foundation for the dividend and its future growth. We like the fact that power is generating a healthy amount of cash that could feed the equity needs of the Utility. There are very obvious operational dissynergies to separating. You never say never because we're always asking the question, but we obviously like the model right now. And I just keep reminding myself that every once in a while somebody says, "Gee, you have such a great Utility, if only that were standalone and separate from that struggling power company." 5 years ago, we used to have the same conversation, only the roles we're totally reverse. So it's not -- we don't put our head in the sand and not ask that question. We do talk about it regularly from the point of view of strategic clarity and being able to give a very specific message to our shareholders. But right now, the cash from power and the equity needs of the Utility are a really nice financial complement, and the operational benefits of moving people from one organization to the other with complementary skill sets has been a big plus for us as well.

And the next question is from Travis Miller with Morningstar Inc.

Sort of back on the capacity auction real quick, I wonder if you could characterize how much demand response you would either expect or you've seen in the past show up and the potential impact on you guys specifically or your zone specifically.

Travis, the ability to forecast the DR is not an inconsequential part of getting the price right, so we really wouldn't want to put that number out. And the historic DR, I would rather have you -- I don't mean to make you do extra work, but check the PJM website for that rather than me quoting it. The numbers, I recall, are high-single-digit percentages, like 8% or so, but it's better to check the PJM website. But the [indiscernible] numbers and the transfer capability and the known assets and the known demand numbers are all out there for PJM. So really, a large part of the auction turns on what you expect for DR. I will say this, that most DR does happen in the higher industrial zones. And in the part of PJM that we operate, we don't have a large industrial load, so there's typically a lower DR component where we are.

Okay. Fair enough. And then secondly, I wonder if you could characterize the hedging environment as you saw from essentially February at the Analyst Day to where we are today, end of March period.

I'll start that right now and fill in. To be sure, some of the banks and financial players leaving the market, we have seen a little bit -- well, we've seen less liquidity in the out years. I don't want to qualify it as less. Also, given some of the infrastructure challenges of moving low-cost gas out of the Marcellus to other regions, combined with some fairly extreme weather conditions, have really introduced a tremendous amount of volatility in the market. So we benefited greatly with our naturally long position. We have what I would just call corridors. They're upper and lower limits in terms of how much we want to hedge. And we play within those corridors in terms of, if we think the market is oversold or maybe there's some potential for upside. So we'll lean one way or another. That's why we give you ranges of our hedge position. And suffice to say that, we've been pleased by the way in which we've managed our book given the increase in power prices of late. And we've seen a little modest increase coming from the CSAPR rule. How sustainable that will be, we don't outguess the market, but we do capitalize on those opportunities when they come up. Caroline please go ahead and answer it. I'm sure your...

Sure. Just a few other points then looking at some of the numbers that you saw on our slide deck and comparing them perhaps to what you saw when we were at the March 7 meeting. So we did continue to layer on hedges, consistent with that layering and strategy that Ralph mentioned within the corridors. Keep in mind that the numbers that you have now in today's slide deck reflect an increase in the expected terawatt-hour generation from our fleet based on the economics in the market. That's a good thing, obviously, for us. So what its impact would be is, as we continue to layer on hedges, you wouldn't see the ranges move up quite as much of the hedge percentage because the denominator is moving up. That's great from our perspective. Also, if you look at the hedge percentage for the remainder of this year, it looks a little lower than the hedge percentage we gave you for the full year earlier this year. That's normally what you see because when the first quarter rolls off, you've got a greater representation from the summer period. And the summer period is where we have the mid-merit in peaking, which we would never be hedging fully because of the weather. So you normally see that percentage looking like it's going down, and then it kind of goes back up after you get through the summer. So we continue to layer on our hedges. It kind of looks the same as the progression last year, if you rolled the tape back. The only other thing going on there is that increase generation expectations, which is just great from our perspective. That changes a little bit how to think about the numbers, but it's all because of that denominator effect that we're very pleased with.

And the next question is from Paul Zimbardo with UBS.

I think pretty much all my questions have been answered, but one question on Linden and that acceleration, and some of the other cost acceleration. Do you see that having an impact on the remainder of the year if some of the costs have been accelerated?

In terms of O&M do you mean or in terms of generation?

In terms of outage and O&M type of expenses that you've moved forward.

Oh, sure. So we moved them forward because we had a Linden outage that was ongoing. So we took the opportunity to extend it a little bit so that we could add the AGP, the uprate, so now we have 63 extra megawatts at Linden, which will be available for us for the summer. That increment was about $0.02 for the quarter, but that would have happened later on as we continued to do Linden. So we're still forecasting to have the O&M be lower at power and on a full year basis than prior year. That's what we told you earlier this year. And that hasn't changed. Again, some of this is timing, but a good timing to get the AGP done sooner. Remember, both businesses continue to benefit from pension expense, and that's baked into the numbers. So a little bit of timing difference. Good thing for us from the generation side, still going to see that O&M reduction in our current forecast, actually in both businesses on the year-over-year basis.

Okay. Great. And I'm sorry if I missed it, but did you say a potential timeline on when we would get our next update potential review from the BPU on the Energy Strong settlement?

So Paul, depending upon the extent to which the settlement is universal, if all the parties agree, then it's conceivable that the board would act on it in the May time frame. If all the parties are not on board, and there's reason to believe that we have a good shot at getting all the parties, but I don't know that for a fact, then it's more likely that the board will schedule an opportunity for comment on the settlement, and you're looking at more of a June decision.

And the next question is from Anthony Crowdell with Jefferies.

Yes, actually, it's Paul Fremont. What I'm struggling with a little bit is, when I compare the uplift in commodity margin that you guys realized, which is roughly, I guess, in PJM $50 million on close to 14.5 million megawatt hours, and I compare that to Calpine, which, I think, had only 3.5 million megawatt hours in their north region, but had an uplift of like $125 million. What is it that you would point to as the biggest differences between their profit opportunity versus your profit opportunity when both companies were sort of in a similar hedge position going into the quarter?

Sure. So thanks, Paul. So I don't their situation, so certainly I can't comment on that. Obviously, we saw, as we provided the data in the waterfall, right, part of what you have to keep in mind for us is not just the data on the incremental generation, which we said was 3% higher, but you've got to take into account the impact of the hedges, right, the hedges that we have including the full requirement of BGS, right? So when BGS has stronger demand because of the winter weather, and it was a strong winter this winter, that BGS is a fixed price, and so that reduces some opportunities for us in taking advantage of the market because we have that cost to serve. So we were about 75% hedged, about 25% open to the market for the quarter. Not too dissimilar to where we've been before, but obviously the BGS prices relative to the market prices are lower now because of where the market moved in the first quarter.

So I mean, does that lead you to maybe reconsider whether the BGS is the best hedging vehicle for the company?

No, no. Not really, Paul. I mean, if you think about the reliance on power's cash generation, BGS has nicely protected us in the down markets. Yes, it does create an opportunity cost on the up markets, but it provides a nice stable platform. If you remember, the strength of a BGS is that it is full requirements, and it's -- we are uniquely capable of serving full requirements because of the breadth of our technology. The breadth, meaning baseload, load falling and peaking, which allows us to incorporate a load factor premium and a risk mitigation premium. So no, I don't think you'll see us moving away. That's why we have the 10 to 11 terawatt hours of BGS still factored into future years.

And the next question is from Paul Patterson with Glenrock Associates.

Just, I wanted to follow back on this energy cost bid issue. Are you guys not disclosing the liability in the quarter? Is that -- did I get that correct?

Yes, we're not disclosing the specifics of the liability in the quarter because, as I mentioned, we're in the regulatory process. We did the self-report. We're in discussions with PJM, the market monitor, and self-report to FERC. We'd rather let that regulatory process go on and complete. So as I mentioned to you, we did book something this quarter, but it's all rolled into that gross margin per megawatt hour, that increase. And we'll give more details when we finish the process.

Okay. And then you also said that it was historical in nature. Could you give us just a little bit of a flavor just roughly speaking over what time frame this was?

No. I won't go into that right now. Same thing, we want to handle the regulatory process as appropriate, but it is historical in nature. It's things we identified looking at historical things, for example, as I mentioned, such bid adders like emissions. Those things have been fixed, and those are the kinds of errors we've been reporting.

Did it have an impact on market prices during that period of time or can you...

That's not something we can comment on. As I said, we'll go through the regulatory process, complete all of that, and then we'll give additional information.

Okay. But this is something that you guys discovered and it didn't involve the market monitor or anybody else? You guys are self-reporting that, correct?

We self-reported, that's correct. We discovered it, and we self-reported it to all the agencies, correct.

Okay. And then just finally, there was some commentary about the replacement capacity case, I think, the arbitrage, and you guys have some insight as to what the outcome is going to be is that correct or what were you talking about?

No, no. We, like others, have been curious about whether or not DR actually is physically delivered or whether there's an arbitrage between the base residual auction and the incremental auction. And PJM has basically adjusted some modifications to the way in which that incremental auction can take place and the physical delivery of demand response that we think will benefit the market. That's all. We have no insights other than the full public dialogue on the subject.

And the next question is from Michael Lapides with Goldman Sachs.

Two questions actually. One, Caroline, when I look at O&M in the quarter at both power and the E&G, up year-over-year at both places, up a good bit at E&G relative to first quarter 2013, but even a little bit at power. Can you just walk us through the puts and takes and what of that, if any, would be recurring when we start thinking about 2015?

Okay. Sure. So not really forecasting 2015 specifically, but if you look at the O&M for the quarter -- and you see a nice breakout, I think, on Page 9 of our deck. We put the O&M in 2 pieces for you, which I think is kind of helpful. So the lower pension expense for PSE&G is valued at about $0.02 a share on a favorable basis, right, and then there's distribution O&M, about $0.02 a share unfavorable. So the way to think about that is, we told you that the pension expense for the whole company, right, would be $0.15 a share favorable. A little bit more than half is at PSE&G. So you'll see more like $0.08 for the year and then $0.02 for the quarter. The $0.02 on distribution O&M that was unfavorable year-over-year is primarily driven by some incremental -- some of the storms that occurred in the winter. Can't really forecast that, right? We always forecast normal weather. Sometimes we have storms in the winter. Sometimes we have storms in the summer. So together that leads to a flat O&M on an operating earnings basis, the way we typically report it. Keep in mind, if you're looking at the GAAP statement though, you wouldn't see the impact I'm showing on the waterfall because the O&M in the GAAP statement includes -- is the O&M for clauses. We always take that out from a management perspective, but if you're looking at GAAP, you're going to see O&M that relates to the contemporaneous return clauses we have, for example, like solar and a number of other things. We've always excluded that because that's recovered within the ROEs that we get when we get those clauses. That's why we focus on the operating earnings waterfall that we show you on 9, because that's really what to think about in terms of what flows down to the bottom line without recovery. So that's the Utility piece. You should expect to see pension continue to benefit quarter-over-quarter. And then the rest of the O&M really depends on the rest of our ongoing and control and whether there are any storms in the summer season, but you can't be sure about that. So in terms of power, now if I go over to the other side. Power, we also break out pensions. It's about a $0.01 for the quarter. Remember, I said, power will be a little less than half. So power gets on a rounded basis about $0.01 of benefit for the quarter. And then it has about $0.05 on a quarter-over-quarter impact for this quarter. And I mentioned the Linden outage, which was planned, but then extended. And the extension was an impact of about an extra $0.02 this quarter for the AGP. That's a good thing because that gives us more generation. So on a year-over-year comparison, most of what you're seeing in the O&M negative is the impact of outages and outage extension. For power, going forward, there's no Hope Creek outage in '14. So that will be a favorable impact relative to prior year. Because remember, when we have outages at Hope Creek, we get 100% versus outages at Salem, where we only get a portion. And also there was BEC outage, remember I talked about last quarter, for the end of the year. There won't be a BEC outage in the later part of this year. Roll that all together, where does it all take us? We have some storms in the Utility we had to spend and couldn't anticipate. We had the extended outage for the AGP in power. That is just a little negative. You've got the positive pension rolling through just the way you should expect to see it for the quarter. And when you pull all that together and you look at the rest of the year on an operating earnings basis, setting aside Utility clauses that get recovery, that's why we're still comfortable forecasting a decrease in the aggregate for each of our businesses year-over-year.

Got it. And then Ralph, just on the Energy Strong settlement, I want to make sure I followed kind of the high-level details. $1.22 billion, the bulk of the CapEx is really 2015 to 2017, there'll be a tiny bit at the end of '14 and a tiny bit that kind of trickles after 2017. On ROE, that's 30 to 40 basis points lower, 30-ish basis points lower than kind of the last authorized level and about 80%, 85% of it recovered via contemporary -- contemporaneous clause and the rest of it will be trued-up in a rate case. Is that basically the high-level gist of the settlement, anything I'm leaving out?

No. I think you got it, Michael.

I know there's another call that's about to begin. I don't want to interfere with -- so we do appreciate, I'll turn the call back over to Ralph for any closing comments. I'm available as well as Carlotta for any calls people have.

Yes, thank you, Kathleen. So just a summary, looking back at the quarter and looking ahead. From my perspective, power just continues to handle anything that comes its way. Power managed the polar vortex almost flawlessly. While that's going on, we ran 100% nuclear capacity factor, and we managed to get our Advance Gas Path technology accelerated into the quarter at Linden to make sure it's ready for the summer. And then looking ahead, please make note of the increase in our expectations for power's output in the subsequent years. Utility, once again on track for double-digit earnings growth. Capital program is on budget. You heard us mention a couple of transmission projects that are ahead of schedule. And of course, the good news that we've reached resettlement on the $1.22 billion Energy Strong Program. And last but not least, the weather-normalized demand for gas continues to grow, and we're now beginning to see growth in electric demand, and that's refreshing. So thank you for joining us. I hope to see all of you at some point in the near future on the road as we make our visits. Thanks, everyone.

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