Ladies and gentlemen, thank you for standing by. My name is Kimiko, and I'm your operator today. I would like to welcome you to today's conference of Public Service Enterprise Group Fourth Quarter 2012 Earnings Conference Call and Webcast. [Operator Instructions] As a reminder, this conference is being recorded, Thursday, February 21, 2013, and will be available for telephone replay beginning at 1:00 p.m. Eastern Time today until 11:30 p.m. Eastern Time on March 4, 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.

Thank you, Kimiko. Good morning, everyone. We appreciate your participating in our earnings call this morning. As you are aware, we released our fourth quarter and full year 2012 earnings statements earlier today. And as mentioned, the release and attachments are posted on our website, www.pseg.com, under the Investors section. We also posted a series of slides that detail operating results by company for the quarter. Our 10-K for the year ended December 31, 2012 is expected to be filed shortly. We won't go through the entire disclaimer or the comments we have on the difference between operating earnings and GAAP results, but we do ask that you read those comments contained in our slides and on our website. The disclaimer statement regards forward-looking statements detailing the number of risks and uncertainties that cause actual results to differ materially from forward-looking statements made therein. 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 estimates change, unless required by applicable securities laws. We also provide you with a commentary on the difference between operating earnings and net income reported in accordance with Generally Accepted Accounting Principles in the United States. PSEG believes that the non-GAAP financial measure of operating earnings provides a consistent and comparable measure of performance to help shareholders understand trends. I will now 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. [Operator Instructions]

Nice try, Kathleen. Thank you, Kathleen, and thanks, everyone, for joining us on today's call. Now before I review the earnings we reported earlier this morning, I want to recognize the extraordinary response by PSEG's employees to Superstorm sandy. This truly epic storm challenged us more than any other natural disaster in PSEG's 109-year history. Every aspect of our business was affected by the storm, electric and gas distribution, as well as transmission and power generation. We restored service to more than 2.1 million customers in a 2-week period of time. We reactivated generating facilities damaged by the storm surge and we repositioned our portfolio in response to the storm's impact on our facilities. We came through this unprecedented storm because our employees worked around the clock to restore service to our customers. We also owe a debt of gratitude to all the employees of utility companies from outside the state who helped us restore our system to working order. We take our commitment to serve the public very seriously, and our employees demonstrated that commitment in the aftermath of Sandy, even at great personal sacrifice. There is simply no better group of people to get the job done. A s we've disclosed previously, we estimate the cost of restoring service and getting back to normal operations at approximately $295 million of PSE&G. Today, we want to let you know that damage from Sandy could cost up to $300 million of PSEG Power. We incurred $85 million of this expense in the fourth quarter of 2012, the amount that PSEG Power will be spent over a 2-year period. The estimate of the storm's impact on our cost doesn't reflect any recovery from our insurance carriers, which we are pursuing. Superstorm Sandy has also caused us to review our investment program,…

Thank you, Ralph, and good morning, everyone. As Ralph said, PSEG reported operating earnings for the fourth quarter of $0.41 per share versus operating earnings of $0.47 per share in last year's fourth quarter. Our earnings for the fourth quarter brought operating earnings for the full year to $2.44 per share versus operating earnings for 2011 of $2.74 per share. Our current results were at the upper end of our operating earnings guidance for the year of $2.25 to $2.50 per share. On Slide 4, we've provided you with a reconciliation of operating earnings to income from continuing operations and net income for the quarter. And as you can see on Slide 10, PSEG Power provided the largest contribution to earnings. For the quarter, Power reported operating earnings of $0.24 per share compared to $0.27 per share last year. PSE&G reported operating earnings of $0.15 per share compared to $0.19 per share last year, and Energy Holdings and parent together contributed $0.02 per share to operating earnings compared with operating earnings of $0.01 per share in the year-ago quarter. As always, we've provided you with waterfall charts on Slides 11 and 13 to take you through the net changes in quarter-over-quarter and year-over-year operating earnings by major business. Needless to say, Superstorm Sandy had a major impact on our operations in the fourth quarter and we'll highlight that impact across PSEG. Let me now review each company in more detail starting with Power. As shown on Slide 15, PSEG Power reported operating earnings for the fourth quarter of $0.24 per share compared with $0.27 per share a year ago. The results for the quarter brought Power's full year operating earnings to $1.27 per share. Power's fourth quarter operating earnings benefited from a strong control of operating expense, higher price for…

[Operator Instructions] And your first question is from Travis Miller of Morningstar.

I wanted to get more into the dividend policy, where you think that dividend is going. When you think of, given the CapEx spend and such, do you think you could grow the dividend in line with earnings? Do you think about it in line with corporate earnings and in line with utility earnings? Give us a sense of that growth.

Travis, thanks for your question. What we've consistently said to folks is we don't have a dividend growth rate target, we don't have a payout ratio target. Both of those are items we consider, as well as the relative cash being generated by the businesses and the cash requirements of the businesses. So we summarize it by saying that we do believe we have an opportunity for modest growth in the dividend, consistent with what we see right now in terms of the cash generation and needs of the business, but we don't get numerical or quantitative on it. I mean, we've grown it, 9 or the last 10 years, it's been about a compound annual growth rate of 3%. We've paid it annually for over 100 years, so we try to give you comfort about it without giving you a specific, here's the growth rate.

Okay. And the second question, on the BGS auction, particularly looking at that incremental $53 a megawatt hour, you signed all those extra elements, how did that correspond with your expectations? And obviously, the capacity revenues were set. But if you take out that, how did that incremental part line up with your expectations?

Sure, Travis. So it really lined up relatively well with our expectations. Because if you think about it, and I know we've talked about this, and Kathleen spoke with folks earlier about this after BGS results came out, the 2 pieces that we pointed to as growing in that green section were the green energy component, right? The renewables. And also transmission. And so transmission wasn't a surprise to us because it really reflects the inclusion in cost for the BGS contract from the significant transmission work that's underway at PSE&G, which we've been talking about, right? So the significant transmission work that's been underway in PSE&G for some time, as well as the ongoing program for increased transmission spend, that is part of the base we've been talking about for a while, it finds its way into those numbers, because obviously, every BGS provider has to fully support the full transmission build out. So that wasn't really a surprise to us. Don't forget, of course, the other thing that increased slightly from the 2012 level was energy based on the PJM Westford energy price. So these results were relatively consistent with our expectations, and the way we think about this is really what you're seeing now is stability in BGS as the PJM West prices have been stable on a year-over-year basis.

And your next question is from Dan Eggers, and he is at Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Can you mind talking a little bit about the big transmission -- or the big CapEx program you announced yesterday as far as what is the approval process to line up investment both on the distribution side and on the transmission side and maybe a timeline of when you think you'd get approvals to start making those investments?

Sure, Dan. So on the distribution side, if you think of these the same way we thought about what we used to call our CIP programs, our capital infrastructure programs, so there is no time requirement for the BPU to act. These are clause recovery mechanisms that we're proposing. And the pace of review and approval is really directly proportional to the importance that the BPU ascribes to storm readiness. So we expect the BPU to fully scrub the numbers and go through and think about cost benefit. I think they'll trust our judgment in terms of what the priorities are and which substation is the most critical and which switching stations are most critical. But it really is a question for them in terms of what pace of action they want to see occur. I mean, we are a reliable utility. This is not needed for day-to-day reliability. This is to respond to enhanced extreme weather and enhanced reliance on electricity on the part of customer lifestyles. Transmission is a wholly separate story. Those are supplemental projects that come out of our analysis of RTEP. And while PJM can reject those, we don't need to wait for them to be included in the RTEP, and you can be assured that we've scrubbed those pretty tightly and we'll put them into formula rates as the work begins. And let me remind you that, that $1.5 billion is above what we've already announced previously for transmission. So PJM will conduct their no-harm review, and that will just then go into formula retreatment. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And just to make sure I understand on the distribution side. So do you have to get approval to get treatment for these under the capital writer that you've had in the past or is that something that you guys think you can just implement now?

No, we would only do these under a capital writer program. What we proposed is one that's identical to what we had and what we call CIP 1. And CIP 2, that was different writer and that was obviously acceptable to us then, it would be acceptable to us now. And we want to be flexible in talking with the staff and the BPU about what the recovery mechanism is, but we are not going to make these investments under traditional regulatory lag programs. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And then I guess from a spending perspective, as you scale in, a lot of that money is kind of in the next 3 or 4 years, should we assume that not a lot in '13 and have it ramp up in '14 and '15 or is it something you guys are going to get into at the Analyst Day?

Yes. We'll get into more details at the Analyst Commerce, but yes, what you said is accurate, you should not assume a lot of that in '13.

And your next question is from Andy Levi of Avon Capital.

Just 2 very quick questions. Just to clarify on the BGS auction, so the net margin increase, is that about $2, is that kind of a way to look at looking at your chart that kind of hits the bottom line?

We never disclose that number, Andy, sorry. That's been a pretty consistent policy of ours.

Okay. And also then, just on the new CapEx program, could you just reconcile for me -- I guess there are not going to be rate increases for this?

Yes, so...

But just explain, I guess, obviously, there's an increased expense, so there must be some type of rate increase, but what does it offset by, to get your net 0?

You got that right, Andy, right. So the bill consists of numerous rate components. And even a sophisticated audience such as this will be surprised as how many components there are in a rate, which is a way of me saying please don't ask me to list them all because I probably won't remember all components there on the rates. So obviously, the distribution component of rates will go up as a result of this. One cannot invest this amount of money and get a fair return without those increasing. But it will be offset by declines in several components. And the BGS, as Caroline reported, were it not for transmission, would have been down probably, I don't know, $6 or $8, I think, is the exact amount. So there, you see an example of exactly the strategy we've been following, which is as wholesale supply costs come down, this is the time to make needed infrastructure investments and keep the bill essentially flat. And as we look forward, there are a couple of elements of the market transition charges that were put in place in 2000 that will come off. That add up to about 6% of the bill, and that will happen at the end of '13, and at the end of '15. So those declines will be offset by the increase in the distribution rate. So what we hear when we talk to our customers, and we talk to them a lot, is don't confuse me with rates, tell me what's going to happen to my bill. So we're not suggesting that rates aren't going to change. Obviously, rates will change, but the net effect is that if you assume continued flat BGS rates per the forward price curve, that customers' bills will be the same in 5 years as they are today, and customers' bills are substantially 30% to 35% below what they were on the gas side, and a few percent below what they were on the electric side from 2008. And if you were to -- if you would do something that just take CPI, it escalate either today's bill or the 2008's bill, in real terms, customers' bills will be far below. So yes, you're right. One element of the bill, one rate component of the bill will go up to pay for investments, but it will be offset by other pieces coming down.

How much is the stranded cost portion?

I think it's about -- we'll detail it for you on March 1. I think it's about 6%, 4% to 6%.

Which is, in millions of dollars, do you have that?

Oh gosh, no I don't. But I'm being told it's 6.6%, but I don't have it. I really didn't know. We'll give you the details at March 1.

So on the distribution side, what would be the percent increase that you're proposing?

I don't know either.

Yes. I guess, going to wait to see the file. Well, I guess, you made the filing but...

We made the filing, yes. We've been swimming in customer bill questions, because that's what our customers are most concerned about and that's what we want to make sure we're attentive to. So the incremental components, we can give you more detail later.

Okay. So bottom line is the PSE&G Power will offset the distribution rate increase, I guess, is what you're saying?

That's -- I mean, at a high level, it's true, plus some regulatory explorations, all right?

Right. The stranded cost? Right.

We've been pretty consistent and upfront with policymakers and everyone about that, that the decline in natural gas prices and the result which directly affects the gas billing, the result in decline in electric prices, combined with the low interest rate environment, the availability of labor and the pressing need for the infrastructure investments makes this a perfect time to do.

And your next question is from Paul Fremont of Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: I guess my first question is can you give us an update on what you're expecting to happen with LIPA and the status of your contract? And if it were put up for sale, would you have an interest in it?

So Paul, so we are busily approaching January 1, 2014, per the terms and conditions of that contract, which gives us the authority and the responsibility to manage those distribution and transmission assets. So we are focused on exactly what we're focused on pre-Sandy, post-Sandy and everywhere in between per in terms and conditions of the contract. So we're assuming on January 1, we have those responsibilities. In terms of whether or not we will be interested, we never comment on any asset acquisition or company acquisition. So I just... Paul B. Fremont - Jefferies & Company, Inc., Research Division: Can you update us on what level of customer migration was at the end of the fourth quarter? And also, can you give us a sense of what would be your expected insurance recovery for the $300 million of spending at PEG Power?

Sure, Paul. It's Caroline. So relative to customer migration at the end of the year, you may recall at the beginning of the year, we gave an estimate of between 36% to 40% migration by the end of the year. And we don't have the December data at this point. It usually comes about a month from now, because everything's on a bit of a lag. But our best estimates are that we ended the year right about the high end of that range, but right come smack at the edge of the range. So that's really consistent with our expectations. The other point that I made on my remarks about the year-over-year impact is actually an important point relative to how to think about the ongoing impact of migration, and that is about the headroom. So year-over-year, in the fourth quarter, migration was actually a net positive, and that's because in 2011's fourth quarter, we saw headroom expand significantly from what it had been earlier in 2011. And by the end of 2012, that headroom had come down significantly, really, it was coming down during the year. Now to what we see, and you have to calculate your own, but what we see is a single-digit number. So that's important because it goes to a way to think about migration in the upcoming year. As to headroom, if it stays to be a single-digit like number and you saw some -- the prices embedded in the most recent BGS clear, that means the impact of migration, as we've always talked about, becomes a smaller and smaller impact to our margin, because the real impact is that difference or that headroom. So we're not forecasting a specific migration level as we come into the upcoming years. I think you've heard…

Paul, I guess, I just want to add one thing on LIPA. Obviously, should the contract not take place for whatever reasons, some change in direction, all of the cost that we're incurring this year are recovered from LIPA. And they've been a good payer and a good partner throughout this process. So there's no financial risk there to us. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And quickly, the utility, what type of electric demand growth are you expecting for '13?

So we'll give you those numbers in a second. But be mindful of the fact that my usual speech about weather normalization becoming more of an art than a science has to be multiplied by a factor of 10 with an event like Sandy. But Caroline, do you have those numbers?

Sure. When you think about demand growth, we typically stay relatively close to the forecast that you see from PJM. So pretty modest demand growth is what we're assuming over the multi-year period. PJM's most recent documents, as you probably saw, had demand growth of about 0.8%. And so we tend to use figures around that range, so relatively modest demand growth taken in the aggregate.

And your next question is from Neel Mitra of Tudor. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I have a question on holdings, the $25 million to $35 million in operating income guidance for '13. I'm trying to understand what's really driving that. Is that a solar tax credit? And is the $25 million to $35 million earnings, is that something that we can apply going forward or is that more lumpy when you get projects in the Q?

So it's a good question, Neel. I would say, from an ongoing basis, it is a little bit lumpy because when you put a solar facility into place, you have a onetime benefit that is a portion, it's not the entire ITC. It's just a portion of the ITC based on how the tax rules work. The remainder of the ITC rolls out over the life of the asset. But there's a little bit of a bump of a benefit there. In addition, the remaining things in holdings that we have are assets, like we have a generating plant in Hawaii for example, those ongoing earnings flow in and also anything that happens on a short-term basis on interest from parent would be in there as well. We have some swaps in there also. So I'd say you should assume last year's level of course was never something you could extrapolate from because we have the audit settlements. The current year level has a little bit of bumpiness for solar, so if you're thinking about it on a longer-term basis, you should have some level of value there but probably not the level that we're forecasting this year until we get to a new solar installation, in which case, we would give you that information on an ongoing basis. Neel Mitra - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then second question. Ralph, on the PJM planning parameters, PS Zone seemed a little tight. Can you just talk about some of the changes year-over-year that would drive that? Would it be just some of the head retirements and less incremental transmission, just what are your thoughts on that?

So it wouldn't be less incremental to transmission but it would be the head retirements, that's right. We typically don't get much further than that in terms of the disclosure, especially with RPM being just 2.5 months away now.

And your next question is from Jonathan Arnold.

My question -- I hope you didn't just answer this, but if you did, just say, I was caught away for a second. Does the investment in storm hardening, in any way, changed the sort of likely pace of -- or enthusiasm for some of the incremental solar investments that you were talking about, say last quarter and/or the gas infrastructure upgrades or should we see it as sort of simultaneous and incremental?

So Jonathan, thanks for the question. So there's no linkage between the solar and the hardening other than the obvious linkage being the customers' ability to pay. But my flat rates comment included the solar component. The gas firing that we had anticipated making has now been superseded by this infrastructure filing. We had originally thought that we would do a gas filing of about $250 million to $300 million per year, and it's turned into this $1.04 billion component of the storm filing that we just made.

Next question is from Paul Patterson of Glenrock.

Just, I guess, I'm a little bit slow on this, I apologize. But just the incremental amount of CapEx that we should be seeing, I guess, beginning in 2014 versus your previous planning, how should we think about the increase in CapEx because of this program that you're mentioning? You just mentioned the gas thing, and I just wasn't clear.

Yes, and it's understandable, Paul, because what we're basically saying is we're going to give you -- we have the details of that, but it just -- it doesn't lend itself to a phone call conversation. So we'll give you details from '13 to '17, by electric, by gas, by transmission, and that will all become much clearer on March 1. It exists. I'm not saying it doesn't exist, it's just doing that by phone is at least 3 by 5 matrix, and it's just -- it's not pretty, so...

Okay, great. So we have something to look forward to. And then just the weather-adjusted sales growth, really quickly, the quarter just seems a little bit odd. I mean, it seemed like it was diametrically different for -- on a weather-adjusted basis for residential versus commercial and industrial. I mean, it may seem like big, big differences, I mean, 3.2%-plus for residential if I read that correctly, and minus 3.7%, and you guys associate part of that, with the economic impact associated with Sandy, but it wasn't Sandy itself. Just any sense as to why there's such a big difference between the 2?

Right. So I think, Paul, one thing to keep in mind is when we did the weather normalization, right, we are not normalizing for Sandy, right? Because weather normalization is essentially temperature, right? Sandy wasn't temperature, right? Sandy was something completely different in storm surge and outage and all of that. So you have a little bit of a differential in terms of seeing, as you point out, between commercial, industrial and the residential. So you just got to think about it as Sandy really changed a lot of things that really changed that dynamic. But keep in mind that if you kind of look at the year-to-date, you do see a pattern that is of the same direction, right? So the residential was a little bit higher on a full year basis and commercial and industrial were a little bit lower. The fourth quarter is really a distortion for the magnitude given what happened with Sandy. But the year-to-date, you're still seeing a little bit of growth in residential, and you're seeing a little bit of decline in commercial and industrial. We've kind of seen that pattern for a bit.

So Sandy messes everything up kind of thing?

Yes, for the quarter, I wouldn't do any kind of extrapolation because, really, it's hard to pull Sandy out of all that. We think, without Sandy, it would've been more like a neutral picture for the fourth quarter. But as Ralph says, weather normalizations is an art, and probably Sandy normalizations is a double art.

Your next question is from Julien Smith of UBS.

So first, to go back and clarify the holdings component for '13, if you would've think about a couple pennies or so from this Arizona solar project, is the bulk of the remainder there, call it the $0.04 in earnings, going to be sort of an ongoing element, is that what you were meaning to say earlier?

Well, I didn't give any specific numbers, right, for the amount from the solar ITC, kind of onetime effect from that permanent difference calculation for both relative to how to think about kind of ongoing. Yes, I mean, we do have ongoing benefits from our assets and they do flow through. But I would just caution about drawing too many conclusions on exactly how to forecast beyond the current year, because, of course, we don't give guidance beyond the current year. But you should assume that there are a few cents in there for the ongoing performance of our assets. That is the right assumption. We have assets that are performing well. But the solar, as it is for every company, right, creates onetime events that relate to the recognition of a portion of the ITC.

But to be clear, the single item that you've called out for next year is this Arizona solar project, right?

No, no, no.

Well, in terms of ITC for a project coming into service, that's a onetime event, right? So remember, in the ITC, if -- you may not be familiar, right, in the ITC recognition, there is a onetime permanent tax benefit that comes from the implementation of the ITC where you get the ITC, you recognize it over the life of the asset, but you don't take down the tax basis for the full amount of the ITC. It's that permanent difference that gets recognized on a onetime basis. The rest of the time, the ITC flows out over the earnings on an ongoing basis.

But just to correct, we're not saying that one project is the bulk of the $25 to $39 [indiscernible] at all.

No, it's just one unusual item that you wouldn't want to forecast from.

Right. Great. Second question. When it comes to -- perhaps a clarification, when it comes to this filing you've made yesterday, how does that contrast against some of the pending bills out there at the legislature, contemplating similar infrastructure build outs?

The bills in the legislature really have 2 components to them. One component is a change in the penalty schedule for utilities underperforming which we have expressed support for, because we have a lot of confidence in their ability to operate. Well, what we said to folks is, look, if you're going to increase the penalties, please improve the tools that the BPU has available to it to establish rates that facilitate investments that will help us perform at the level you want us to perform. Now there's some debate as to whether or not the BPU already has that authority, but we're of the opinion, "better safe than sorry." So why not make it an explicit option at their disposal.

Great. Your proposal thus far, though, is not tied to any kind of pending legislation though, right? This is completely independent?

That's correct. Surely, it is not.

And your next question is from Michael Lapides of Goldman Sachs.

Just actually 2 items, a little bit unrelated, my apologies. First, on the Solar 4 All, what's the timeline for getting approval for that, and the capital spend kind of on an annualized basis?

So the timeline has been stretched to May 1, Michael. The Board staff with Sandy has just been incredibly busy. So there's a period of cooperation, we set the 180-day requirement, something that we're more than willing to live with, even relax. So May 1 is the new date. And that's all for components, $690 million over roughly a 5-year period.

Got it. Okay. And second item, on O&M, when you think about the O&M that's in ongoing earnings for 2012, so backing out the Sandy impact at PEG Power, can you just -- what's in your guidance for 2013, just all-in for year-over-year O&M growth?

Sure. Michael, it's Caroline. So we haven't given the overall O&M growth. So I mentioned pension only because that's quite a swing factor that obviously garners a lot of attention and we've given a lot of attention in the past. As you know, we did pull Sandy out of O&M for Power on an as-reported 2012 basis. We will do that for 2013 as well. And we'll give you the O&M forecast, as we typically do, on a kind of 3-year CAGR basis. We'll give you that for the company as a whole, as well as power utility kind of broken out in 2 pieces on March 1, again, in context, the same way we give you the capital expenditures for an ongoing 3-year basis as well. We haven't given that on this call. We'll give that on March 1 as well.

And your next question is from Brian Chin of Citi.

Can you -- I know that you said that you based the guidance on the current forward curves. But given that volatility, can you just be a little bit more specific? Are you talking about the current curves in the last week or 2? Are we talking the current curves maybe a month ago? Just a little bit more specificity there would be helpful.

So Brian, actually the curves have been pretty steady for quite a few quarters now. So I'm a little bit at a loss. I mean, we do refresh our detailed plans on a fairly regular basis. I'm sure the finance team thinks I'm saying that we do it too often, but I mean, I'm just looking at a chart right now that looks like a very small modulating sine wave for the past 9 months. So the day-to-day volatility due to basis differentials or weather spikes, I mean, that's something that ER&T managers on a day-to-day basis, and we don't do our business planning or financial planning on that basis. So I guess, I'm politely disagreeing that we've seen pretty stable prices. And given our hedging, we're even more comfortable with our numbers.

Okay. Well, I mean, we can disagree about what is a volatile level of power price movement. But can you give at least a rough timeframe on which you set your forward curves? Was it -- when you say current, is that in the last few weeks, last month, last -- just to give us some sense there?

So the last time we did a full run of the business plan was January -- December 31, 2012.

Okay. Great. And then lastly, the $1.5 billion in transmission line spending, when is that going to go through the PJM approval process? Can you give us a sense of the timeframe there?

Yes, this one is a little bit stranger, Brian. It's not a PJM approval process. It's a PJM veto process, so to speak. They come up with an RTEP. We look at RTEP and say, oh, if we're going to do that, we have to do this, this, and these other few things, these supplemental projects. They tend to be of a lower voltage, but still transmission voltage. And then at the staff level, there's no major project that comes out of that as they make sure that there's no harm to the RTEP. And in fact, what we're doing is consistent. If that all works the way it always works, we will start spending in 2014.

Okay. So I guess the argument then would be given the veto process by which this proposed spending has to go through at PJM level, it's unlikely that this new proposal is going to change any of the RPM parameters ahead of this auction, it will probably show up in whatever parameters are put out in the next [indiscernible]

Yes, that's correct. I didn't realize That's where you were going, yes. That is an accurate statement.

You may turn over for closing remarks.

So we've had quite a few of these calls together. So by now, I'm sure you're a little bit tired of hearing the pride I take on our operational excellence, I'll have a slightly different emphasis right now, and that is that we work quite hard and take an equal amount of pride in the financial strength we built for the company. And it's really with quite a bit of enthusiasm and optimism that we're proposing to put that balance sheet strength to work to benefit our customers and our shareholders alike. I'm delighted by your questions. I know we said a lot of we'll give you that on March 1, so I hope we see all of you next Friday and have a great week. Thanks for joining us.

This concludes our teleconference. You may now disconnect.

Thank you, operator. Thank you all.