American Electric Power Company, Inc. (AEP) Q4 2013 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by, and welcome to the American Electric Power Fourth Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, today's call is being recorded. I'll now turn the conference over to Ms. Julie Sherwood. Please go ahead.

Thank you, John. Good morning, everyone, and welcome to the fourth quarter 2013 earnings webcast of American Electric Power. Our earnings release, presentation slides and related financial information are available on our website, aep.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Joining me this morning for opening remarks are Nick Akins, our Chairman, President and Chief Executive Officer; and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.

Thanks, Julie. Happy New Year to everyone and thanks for joining us today. Usually, the new year comes with a sense of renewed optimism that our best days lie ahead. I can tell you, here at AEP, reviewing what has been accomplished during 2013 and after a more detail review of the fundamentals during the fourth quarter, there is reason to be optimistic. The foundation has been set for continued success and perhaps, finally, a growing economy. We talk a lot here about infrastructure development, including transmission, the customer experience and the employee experience, and this provides the focus for the actions we take. In that context, I'm very pleased to report several significant accomplishments during 2013. Our safety performance. For the second year in a row, we accomplished 0 fatalities on our entire system with one of the best safety records we've ever had. Moreover, we also had our best year from an environmental stewardship and compliance perspective. We are very proud of both these accomplishments that, in my view, is a strong indicator of the health of the organization. We completed corporate separation on time and accomplished many of our objectives, including the transfer of the Ohio generation assets to APCo, Kentucky and the new unregulated generation company. I want to thank all of the commissions and the other stakeholders for their cooperation to get this done. We delivered fourth quarter '13 GAAP earnings of $0.71 per share and operating earnings of $0.60 per share, concluding the year 2013 with GAAP earnings of $3.04 per share and operating earnings of $3.23 per share, solidly in the upper range of guidance. Rate activity was positive, with $340 million of secured rate changes across our state jurisdictions. I'm pleased to report from last week that PUCT did reverse the AFUDC…

Thank you, Nick, and good morning, everyone. On Slide 6, you will see our comparison of 2013 results to 2012 for both the fourth quarter and the full year. In the interest of time, I'll focus my remarks on the full year column and only add comments for the quarterly comparison when necessary. Operating earnings for the fourth quarter were $2 -- $296 million or $0.60 per share, up $0.10 per share compared to the fourth quarter of 2012. These results bring the full year earnings to $1.573 billion or $3.23 per share compared to $1.497 billion or $3.09 per share recorded in 2012, an improvement of $0.14 per share. Stepping through the detail from top to bottom, you can see that the annual comparison was adversely affected by a combination of certain Ohio transition items that were unfavorable by $0.26 per share. This effect on earnings was driven by an increasing customer switching net of the capacity deferrals, lower capacity payments from competitive retail energy suppliers and the overall -- and the reversal of 2012 prior-period unfavorable provisions. The effective income tax rate was unfavorable at $0.17 per share for the year due to unfavorable year-on-year tax-to-book differences accounted for on a flow-through basis, as well as positive adjustments to the state income tax returns that were recorded in 2012. A significant portion of this effect was recorded during the fourth quarter. Allowance for funds used during construction, or AFUDC, was off $0.10 per share for the year, due primarily to the start-up of the Turk Plant in December of 2012. O&M expense net of offsets was unfavorable $0.05 per share for the year, primarily due to increased spending for planned outages in 2013. The unfavorable variance for the quarter reflects higher storm and employee-related costs. On a total…

[Operator Instructions] And first, we'll go to the line of Greg Gordon with ISI Group.

A couple of questions. First, can you repeat what you said about your -- what was the build-up for your assumptions on residential sales? And then can you extrapolate on what that means sort of going forward over the next several years of your forecast?

Yes. So we're anticipating residential sales to be down almost 1 percentage point in 2014. And we think it's largely being impacted by a lot of the energy efficiency programs that we have across our service territory, with Ohio, Indiana and some other states having some pretty aggressive programs. So it is impacting load, also customer accounts are an impact as well. We're seeing positive customer account growth in the western part of our service territory and pretty stagnant customer growth in the eastern part of our service territory. So when you put those effects together, it's definitely a drag. We'll see how things work out as we go through the year, and we'll obviously be updating you quarter by quarter. But we are anticipating some load decline in the residential sector in 2014.

So Greg, the last quarter of the year indicated some positive strength to that. But I think you -- we're going to have to sort of see that play out before we make any changes.

I guess what I'm asking is, as we think about the guidance ranges for '15 and '16 -- I'm not asking you to give specific drivers across all the factors of the business, but would it be fair to say you're assuming continued reductions in residential demand through time due to federal and state energy efficiency standards? Or do you think that your base case for economic growth beats [ph] into that and you could get back to a positive net residential growth?

Our load growth assumptions through '16 are very, very conservative. So I mean, we are not forecasting to hit our numbers. The classic 1% to 2% load growth that we had seen earlier in the century, we're anticipating that negative 0.5% to positive 0.5% load across the timeframe.

So it's relatively flat. It's less than 0.5%.

Great. Second question is on what you're seeing. I know you have a de minimus footprint in -- relative to a lot of the other companies when it comes to competitive generation and retail, but it's still significant for you. Have you seen behavior change on the part of retail consumers and wholesale buyers in the last several weeks with regard to what they're willing to pay for longer-term power contracts? Wholesale prices are up quite a bit in '14, last 3 weeks, not as much altitude [ph], but are you starting see some depth and breadth of the market come back as volatility comes back or not?

Yes. Greg, we really haven't seen much of that yet. Obviously, there's going to have to be a little history that plays out here with the weather. But also, it's pretty clear that capacity rents are included in energy prices. So with the market reforms that are occurring plus the experiences people are having relative to this extreme weather, there may be opportunities for additional hedging to occur and also, for customers to finally see that we need to sort of lock things up for the long term. So it may be helpful, but at this point, it's too early to tell.

Next question is from Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Nick, just kind of -- now that the transition for competitor generation in Ohio is kind of on its way, can you just share your thoughts on the future of competitive generation in the AEP business mix? And maybe to what Greg was asking, are you're starting to see or are you able to engage in conversations about some long-term supply agreements to help put some more visibility in that business?

Yes, I think we stand by originally what we said relative to this business that it'll hinge upon our ability to see this additional hedging occur, that we can firm up the supply and make it look quasi-regulated. At this point, because capacity markets have been depressed and now recent experience aside, it's difficult to tell how successful we'll be in our ability to hedge that up because -- but we're not standing on our laurels with that. We're aggressively looking at the cost structure of the business. We're also reforming the way we operate as our plants -- because they know full well their survival is at risk there. And so we're going to do everything we can do to position this fleet to where it's positive and also address the market reforms that are occurring for now. And then, hopefully, with the events that have transpired recently with the weather, it could help us in terms of -- and get additional hedges in place. But that business, our retail operation, together now with that generation fleet, there are some opportunities there, so we're working on all fronts to ensure that we're able to position this business as best we can. And at the end of the day, it needs to look quasi-regulated to us. Dan Eggers - Crédit Suisse AG, Research Division: I guess, yes, Nick, from a market reform perspective, given the time horizon, even to the next RPM results actually affecting your earnings contribution, are there changes going to happen in a reasonable time period of giving you guys comfort to wait it out? Or are you going to need a customer to come in and buy and -- rather than having policy reform to do it?

Yes, that sort of -- that remains to be seen. We have -- I think there's 2 or 3 of the changes -- market changes that PJM has filed at FERC. We expect another to get filed. And then with the strainer review of the curve itself, there are some opportunities there if it's done in a positive fashion. But we're going to have to see the results actually of what FERC approves. And it's important for us to see that FERC understands the issues that are in play here and that they obviously make wise decisions on what that market reform should be. And certainly, this is its first round of -- the 2 or 3 filings that have been made by PJM will be instructive in terms of what FERC's mood is relative to market reform. Dan Eggers - Crédit Suisse AG, Research Division: I guess, just one last question, Nick. Just on -- Greg asked about residential load, but commercial also looking pretty flat for '14 versus '13 with sustained GDP growth and that sort of thing. Is there a potential that, that number will start to spruce up, or are you just not seeing kind of the growth construction or commercial space to give you confidence that's coming back?

No, I think there's a chance it will. We just -- I think one quarter, a trend doesn't make. So we've got to look at the numbers for this quarter that's occurring now, and we'll continue to adjust accordingly. And not just only adjust our forecast accordingly, but adjust our cost structure accordingly as well, and our employees are well tuned in to that process at this point. So this is very much about optimization business now.

Our next question is from Paul Ridzon with KeyBanc.

A couple of questions. At EEI, you kind of indicated that your forecast didn't have any project on the transmission side that weren't pretty ironclad. What kind of upside is there from here from what you've done since then?

Yes. So as you recall there in EEI, we had the presentation of the real projects that are in the plan right now, and then we had this incremental bandwidth above that graph that showed the incremental real projects that are also in hand that we're finding capital for. As you recall, we -- for 2013, I think we moved $120 million of capital over to transmission as a part of our regular ongoing process, primarily from generation, and that's been positive for us. We'll continue to do that to achieve the capital associated with those particular projects that's still well in hand, moving forward very well. And in fact, now, we're in the process of defining a ridge even above that, but that's going to be -- that's going to have to play itself out in terms of our ability to come up with the real projects. We also -- we aren't standing aside on the sidelines with Transource and other activities. We continue to pursue projects outside of our footprint, as evidenced by the -- I know you probably saw that we were 1 of 5 bidders for a Canadian project in the Murray 500 kV project. So all that's going on in all cylinders. And we're very happy with the progress in there, and we'll continue to identify those real projects that can be done.

And then just -- you indicated you're not changing your forecast for gas or power pricing. But I assume it's safe to think that so far in the year, it's been a nice tailwind. In other words, you're not having to go buy power in the east-side markets to fulfill some obligations.

Yes, that's right.

Yes. So most of what we have for off systems, that's for -- particularly for the generation resources side of the business is hedged with its contract to Ohio for the year. So although our units are performing well, demand is strong, I wouldn't want to get -- have irrational exuberance over the fact that it's been cold and prices have been high at this point.

But you aren't that long so you are participating?

What AGR is, and we are participating, but some of our operating companies are having to buy to meet their needs. And we've offered capacity to some of those companies to help fill that need, and some have taken it and some haven't. And we're hoping to get positive resolution to that. But not all of our operating companies are long through this event, but AGR is.

Then lastly, just what your early read on what's going to happen in the next capacity auction? Or is it just too many things still up in the air here to predict that?

Well, I think if the market reforms that FERC has in front of it now, are approved, that could be helpful. Whether it's enough, remains to be seen. And that's something I think that all the generators are looking at in terms of how matured you're going to get around the continued investment in generation for the long-term within PJM. But that remains to be seen. I think some have said a slight uptick. Some have said more than that. But it remains to be seen.

And next, we'll go to Kit Konolige with BGC.

A good number of my questions have been answered already. I was just wondering if you could give us a little more color on, Nick, your equalizer slide, as you always call it.

Yes.

And just go through it again which is improving and which is deteriorating. And also, could you provide a little detail on the transmission spend and why it's -- why there's a lag there and can that be caught up or is that just going to, the lag, going to stabilize and we'll start to see earnings grow with investment?

Yes, sure. So I'll go through it, in terms of the Ohio Power, the 11.3%, that will probably continue to come down slightly because customer switching continues and as part of the Ohio situation. APCo should improve. There is a West Virginia base case that needs to be filed during the year. And then there is also the Virginia by annual case. As far as Kentucky Power is concerned, that's in sort of a middle of the settlement that occurred relative to the Mitchell transfer. Right now, there is sort of a rider in place. But later in the year, our base rate case will be filed that includes Mitchell being moved over. And then, also, as part of that settlement, also some sales revenues come back to the company, 100%. So that's helpful during the interim process. So we expect that to come up. I&M continues to improve. When you get the full value of the rate, and all the rate activities that they've been involved with. I think the last report had 9.1 or something like that, so up to 9.3, which is positive and will continue to improve. That's where we have the legislation for the nuclear life cycle management projects, the environmental projects. So we have a really, really good recovery mechanism there. And then, PSO is in the midst of a rate case. They just filed it, I think, a week ago, a little over a week ago. $45 million rate case and asking for a 10.5% ROE. That's some smart grid activity involved with that. So we expect the positive result there. And then, as far as SWEPCO is concerned, the only lagging part of SWEPCO we have is the portion of Turk that wasn't included in Arkansas retail rates. And that's being sold…

And just one other. To be clear, how much is essentially all of the transmission spend adjudicated by FERC and then passed through the operating companies? Or are there -- is there state-level transmission rate case activity?

Yes, there is some transmission and the operating companies. By and large, most of it is Transco related. It's FERC regulated. And then, of course, Texas is PUCT regulated. So it's pretty straightforward. I mean, we've got the projects. We know what the projects are. They're real projects, and they're just plowing through the process with some favorable recovery mechanisms. So we're particularly happy with where the transmission business is going.

And the final question. Do you have any kind of middle-term, 3-year view on the transmission, earnings contribution and what that's going to mean for where you are in that cone of earnings guidance after 3 years?

Yes. So the high case by '15 is $0.39 a share. And which was, I guess, the original modeling we had have $0.36 a share. So additional $0.03 a share. And then, by '16, we're looking at $0.43 a share. And that they could be upwards toward $0.51 a share. So that's -- and that's based upon those real projects, as I said before. Now if we have incremental projects above that, then there could be additional opportunities there, particularly if some of these projects that we have in PJM that are -- that have been proposed, or the Canadian projects or anything else, that will also contribute beyond what we show and what we did show in the graph back at EEI. But that EEI graph is pretty solid. In that matter, it is solid. And that's pretty solid, it is solid. The issue for us here is making sure we replow the capital back in to get that top side of the transmission, and then also, identify anything beyond that.

And so, just to be clear, if you were to hit the top side of transmission, say, in '15 to $0.39, would that -- would that mean you come in at the top side of that consolidated EPS range?

We continue to hold onto our 4% to 6%. Based upon that original guidance in '13 we gave, that had a 3 15 mid-point. It's a broad bandwidth. And certainly, there's a lot of things that could happen, and ins and outs in the process. So it's sort of difficult to tell at this point. But we'll certainly let you know as it gets closer.

Our next question is from Stephen Byrd with Morgan Stanley.

I wanted to talk a little bit more about transmission. Nick, you had laid out on one of there earlier slides about a 9.5% Transco earned ROE for the year, but there are a number of sort of near-term impacts to that. Wondering if you could just flush that out a little bit more and then talk about, going forward. And then I'll shift to a bigger picture question.

So as far as the transmission is concerned, the TCOS filing is already made. So I think they have a 6 months, is it, to come up with a solution there, I think. And it's sort of -- it's -- actually, we've been very successful with our TCOS filing. So I wouldn't suspect we would have any issues there. And then, really, the return, the ROE of 9.5% doesn't reflect the authorized return at all. We're just getting out ahead and we're intentionally getting out ahead to make sure that we plow as much capital as we can into transmission.

And Stephen, you also remember that our authorized ROE in PJM is 11.49% and in SPP, it's 11.2%. And with the formula rates that we have for those Transcos, they get updated on an annual basis. So the longest lag we have is 365 days and the average is 180. But we're piling so much money into that business right now that there is some lag, and that's being reflected in the 9.5% combined ROE.

So again, when you look at it, we're not too concerned about the numbers, I mean, actually, we're not very concerned at all at this point, the 9.5% because the authorized is there, the recovery mechanism is there, the real projects are there. So we just keep plowing away. And I think we're benefiting from the years that we started this transmission business. And we're reaching the critical mass in our own type of investments. And we feel very good about what we're spending, how we're spending it, and certainly, the recovery mechanisms that are in play. So you'll see -- I mean, I guess, last since last year we've been saying we're going to plow as much capital as we can in the transmission. And when you get out ahead of the recovery mechanisms in transmission, you're doing a lot. And -- but we're happy with the progress.

Nick, your last comment goes to my broader sort of question, when I think about execution risks or transmission. At EEI, you laid out the categories of projects, and many of those looked, honestly to me, as relatively low risk projects. But at a high level, can you talk about execution risk to get to that higher case? What are the key things on your mind when you think about that?

I think there's minimal execution risk. These are actual projects that are on the same thing. We're not gold plating anything. We're focused on refurbishing the grid and enhancing the grid to respond to retirements, generation retirements. RTO-related projects. All those kind of things that are in that plan. And there's a minimal execution risk. As long as we perform well, stay on budget, stay with the projects that we've got and ensure that we're -- we've got the right message in terms of optimization, and the activities we do in transmission are needed. And that's something -- what you're seeing in that list is really needed projects for reliability, not economic projects. Those are additive, if they ever occur. So -- and the other positive benefit is that once again, the diversity of all our states is a positive because we're investing, not only in our states, but the adjacent states. And we've added Kansas and Missouri to Transource. So we have some distinct opportunities in all those jurisdictions and the adjacent areas to really have some tremendous benefits here. And really, ultimately, tremendous benefits for our customers and as well, the optimization of the grid itself.

And we'll go to Paul Patterson with Glenrock Associates.

Just wanted to first touch base on this capacity market rent that you're seeing in the Energy markets. Could you elaborate a little bit on that? I mean, where do you see it going forward with respect to this? And I know it's cold out there and what have you, but it would serve an unusually high prices, it seemed, in some jurisdictions, some zones and what have you. And I'm just wondering if you could just elaborate a little bit more as to what you think is actually going on there in the long-term outlook.

Yes, I think you're right. I think we're seeing higher energy prices earlier than what we thought. We really thought that it really take off when the units that we are running with retirement. We're retiring 7,150 megawatts of coal fire generation, and 89% of that is running now. And if you start to see which we're seeing and economies start to improve, and on the heels, you're trying to retire that generation, you -- I mean, certainly, we expect that energy prices to continue to improve. But this shows to me, it's shows where the real world and the play world collides. And it reflects through in the energy prices. And if the capacity market is not well thought out in terms of enabling investors to invest and advance relative to construction and everything else associated with the grid itself, then you wind up having this kind of thing happened.

Hey, Paul, we've been paying in our market area for gas in the PJM part of our footprint, around $6 in MMBtu for gas. You're seeing PJM prices that are $1,000 a megawatt hour during emergencies, going up to $,1,800 a megawatt hour. Do you think that people being paid those prices are being paid for energy? They're not? PJM is basically paying people for the value of their capacity to keep the lights on. It's not energy that they're being paid for, it's capacity. We need to getting some of those capacity rents back in the capacity auction because PJM is showing the real value of having that capacity when they're willing to pay someone $,1,800 when the price of gas is $6 in MMBtu.

I think if, I remember back in 1984, I was in system operations, and the same thing happened, where you had a very cold winter, caps gets frozen. instrumentation gets frozen, natural gas isn't available and it winds up being an energy prices goes out the roof. And then every one of your coal units and every other resource that you have is brought on the run. And you also have, with cold weather, obviously, coal piles can get frozen. But we haven't run into too much of that. We've been successful in getting through this process. But I think it shows the value of a balanced portfolio. And when that portfolio is no longer balanced, you're going to have additional risks that are placed upon the grid that we really do need to think about. And you brought up a great question that I guess we can talk about all day. But it's clearly a message that I think everyone needs to really focus on the future of the grid and what it actually means to service for our customers.

Okay. I didn't want to take a full day on it because I think you're right. We probably could. But interesting topic. Just back on transmission for a second. I mean, you mentioned that none of this stuff is economic. But do we -- should we expect really no impact on re-rating of the lines, and the improvement on the actual transmission lines in terms of deliverability across regions of LBA as a result of [indiscernible] ?

No, no, we're improving the deliverability. We're expanding the ratings of lines. We are putting in additional transformers. We're putting in additional substations. And a substation, I mean, we're building a substation that cost $250 million. So these aren't small investments that are being made, but they're investments to reinforce and increase the capabilities of the grid itself. and then as well with the generation retirements. There's a lot of planning around additional transmission resources to support those retirements as well.

Right. But I mean, should we think it perhaps there being an improvement in terms of transmission between LBAs at all? Or I mean, in terms of the actual change in the of, I guess, the ability of power to go places where, more power to go into certain areas?

Yes, you'll see it from a reliability perspective. From an economic perspective, it just takes longer to do. Because, I mean, if we cross multi states then you get involved with with cost allocation and the issues between RTOs, and that could be sort of a limiting factor until all of this gets fully rationalized. But ultimately, with the retirements, with the changes in the way the system is being used, it is clear that transmission investment will be a continued positive, at least through the next decade.

Okay. And then just finally on the why a first refusal in order of 1,000. Is there any risk that third parties might compete for this transmission CapEx?

Oh, yes. But a lot of it, a lot of the transmission that we're doing is our transmission project. So when you get into the competitive projects, that's where order 1,000 comes into play. And we think we're well-positioned to compete in that environment because we've been doing it for a while. And so, not only do we have our own projects that are providing the top line for that critical mass, but we also have those other projects that we're competitively bidding that now we're seeing success in.

Hey, Paul, what you see in our forecast for transmission spent in earnings, is not subject to Rover. Those are projects that we control, that we have the ability to invest in that are not going to be taken from us by someone else competing for it.

And that included those incremental projects that we showed on top as well.

Our next question is from Steven Fleishman with Wolfe Research.

Just, I think Brian mentioned, in his remarks, that prices are a lot higher in near-term than was in your plan, but that you'll be kind of over this multi year period actively managing outages and expenses to kind of stay within that range, roughly. Could you just maybe elaborate? I read that as kind of as you're having a really good period, you'll use that to invest more to benefit kind of the future periods. Is that...

Yes, you're right.

Yes, Steve, obviously, as we're working our way into '15, '16 and '17, and you and others have identified some of the shortfall that we have associated with the transition in Ohio, and then the RPM pricing that we're facing, we're going to be doing things, like moving outages around during that time period, maybe pulling some forward, if we find ourselves a bit hot on earnings in an earlier period, maybe pushing them out into the '17, '18 timeframe. And we're really going to be managing our way through this to a very high degree as we work our way through to make sure we stay in that cone that we've identified. So if we come in -- if we see things particularly hot, whether it's weather or pricing, in 2014, we might pull some outages or expenses out of '15, '16 into '14' to help us manage our way through that process. So I think your description of it makes me think that you understand very well what we're doing.

And that's a process that we've put in place here that I think is working just extremely well. It not only gets capital to transmission, but it also enables us to move projects from one year to another into the year. And that's really a positive process for us that we put in place. It's worked very well. We continue to look at it. We look at numbers on a pretty regular basis to ensure that we're managing the year in the proper fashion. We'll continue to do that. Because, as you all have pointed out, this '14, '15, '16 years are critical for us, particularly '16, because of the capacity markets. But we're managing to it. And so far, we're doing very well.

Okay. And just, in 2014, what is your specific savings in pension and OPEBs? I know that's within your O&M budget. But just that specific line, what are the savings versus '13?

So let me give you some detail on that. '13, and you talked about 2 different things, Steve, we'll talk about the pension costs and then the pension expense, okay. So the cost for '13 was $114 million, and the expense ended up coming in being about $64 million, okay, the O&M expense. And then we're forecasting for '14 the cost to be about $84 million. And we're anticipating that the expense will be about $52 million. So the difference year-on-year, the $64 million to the $31 million, is about $33 million.

And we'll go to Brian Chin with Bank of America.

Just given the recent weather, and a little bit of how the current situation is unfolding. Can you give us some color on cold days of inventory on hand? And does this prompt you to think that there might be some changes to how you head into the contract of season for cold later this year?

Yes, typically, we pull down inventories during the winter months. And we've been on the order of 30 to 35 days on average for just about the whole year. I think it was at the top, it was around 40 days. And it's down to 30, 35 days, and we're fine with that. And we'll be very sensitive about how much additional coal procurement we do as a result. We have a pretty flexible system. And some -- well, and all of our contracts are pretty flexible. So we feel pretty good about where we're at now. I don't think -- we don't have any changing conditions or requirements that we're placing on our coal buying efforts because of the weather. We're just performing as we thought we would.

We've got more cold than the country has cold right now. We're good to go.

And our next question is from Anthony Crowdell with Jefferies.

I have a question on, Nick, save the slide, the equalizer slide. And just 2 part. Where do you think the ROEs could go or where do you think is the normalized level of ROE? And what type of sensitivity could you give us, say, for every 50 basis point change in this regulated operation ROE. We could see the $0.10 improvement in earnings or something?

Yes. So I think we look at the equalizer chart I like for it to be with the 10 handle on it. And certainly, we'll -- we said long-term. And we're looking around 10.2, 10.3, in that range. And you're seeing in sort of a quarterly perturbation of a lot of activity that's coming into play here. So as long as it just stays in that range, we're in good shape. And Brian, you got anything you want to add.

I don't, Anthony. We could get you some type of sensitivity for across the system what the 50 basis point change in overall ROE would be, we can get that for you.

And we'll go to Jonathan Arnold with Deutsche Bank.

Quickly on rate. So 2014, you had the EEI of 1 97 penciled in, now it's 1 75. Is that change any things that came in lower or lower assumption on the things you haven't yet got?

'13 came in a little bit higher. The difference is a little bit lower.

So it's basically the '13 starting point?

Yes.

Yes.

Great. And then secondly, just coming back to this demand question and in the context some of your comments about sort of managing within the curve. I mean, you did take down the residential forecast to this year by, I think, 80 basis points and commercial by 90 in what's, less than 3 months. So are you genuinely seeing that much more concern versus what you're seeing in November? Or is this a little kind of conservatism to offset other stuff?

Yes, so you asked us 2 different questions with the same answer. The answer for your prior question is the same as this one. '13 came in a little bit higher.

We'll move to Michael Lapides with Goldman Sachs.

Yes, 2 questions unrelated. First, on the transmission side. We've seen in the MISO and in New England dockets where interveners are seeking lower transmission base ROEs. If same things happens in some of -- whether it's the Southwest Power Pool, whether it's in PJM, how -- what do you think that tipping point is where we change or, I don't know, you're incentive or your desire to be a sizable investor in transmission in the U.S.?

I think, as long as transmission is, at a premium or equal to the state rates, we're in good shape. And I think, clearly, there is an incentive being placed on building transmission. We're happy with that. And if -- really, once again, the FERC needs to send some messages here that from a policy perspective that we want to continue building transmission in this country. And as long as that premium is at or above the state rates, then we're in good shape.

FERC was clearly, Michael, looking to attract a capital into this space. And what they've done with their ROEs has done exactly what FERC wanted to happen. So as long as they, as Nick was saying, as long as they continue to send a signal that they want increased investment in this area, we'll respond to that signal.

Okay, I think it's good -- I think, it continues to be part and parcel to the overall grid expansion that's going on in the resilience of the grid. And there's going to continue to be spin regardless. The question is, do you really want to satisfy that precursor of transmission being build out to respond to the generation retirements and so forth to optimize the grid so that you can do that as a prerequisite and then focus on the rest of the underlying system. That's what key. I think you got to get through this transitional process we're at in this industry. So transmission needs to be incentivized in that regard because that will provide the greatest benefit in terms of resiliency of the grid, but also in terms of the optimization of the resources that are attached to the grid.

Got it. And just looking at your non-transmission investments. So the jurisdictions where you have -- distribution and/or generation right base. Where do you see the greatest year-over-year changes in capital spending? Where do you see kind of a slowing of capital spending?

Incrementally more, Michael, in the OPCo T investments across our system is where we're seeing significantly more investment. We're also seeing increased investment in our Cook Nuclear Power Plant and associated with some of the environmental investments that we're having to make to be responsive demands by 2015. So those are general areas where we're seeing incremental investment.

Yes, I think we're $3.5 billion to $4 billion on the environmental spend now over the period. And then, when you look at the other capital that we're spending, it's block and tackle spending that typically is recovered from a regulated standpoint. So we're sort of in a position where we're not having to build a large central station generation, but we are able to focus on Transmission and Distribution investments that are clearly beneficial to customers. And customers actually see, and that's a positive.

And we'll go to Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: My question is on Page 11. It appears there that probably, half or more of your expected pretax earnings improvement by 2016 will be driven by generation and perhaps, a quarter or less by distribution. When I think of the Generation segment, that's obviously one that's transitioning the combination in environments of $60 per megawatt day capacity prices. Distribution, on the other hand, is probably, I would imagine, half of your rate base, half of your O&M. A lot of that at utilities that are under earning. Why -- I'm wondering if you can give me some color on the SKU of these earnings improvements towards generation and relatively strong contribution from Distribution?

I think it’s just a matter that your generation typically has to the big ticket items that can be adjusted. And when you look at consumables for a scrubber, the way that all of the parasitic load operates within the plant. Certainly, the way that you contract for the activity is associated with it, particularly in terms of use of contractors versus use of employees, all those types of things are substantial within the generation framework. And there, again, generation sort of functions each plant, functions as its own profit center. And so, doing that, it can focus more readily on the benefits associated with optimization of how they operate. And from a distribution standpoint, it really is a matter of outage scheduling, management with the customers, the processes that are in place that goes back through the organization. So it's probably, at least in our view, when you reach from the customer side of things, you want the distribution side to be very robust in terms of the way that it operates to provide the customer experience that we're asking for. From a generation side, that's all done sort of as a back-office function and it contributes heavily to the benefits from an OEM perspective, but also from a capital perspective. And that's our expectation as we get through this. Nuclear, that process hasn't been through lean activities. They start the lean activities. obviously, we're very careful because Nuclear is different. But it's a heavy capital and OEM spend. And there are opportunities for optimization there as well. So I think we've got the right balance when you look at generation. And then when you look at Transmission and Distribution together, you're -- we're on par.

And to the presenters, we have no further questions in queue.

Okay. Well, thank you all very much.

Yes, thank you for joining us on today's call. As always, the IR team will be available to answer any additional questions you may have. John, can you please give the replay information.

Certainly. Ladies and gentlemen, this conference is available for replay. It starts today at 11:00 a.m. Eastern will last until February 3, 2013 at midnight. You may access the replay at any time by dialing (800) 475-6701 or (320) 365-3844, and the access code is 313839. That does conclude your conference for today. Thank you for your participation, and you may now disconnect.