American Electric Power Company, Inc. (AEP) Q3 2012 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the Third Quarter 2012 Earnings Conference Call. [Operator Instructions] And as a reminder, this conference is being recorded. I'd now like to turn the conference over to our host, Treasurer, Chuck Zebula. Please go ahead, sir.

Thank you, Lori. Good morning, and welcome to the Third Quarter 2012 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 marks are Nick Akins, our President and CEO; and Brian Tierney, our CFO. We will take your questions following their remarks. I will now turn the call over to Nick.

Okay. Thanks, Chuck, and good morning to everyone. And thank you all very -- taking the time to join our third quarter 2012 earnings call. Now I really call this -- these calls, as status calls because we now have a long-term strategy that's been in place since February and we're committed to continuing with that strategy and really describing -- taking the opportunity to describe the steps that we've been taking along the way and moving forward with that strategy to not only redefine AEP from a transformational perspective, but also set AEP up for the future. It's also a discussion of the environment that we find ourselves in. And -- but most importantly, what we're doing about it. Notwithstanding the derecho that certainly had an impact on our service territory, I guess multiple storms during that period of time were close to 1.8 million customers over 2 weeks. When you have that kind of customer mix with those storms, it certainly has an impact on what the electric supply was during that period of time. But notwithstanding that, there's no doubt that it was a challenging quarter. In the past couple of years, the accelerator's been pushed on the -- to the floor on the industrial recovery in our service territory, and it's gradually been letting up quarter-by-quarter. Until now, this quarter, we're finding that the foot's off the accelerator. Fueled by primary metals in oil and gas activity, we've made great progress in the recovery after the recession. And now we find primary metals faltering once again due to the soft international demand, primarily in the aluminum area while certainly, oil and gas activity continues to progress. So our industrial load dropped for the first time in 9 quarters about 3.1%. And half of that was probably in Ormet here in Ohio, where 2 pot lines were taken off-line. So it does show that sensitivity around aluminum prices. In previous quarters, the industrials were compensating for residential and commercial load decreases. And now we see commercial customer growth still continuing to improve. We saw that for the first time in a few years last quarter, commercial improvement, that continues. But as we said earlier, the economy is tenuous at best, and we really do have to be concerned about the issues involved with that. And now we're seeing probably the end result of 2012 year-to-date load growth profile being essentially flat for the year. So 1 quarter doesn't make a trend, but we have to be concerned. As anytime we see a slowdown in economic activity, certainly issues such as international market conditions, needed tax and regulatory reform and the need for a coherent energy policy are factors that must be resolved to spur investment and enable a recovery. We're hopeful that after the election, we can make some progress on those fronts. As Brian will discuss later, despite load growth challenges and the continued loss of Ohio-related revenue due to the movement to competition, we delivered near-consensus earnings in the quarter of $1 on a GAAP basis per share and $1.02 operating earnings per share for the third quarter, and $2.55 and $2.59 per share, respectively, for the 9 months year-to-date. How do we overcome the challenges that I just discussed? Well, I think it goes back to the February discussion that we had. Diversity of the AEP system is something that's very positive for us. We not only have been controlling costs, which we've done a great job of, we have various other jurisdictions that have produced rate increases. So certainly, when you look at the strength of AEP, it is in that diversity that we keep talking about. There's no sense of whining about the economy. It is what it is. But we can, and do, adjust to provide a level of discipline that the market expects. We know that when the economy truly begins to recover in a sustainable fashion, the diversity of our system, of our customer mix, the fundamental resources such as shale gas, which is prevalent in our operating footprint, will enable AEP to continue to reach our growth potential. So we remain committed to our long-term strategy as discussed with you in February 10 of this year, and I've talked about it in all the quarterly earnings webcasts as well, but I'll reaffirm it here. Certainly, our notions have been around these issues, movement to competitive market in Ohio with corporate separation and the formation of our competitive generation retail and marketing functions. Number two, investment in our regulated businesses and the focus on ROE optimization. Number three, a focus on growth aspects of the business such as transmission. And then four, to reaffirm to you our commitment to be a regulated utility going forward. The dividend strength that we have is generated by the regulated businesses, and we are intent on maintaining that, that 86%, 14% mix that we've talked about previously, and a continued commitment to the 4% to 6% earnings growth. Transformation of our generation resources is also a key component, particularly in light of EPA mandates and so forth. So as we -- so as far as providing guidance, we anticipate providing guidance after we receive a final order of the Ohio ESP, which we expect, hopefully, by the end of the year. By then, we'll also complete the repositioning study that we've been involved with. So we're anticipating having a February Analyst Day to provide guidance for 2013. At that point, I think the main risk issues that we'll have are really centered around the level of Ohio customers switching and in load growth that we see postelection and so forth. So I think we'll be in a better position, much better position, to give guidance at that point in time. Our operational performance has been excellent. When you look at the things we actually control, we've done an outstanding job. The repositioning study, I'm very pleased with the progress there, we'll be completed by the end of the year. And I'm just pleased with the degree of thoughtfulness that the teams have gone through to achieve the objectives and the progress being made. We've had 2 or 3 sets of discussions with the 5 teams that were working on this thing. And it's amazing to me that you can have substantial process changes that reposition this company for the future and focus on the growth areas. And we wind up providing a level of service that we continue to maintain. So it is a very good progress there and we fully expect to be able to talk more about that when we get to the February timeframe. Transmission has just successfully completed a $350 million debt offering which was fully subscribed. And there was a high degree of interest in it. So it shows that we're moving in the right direction from an investment profile, and we continue to work on our capital allocation to further encourage the growth of our Transmission businesses. We continue to focus on the advancement of Transcos in the various jurisdictions. Now we have 4 Transcos and others are in various levels of ongoing pending actions. So we continue to be heartened by what's going on there as well. Our Turk Plant is moving toward completion. We expect our first coal firing, we had a natural gas firing for startup a couple of months ago, and I was proudly showing the pictures of that. It looks like a gas burner, I guess, I appreciate it more than the others did. But nevertheless, today, we should be seeing the first coal firing. We should see synchronization to the grid of the Turk Plant here in November. And then in December, we'll see it go commercial. So -- and it is a beautiful plant site, being the first ultra-supercritical pulverized coal unit in the nation. And we're very proud of that accomplishment. When you look at it, you wonder why we can't do these things everywhere. The regulatory cases related to that, obviously, getting that commercial operation date is critical for us. We filed the case in Texas and it's ongoing in terms of that jurisdictional recovery there. And even with that following, we still have among the lowest rates in Texas. So I think we stand in pretty good favor there in terms of the placement of that plant and what it means for the future for SWEPCO customers. Other cases, such as the Indiana case, $140 million case filed there. Case hearings have concluded and we expect to have an outcome to that by the end of this year as well. So those things aside, probably one of the main things you're interested in is what's happened in Ohio. During the last quarter, we made considerable progress there. As many of you are aware, the Ohio PUCO provided clarity for our transition to a competitive market by issuing ESP orders, capacity orders and corporate separation orders that enable us to move forward with the FERC filings. And the result of those orders have been positive for us in that we can map out a plan for the future, focus on the filings that need to be made at FERC once again, and also pursue the other state filings on the transfers of Mitchell and Amos to APCO and Kentucky Power. So we're focused on those jurisdictions, and discussions are ongoing in those areas as well. So we'll have 6 filings to make, just as we made last time around the areas of separation of the Ohio assets, transfer of Mitchell and Amos, merging Wheeling into APCO and other termination agreements associated with the pool in the interconnection agreements, in various temporary joint operating agreements and those types of things. So those filings will be made. We anticipate making those filings by the end of October. So we're moving forward step by step in this process to ensure that we continue with the progress that's being made. Also, I'm pleased with the progress of AEP Energy, a form of our AEP Retail business. We put BlueStar and everything else in that business. We now have approximately 150,000 customers. And we continue to focus on margins, not quantity, in a very deliberate, disciplined fashion. So we proceed with separating out our Ohio generation. We'll include that in that part of the business. And I'm very focused on that transition to make sure that it's complete. And I'm very happy to see that, that business continues to progress and they're actually earning their own keeps. That's a great, great story early on in their function. So while the economy continues to be a challenge, we have responded with an unwavering focus and commitment to our strategic plan and the discipline to derive shareholder value and quality customer service. And we're very focused on those steps. We'll be very transparent about those steps as we go forward. And like I said, this is viewed as a status call to let you know that progress has indeed been made and the fundamentals are there in our service territory because of diversity, that this system is ready to go. So I'll turn it over to Brian to give you the details of the third quarter. Brian?

Thank you, Nick, and good morning to everyone. Let's start on slide 4 with the quarterly comparison. Well you'll see that operating earnings for the third quarter of this year were $496 million or $1.02 per share as compared to $566 million or $1.17 per share for the last year's third quarter. Ohio customer switching and the authorized capacity cost deferrals combined for a negative $0.06 comparison to last year's third quarter. In the third quarter of 2011, we recorded a $28 million carrying cost for the TCC stranded capacity auction true-up. Since we securitized this true-up earlier this year, we do not have a comparable amount this quarter resulting in an unfavorable comparison of $0.04. Although this was the fifth one this third quarter in the last 30 years, last year's third quarter was the warmest during that timeframe. This results on weather having a negative $0.04 per share comparison the last year, but it's actually positive $0.07 versus normal weather. Off-system sales, net of sharing, were down $20 million or $0.03 versus last year. Physical volumes and margins were off in response to power prices that averaged 20% below last year, and natural gas prices that were off by over 30%. Trading and marketing results were $5 million lower than last year. Non-Utility Operations and Parent results accounted for a negative $0.03 comparison to last year and are mostly explained by the effect of the drought on our River Operations business. Depreciation and amortization expense increased by $32 million and accounted for a negative $0.04 comparison to last year. This was due to the accelerated depreciation at the Ohio plants that we will retire in 2015, increased depreciation rates on several of our jurisdictions as well as the amortization of the TCC's securitization. On the positive comparisons, jurisdictional rate changes, net of the loss of the Ohio provider of last resort revenues, added $0.03 per share or $20 million compared to last year. Our continued focus on spending, that Nick mentioned several times, resulted in operation and maintenance expenses, net of offsets, having a positive comparison of $0.04 per share over last year. Other, including higher Transco and ETT earnings, added $0.02 per share over last year's third quarter. At this point, I would like to provide an update to the cost treatment related to the June 29 derecho and the 3 smaller storms that occurred during the restoration efforts. The total cost for these storms was approximately $217 million, of which about $62 million were capital and removal costs. Of the remaining $155 million, about $124 million has been deferred for future recovery, leaving about $31 million to be expensed. $4 million were expensed in the second quarter, and the remaining $27 million were expensed in the third quarter. Turning to Slide 5. I will review the year-to-date comparisons. Operating earnings for the 2012 year-to-date period were $1.255 billion or $2.59 per share compared to $1.31 billion or $2.72 per share for the year-to-date of 2011. Ohio customer switching, net of authorized capacity deferrals, accounted for a negative $0.19 per share when compared to last year's year-to-date. Approximately 42% of Ohio's load has switched suppliers versus approximately 10% of load that had switched by the end of September last year. Weather provided a negative $0.16 per share comparison to last year for the year-to-date period. This year's mild winter did not compare favorably with the more extreme winter of 2011. And as previously mentioned, while the summer was warm, it was not as warm as last year. However, when compared to normal weather, 2012 year-to-date was favorable by $0.04. Non-Utility Operations and Parent results had a negative comparison to last year of $21 million or $0.04 per share. This was mostly explained by the drought impacts on our River Operations and by the loss of production tax credits in our Texas wind farms. Depreciation and amortization expenses increased by $101 million or $0.13 per share for the year-to-date period. And the reasons for this are the same as for the quarterly comparison. Year-on-year rate increases from several of our jurisdictions were fully offset by the loss of the Ohio provider of last resort revenues, resulting in no change to the year-to-date period for this category. Continued disciplined spending resulted in a positive year-to-year O&M comparison of $215 million or $0.28 per share. It's important to remember that this line item is operational, and maintenance expenses net of revenue increases to account for rate trackers and other contemporaneous rate mechanisms. The remaining positive year-to-date reconciliation of $0.11 per share is explained by higher transmission earnings, the 2012 reversal of a negative fuel provision from the prior year and a lower income tax rate. Taking a look at retail load trends on Slide 6, you'll see the bottom right hand quadrant that overall, weather-normalized retail sales were down 1.4% for the quarter and are now down 0.3% year-to-date. Before going into the second comparisons, let me provide an overview of the economy in our service territory. On several traditional economic indicators, the AEP service territories outperformed national measures. For example, employment growth for AEP's metropolitan areas was up 2.1% for the quarter, versus national employment growth, which was up only 1.4%. GDP was estimated to grow at 3% for AEP's metropolitan areas for the quarter versus 1.8% estimated growth for the U.S. in aggregate. Our western service territories experienced GDP growth of 3.4% as compared to the 2.6% growth experienced in the western portion of our system. These different growth rates exemplify the diversity that Nick referred to on his comments. Despite these positive comparisons for national indicators, AEP did not escape the realities of a struggling economy. This is evident when looking at the bottom left hand quadrant of the slide, where you can see that industrial sales were down 3.1% for the quarter. This development is of concern because as Nick said, it's counter to the positive industrial load trends from the previous 9 quarters. Industrial sales are now positive 0.2% for the year-to-date period. We'll explore this customer class in a little more detail in the next slide. Above industrial sales, you'll see that weather-normalized residential sales declined. 0.5% compared to last year's third quarter. We believe that about half of this negative 0.5% was attributable to the derecho. While customer counts remained fairly steady at 5.3 million customers, average usage per residential customer declined 0.7% for the quarter and is down nearly 2% for the year. We believe this is related to state and federal energy and efficiency initiatives and to the lingering effects of the economy. The commercial customer class was essentially flat for the quarter and is now up 0.5% for the year-to-date period. We believe that the growth in employment that I mentioned earlier should have a positive impact on the commercial sector in the future. Let's take a look at the industrial sales class on Slide 7. You can see that 4 of our top 5 industrial sectors experienced negative trends for the quarter. Nick referenced the primary metals sector, which was down 9.8% for the quarter and is now down 2.5% for the year. Much of this decline is due to our largest customer which reduced production by 1/3 during the quarter. Excluding this customer, primary metals were down 3.9% for the quarter and 1.4% year-to-date. The chemical manufacturing sector was down 5% for the quarter and is down 2.2% year-to-date. Nationally, chemical manufacturing is at its lowest level since 2010 due to decreases in worldwide demand. Mining, excluding oil and gas, is down in response to coal mine closures related to environmental challenges as well as reduced coal mine production due to low utility demand and the low natural gas prices. On the bright side, petroleum and coal products manufacturing, our third largest industrial sector, was up 6% for the quarter and is now up 6.7% year-to-date. Our largest increase here was in SWEPCO service area where our larger finer [ph] expanded capacity. Other sectors showing growth are transportation equipment manufacturing, our seventh largest industry, which is up 5.3% for the quarter related to strong U.S. auto sales; and oil and gas extraction, our ninth largest industry, which is up 2.6% for the quarter related to shale gas production. Turning to slide 8, you can see that the company's coal capacity factors have decreased on a quarterly and year-to-date basis as our natural gas capacity factors have increased. Overall, our generation from natural gas has increased approximately 50% year-to-date. For our East combined cycle units, the increase in capacity factors and generation is even more pronounced. With the addition of the Dresden generation facility to our Waterford and Lawrenceburg plants, our East combined cycle generation has increased 114% for the quarter and 160% for the year-to-date period. With year-to-date capacity factors for these plants approaching 70% and with the recent increases in the Ford natural gas prices, the ability to realize incremental coal-to-gas switching within our Eastern fleet is minimal. Because of the hot weather, our coal units were in more in the third quarter than in the second quarter and our coal inventory went from 48 days at the end of the second quarter to 45 days at the end of the third quarter. Our target is 35 to 40 days. Our coal needs for 2012 are fully hedged and our needs for 2013 are about 92% hedged, with many units fully hedged. Turning to slide 9, you will find the company's balance sheet, credit and liquidity statistics for the end of third quarter. The balance sheet continues to reflect our conservative approach to financing a company. At the end of the quarter, total debt to total capitalization was 54.6%. In addition, our pension funding status was at 87% and include the contribution of $100 million made in September. Our credit statistics for the trailing 12 months remained strong, with FFO to total debt near 20% and our interest coverage ratio at 4.8x. In addition, our liquidity at the end of the quarter was over $3 billion and is supported by 2 core credit facilities with a total capacity of $3.25 billion. Last week, Moody's published their latest credit opinion on American Electric Power. This opinion positively highlighted the company's diverse stream of cash flows and conservative financing policies, while at the same time, identifying the increased business risk due to the transition of Ohio-generated -- generation to a deregulated market in 2015. We remain committed to managing our balance sheet and credit outlook conservatively as we approach the Ohio transition. On Page 10, you will find a number of upcoming events on our calendar through the first quarter of next year. In the next few weeks, we plan to make filings at the FERC related to our corporate separation plans in Ohio. We believe that making these filings this fall puts us on track to legally separate at the beginning of 2014. These FERC filings on corporate separation will require us to evaluate the accounting recovery of Ohio generating assets. In the past, we have evaluated the recovery of the generating assets in the East generation pool collectively as an asset group. Prospectively, we may need to review the Ohio assets individually. Of interest are the Ohio units that we have previously identified to you for retirement in 2015. We are currently depreciating these units to an end of life in mid 2015. And as of the end of the quarter, those 11 units at 5 plants had a net book value of $284 million. Later this year, we also plan to file with West Virginia, Virginia and Kentucky to seek authority to transfer the Mitchell and Amos capacity to Appalachian Power and Kentucky Power. Also in the regulatory front, we do anticipate a rate order in our Indiana case by the end of the year, and we are hopeful to get the financing orders in Ohio and West Virginia by early 2013, enabling us to proceed with about $700 million in securitizations in the first quarter of next year. Nick mentioned earlier in his comments about the Turk Plant becoming operational later this year, and he also mentioned the cases that will be used to get Turk in the jurisdictional rate base as quickly as possible. Lastly, I'm sure that we'll see many of you at the upcoming EEI Financial Conference in Phoenix. At the meeting, we will highlight many of the drivers of financial performance of the company as well as an update on the company's strategic initiatives. We will not be issuing guidance at that time. Once the regulatory process concludes in Ohio and our orders are final, we plan to host an analyst meeting where we will address guidance, earning and dividend growth, our regulated operations and our competitive platform going forward. Thank you for your time this morning. And at this point, I'll turn the call over to the operator, and Nick and I will be happy to take your questions.

[Operator Instructions] Our first question is from the line of Paul Fremont with Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: I guess, my first question would be that you've made some really good progress on O&M reduction. Can you talk a little bit about where the O&M reductions so far has come from? And can you just generally talk about, based on what you've achieved already, what types of opportunity -- incremental opportunities -- do you think there are?

Yes. So Paul, there's been a lot of activity associated with that. Obviously, we've been very careful as the years have gone by, and this year's no different where we look at operating top of our synergies that exist. But also from an O&M reduction standpoint, there are things that we view as -- typically, we have outages moving in and out. We have other things that occur as a result that changes the nature of the O&M spend. But we make sure that those changes are sustainable going forward. It's not a matter of us not doing something and moving it into next year. We're really focused on making sure that we're able to do it in a sustainable fashion. So what we really have done with the repositioning study is refocus that effort to say that we want to focus on process changes that enable us to make sustainable O&M reductions in the future. And the teams have focused on that -- and just to give you examples, there are areas where there's reporting things that we have done internally that over the years, reports continue to be done, they don't need to be done. Or they can be done in a consolidated fashion, the same report being produced by several business units, for example. Those are synergies that we're looking at and process changes that can occur. On the supply chain side, standardization is certainly a key for us. You'd be surprised how many pairs of gloves, 90 different pairs of gloves that we buy. So it's those kinds of things that we really focus on to try to make sure that we're getting as much O&M reduction as we can, but doing it in a sustainable fashion. Typically, I think you're going to see, on a percentage basis, roughly a 2/3 process-oriented reduction change. And then when you look at changes in spans of control, in terms of organizational realignment, those types of things, and because the process review enables less resources to be performed in one area versus another, 1/3 of that will be more resource reduction types of activities. So it's those kinds of trade-offs that were seeing. But it's very focused on the process side of things first, and then the resources fall out. The reason why we do it that way is because we want to wind up in a situation where if we're trying to expand and grow the transmission business, we want resources to be put into those capital areas where transmission can be built and also produce headroom from a rate perspective where more capital can be deployed. So that's why we're doing it. And I think it's coming along quite well. Paul B. Fremont - Jefferies & Company, Inc., Research Division: And then just as a quick follow-up. In Arkansas, I think you initially got a negative decision out of the Commission, but they're giving you an opportunity to file additional testimony. When do you plan on filing the additional testimony? And do you believe that you're going to be able to convince Arkansas that there's benefit associated with the transaction for customers?

Yes. We expect to get something in early December on that. And I think they've given us an opportunity, obviously, because we have a very good relationship with the Arkansas Commission. And certainly, to give us an opportunity to supplement the record to do additional things, to reinforce our position is a good thing.

And our next question from the line of Jonathan Arnold with Deutsche Bank.

My question's on coal gas but -- and switching and the like. You mentioned that you'd reached a 70% cap factor on the CCGTs in the East and not having much room for further switching. So I guess, firstly, whether you'd expect to see some reversal of the switching dynamic in calendar '13, given current Fords and considering your contract position, which I guess is maybe less of a factor than it was this year?

Yes. Jonathan, actually, we've seen switching going back the other direction. The capacity factors of the gas units are starting to drop. The coal capacity is picking back up. For us, you get in that gas price of $3 to $3.25 per MMBtu, you're going to start that switch to -- back to coal. I think for other utilities, it's higher. But because our mines were located close to the plants and they're mainly -- coal comes in by the river and we have pretty advantageous contracts, it certainly helps us keep in that switchover price lower. So I think it's a very good proposition for us because we are able to move back and forth in that perspective and we have the contractual ability to adjust from that perspective as well. And it really says something good about the ongoing nature of our unregulated business because it will be practically 2/3 are fully controlled coal units. And as well, our gas units, 1/3 gas, will be able to take advantage of those economies as well. So...

Great. Can I just steal a second? So timing-wise, do you have a -- can you give us a sense of when on the sort of forward monthly calendar, you would stop seeing year-over-year increases in gas-fired comps? Is that sort of before year-end or is that some time during the first half of next year?

Well I think, certainly, year-over-year from a gas standpoint, I think we'll continue to see participation from a gas standpoint. I mean gas prices have gone up slightly through this timeframe, but when you look at next year, the strip is still pretty low. And you'll still see coal consumption. But I think you'll still see a conservative amount of gas consumption as well. And it also depends on whether the economy comes back the way it should to fill in the valleys.

And we have a question from the line of Kit Konolige with BGC.

So a quick follow-on, Nick, your comments on -- that the rising gas price now, it may have positive -- if I heard you correctly, may have positive implications for the unregulated business. Are you talking specifically about looking at a dark spread kind of calculation there where earnings and cash flow improve more or less directly with gas price?

Yes. I think, certainly, the dark spread will be critical in that analysis, but also it's -- I think that because we do have advantageous coal pricing, and certainly, the switchover price is lower. And we also have coal units that participate very well in the market. They will have a degree of flexibility there and certainly, the flexibility in our contracting to take advantage of upward [ph] swings whether they go one way or another. So I think, certainly, from our perspective, we look at it. And our coal units are still in the money. Our gas units are clearly in the money because we have newer gas-fired units that are hot in terms of efficiency. So -- and our coal efficiency is still pretty good as well. So I think we're in a good spot there.

Very good. And can you tell us a little bit more about how things are looking at BlueStar and the retail business? I believe you said you're making money there or they're covering their cost or something to that effect. Can you talk to us a little bit about what kind of margins you're seeing in the retail business?

Well, I probably can't comment on the margins, but I can tell you that we are after margins rather than volume. But as far as the integration of BlueStar, the systems integration continues and is in a good place at this point. And certainly, from the effort placed in that business, there's a consistent philosophy of BlueStar and our philosophy, which are one and the same today, that we're participating in many markets. It's not -- I mean, it certainly the Ohio market that's critical for us. But we're also participating in Illinois, Pennsylvania, Maryland and others. And that's one way in which we can hedge this generation in the future, with quality contracts, with customers across the board, so particularly in areas that we understand, like PJMI, so on and so forth. So -- and like I said, they have 150,000 customers. I think that's like a 28%, 29% increase from last quarter, and they continue to make progress. But I -- it really hasn't been a talk about volume increases because, once again, I think we're focused on the margin piece.

Your next question from the line of Neil Mehta with Goldman Sachs.

This is Neil Mehta, in for Michael here. So on industrial demand, how would it have looked in the third quarter if we were to exclude Ormet from the calculation?

Yes. So Brian, you have those numbers.

I do. It would obviously be slightly better. The industrial, overall, would drop to something like 2% negative for the third quarter rather than the 3.1% than it was.

Yes, because we had primary metals which is where Ormet is in. You still had approximately a 9% to 10% reduction in activity on the industrial side, so in the primary metal piece of it. Obviously, it was compensated in oil and gas activity and other things. But when you look at the industrial piece of it, we have to be concerned that either the inventories are catching up or the economy is slowing down to where they're having to drop their consumption. So we're certainly keeping an eye on that, particularly after the election.

And on Ormet, I think regulators said that they can defer some of their electricity payments to you. How should we think about the earnings impact of this deferral?

Well, certainly, we work together with the Ohio Commission on this. And we have a customer in Southeast Ohio that's 500 megawatts. I guess, with the 2 pipelines off, it's 300 megawatts. But they employ 1,000 customers -- I mean, 1,000 employees. So it's pretty important to the economy to keep them going. And certainly, the Ohio Commission has stepped up with us to try to arrange a solution, a stopgap measure to keep them going. And the deferral mechanism the commission set up for approximately $20 million on the deferral, we -- and that's certainly, for us, it's no earnings impact, but we're still deferring that.

Got it. And last question, could you provide some color on the timing and sizing of the securitization in Ohio and West Virginia?

Yes. Neil, in West Virginia, we're talking about $400 million. And in Ohio, we're talking about $300 million. We anticipate getting those orders later this year, very early next year, and anticipate the securitizations for the gross amount of about $700 million in the first quarter of next year.

And we still have outstanding, the other fuel deferral in Ohio, too.

Fuel deferral, and hopefully, a capacity deferral in Ohio as well, to come in later years.

And our next question from the line of Paul Ridzon with KeyBanc.

Talk about the impact of the accelerated depreciation on the merchant assets. I think you said book value was 2.84 and you're depreciating them on -- they'll down to 0 by '15. What's going to happen there? I mean, is this -- are these lives going to get extended when you get an order?

No. I don't anticipate the lives will be extended. What we're going to do is, Paul, we're going to go from a methodology where we used to look at those assets on a collective basis in the East generating pool. And now we need to look at them likely on an individual basis. So certainly, the lives won't be extended beyond 2015 because that's where we have to be in order to be compliant with MATS. There could be some type of impairment that might be associated with those assets. But in any event, we are depreciating them in a pretty aggressive schedule right now and have been since late 2011, when the final MATS rule came out.

And this only applies to the units that we anticipate retiring in 2015. The others are fine.

And our next question is from the line of Ali Agha with SunTrust.

Nick, going back to your opening remarks, when you talked about the goals, et cetera, for the company. You'd again mentioned the EPS growth of 4% to 6% a year. I wanted to just clarify, you talked about the concern on the economy, et cetera. So is that 4% to 6% an aspirational goal? Or should we see, given everything that's going on, that off the 12 base [ph] next couple of years, you can actually generate 4% to 6% a year growth?

No. I think, as we said in February, know that the -- that growth rate, just by the invested capital in the regulated business, will support that 4% to 6% growth rate. So -- and that's things that we -- I think if you look at the capital allocation chart that we had, we used to have a chart in there that had the spend on each area. Much of that's block and tackling and things that we have to do. So when you look at the level of that capital spend and the earnings profile associated with that, they get you in that 4% to 6% range. So -- and then, of course, we're still working on the transmission piece and certainly, very pleased with the progression of transmission in its business case. So I think the issue for us is to define what that base start is when we give 2013 guidance. But we fully intend on the 4% to 6% rate to still be there. And of course, the dividend policy to be commensurate with the earnings growth as well.

All right. Also on the transmission piece of it. You guys have laid out for us a couple of times, I think, in your slide deck, a ramp from '12 to '15 in terms of the earnings contribution. Are those numbers is still solid? Are all those projects now in hand? And you're still confident that ramp is pretty much locked in? How should we think on that?

Yes. As we said before, we're only showing projects that we know are real. And so those numbers are still secure. And we continue to grow the transmission business. We continue to work for ways to allocate more capital in the transmission because there's a lot of projects out there. And when we refocus our staff on the indigenous projects within AEP in the service territory and things that need to get done to benefit reliability for our customers, there's a lot of work to get done. So we're happy with those numbers. And you can look at those as numbers we're going to deliver on.

Yes. And last question, I believe you guys said at the end of September, customer switching in Ohio was 42%. Are the trends so far that you're seeing in switching pretty much consistent with your expectations and also consistent with what was baked into the final ESP order?

Yes. They're a little bit lower than we anticipated. But as this process moves forward, it's difficult to tell how quickly it'll move along particularly when we go to auctions and other things. So it's one of those things where there's 42% there and then there's a queue associated with people switching as well --

About 8%.

About 8%. So it continues to grow.

It's a pretty aggressive switching schedule. I think some of the things that happened with the timing of capacity orders and the like slowed that rate over the summer. But we've seen it pick up since there's been some clarity with the recent orders that the Commission's brought.

Our next question from the line of Philson Yim with Luminus Management.

Just following to that question. I think there was an 8-K filed in July that talked about if you included the queue, you would have seen 45% switching. So that does that mean that you guys are doing better with kind of in the net adds to end up 42% at the end of September?

So that 42%, and additional 8% or 9%, the queue, you're at 50%, 51%.

Okay. So the guys in the queue in July are -- haven't all been processed yet, I guess?

Well -- or there's more in the queue to be processed. I mean, it's difficult to tell. But I'm sure we processed some of them, probably all of those in July, had been processed. But we just have new people in the queue.

Got it. Okay. And that -- so the 42% is a gross number?

42% gross…

Yes.

Of load. And then there's the other 8% that's still waiting.

Right. Have you mentioned what BlueStar is picking up?

No, we have not. And we probably won't mention that either.

And our next question from the line of Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: If I remember correctly, you all mentioned that you'd seen reduction in usage for residential customer this year on the order of 2%. I was wondering if you expected that to continue to decline and possibly accelerate over the next year as the incandescent light bulbs begin to be phased out.

Yes. I think the verdict's still out of that because there's 2 issues there. One is efficiency, obviously, which Brian talked about, and the other is what happens to the economy? And it's yet to be seen, really, what the true effect is. I think you still have growth when you have energy efficiency, if you have an economy that supports the growth. But right now, the denominator continues to decrease because you have both issues occurring. And I fully agree with you, energy efficiency is here to stay. And I think the energy-efficient appliances and certainly bulb replacements, all those types of things will have an effect. But we don't know the effect of the economy in the future, and really, the further electrification of the economy that still needs to be resolved. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: That's helpful. Could I trouble you all to comment on how the regulators of Appalachian Power and Kentucky Power have responded today to your proposed -- the move over the Mitchell and Amos free plants? And how you see those regulatory proceedings playing out over time?

Yes. I think those conversations are going very well. Certainly, there's been plenty of time, based on what we've gone through the last year for there to be a complete understanding of what we're trying to do. The fact of the matter is, though, we're transferring over at net book something that they're already paying for. And certainly, their asset's located within the service territory. So when the states look at it, and typically in the past, they've been focused on FRR, in other words, supplying their own needs for customers and securing a consistent supply for -- price supply for their customers, I think these are fully controlled assets that clearly are in the money and produce value for customers in long-term. So those discussions have been positive.

[Operator Instructions] Our next question from the line of Art Massimiani with Federal Investors (sic) [Federated Investors].

Just a quick question. If you could just give maybe a little bit more color on the dividend. I know you've talked about the dividend policy focuses to be commensurate with earnings growth. And you've talked about 4% to 6% earnings growth. Any color on the payout ratio? I know you're running towards the higher end of 60%. With the increase in your earnings coming from the regulated, could we maybe potentially see that payout ratio go up? Or if you could just give a little bit of color on the growth?

Yes. Well, if you look at the -- just the regulated portion, and you look at pure regulated utilities, that ratio is higher than that, up in the 70% range. So -- but that being said, our Board certainly understands the importance to our shareholders of a dividend policy that makes sense. And when we come out with the February guidance, certainly, our Board will be, as they usually do, look at considerations relative to the dividend as well. So I would not be too concerned about us tapping out at the 60%. That's a guidance that we've put in place ourselves. But we will certainly evaluate our dividend appropriately.

Art, we'd really like to have a complete story around that in February when we talk to the investors. And I think Nick's comments about the Board being committed to rewarding our shareholders with a strong dividend is something that's demonstrated over time, and we'd like to discuss that in more detail in February.

And our next question from the line of Rajeev Lalwani with Morgan Stanley.

I wanted to ask a bit more about the repositioning study and what that's going to encompass, whether it's reviewing your cost structure or your asset mix overall?

Yes, Rajeev. So the study is focused on several areas. Our generation side -- and very heartened by the evaluation there. We manage our practice of those types of things. Over 80% of the plant people are involved in the evaluation of how the plant moves forward. And there are some pretty interesting things that they've come up with. So there are some structural changes in the way the plants operate. And really, the use of contractors and things like that. So which -- that's something that they're looking at. From an IT perspective, it certainly is focused on that piece as well. The finance piece, they're looking at their reporting obligations and all these types of things that -- where the efficiencies lie or certainly, an organizational review is going on as well. But I wouldn't say it's an asset change. Certainly, it could be some capital deployed to make things more efficient in some manner. But most of it is process, pure process oriented, and then looking at spans of control, looking at organizational structure alignment with the new reality of where we're taking the business. And -- but the big issue is to make sure that whatever changes we make are sustainable for the future and with our long-term strategy in mind. And that's -- so -- and that really gets us to a point where we can start to think about -- as I've said earlier, once we go through the steps of -- that we've lined out in our long-term plan to get to a point where we can effectively optimize our asset mix to improve ROE.

Okay. And then just on the asset mix side in terms of maybe unregulated side of the business, it seems like you're still comfortable keeping that longer-term. Or is that subject to change if commodity prices are weaker, capacity prices are weaker?

Well, I think as I said previously, we're going to continue to grow this competitive business. But we are a regulated utility and if we can make it look with long-term contracts, FERC-based contracts, long-term retail contracts, all those types of things that make it appear to be quasi-regulated, in some fashion, either FERC-regulated or otherwise, then -- and it make sense to our shareholders to keep it, we'll keep it. But I would say that we're going to continue to grow the business as if we're going to be in that business, and then we'll make the ultimate determination when the time comes.

We have no additional questions at this time.

Good. Thank you for joining us on today's call. As always, our IR team will be available to answer any additional questions throughout the day. Lori, can you go ahead and give the replay information.

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