American Electric Power Company, Inc. (AEP) Q1 2012 Earnings Report, Transcript and Summary

Charles E. Zebula - Senior Vice President and Treasurer Nicholas K. Akins - Chief Executive Officer, President and Director Brian X. Tierney - Chief Financial Officer and Executive Vice President Robert P. Powers - Chief Operating Officer and Executive Vice President David M. Feinberg - Senior Vice President, General Counsel, Secretary, General Counsel of American Electric Power Service Corp, Senior Vice President of American Electric Power Service Corp

Greg Gordon - ISI Group Inc., Research Division Dan Eggers - Crédit Suisse AG, Research Division Paul T. Ridzon - KeyBanc Capital Markets Inc., Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Jim von Riesemann Anthony C. Crowdell - Jefferies & Company, Inc., Research Division Stephen Byrd - Morgan Stanley, Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Steven I. Fleishman - BofA Merrill Lynch, Research Division Ali Agha - SunTrust Robinson Humphrey, Inc., Research Division Andrew Bischof - Morningstar Inc., Research Division

Ladies and gentlemen, thank you for standing by, and welcome to the First Quarter 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to Chuck Zebula. Please go ahead.

Thank you, Linda. Good morning, and welcome to the First 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 remarks are Nick Akins, our 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, Chuck, and thank you, everyone, for joining us today on AEP's First Quarter 2012 Earnings Call. It has been a great quarter for us, I think. From an overall viewpoint, AEP has done very well in terms of financial performance. We delivered GAAP ongoing earnings of $0.80 a share, which is positive, given some significant headwinds of the mild weather, low natural gas prices impacts on all systems sales and the Ohio customer switch. The story demonstrates the value of the diversity of AEP's service footprint and our ability to control costs to respond to these headwinds. Industrials continue to improve, while commercial and residential still struggle. I think it's an indication of the economy and how much of an issue it is with the recovery of the economy at this point in time. And I think as we progress, though, there's some fundamentals within AEP's service territory, primary metals and oil and gas activity, that are contributing to positive success for our territories. With that said, we can't reaffirm guidance because of the significant area of risk involving the Ohio situation and the transition to competition, which I'll discuss in more detail a little bit later. With the Ohio risk, we're still committed to our long-term strategy we've set out for you on February 10 namely: Movement to competitive environment, we will continue to move to that competitive environment in Ohio. We're embracing it. We support it with the corporate separation that goes along with it and the formation of our competitive generation in retail and marketing functions. Our investment, our regulated businesses, obviously, will continue as well. Our focus on the growth aspects and repositioning of the company around transmission and other growth areas will be significant. The dividend strength is still provided and secured by the regulated businesses. And we have a continued commitment to the 4% to 6% long-term earnings growth rate that we've discussed in February 10. The transformation or our generation resources, in response to the market and EPA mandates, is going to be an opportunity for us because we will deploy capital to do that, and we've seen the latest EPA rules, and Mark McCullough and our generation area certainly has worked out a capital path that makes sense for us going forward. So we have made progress in the first quarter on several fronts. On March 7, we issued $800 million of TCC transition funding bonds, an attractive average interest rate of 2.28%, which compared favorably to similar recently priced deals. Proceeds of the bond issue were used to fund the capital program, reduce TCC debt and contribute to the pension, which is now 90% funded. On March 8, we completed the acquisition of BlueStar Energy, the retail organization based in Chicago that participates in deregulated retail markets and provides energy services such as DSM type activities. Integration of BlueStar with AEP retail is progressing very well and is on schedule, and we now have over 100,000 customers and growing quickly in that area. I'm pleased with the progress in our reposition of the transmission business. Earnings from transmission continue to improve, and with the recently announced Transource JV with Kansas City Power & Light, Great Plains Energy, and our continued formation with Transco's in our service territory, we continue to deliver more near-term projects to achieve the critical mass for future growth. Transource is an addition to the capital plan. We believe that it was a great project for us. It shows that critical mass in near-term on the joint venture, although there's not much spend in the first 2 years. It really does pick up in '14, '15, '16. So that graph that we provided for you back in February that had sort of a dampened look toward the later years, as we represented, was really based upon firm, known projects with little risk, and we wanted to show it that way. And now, with the addition of Transource, you're going to see that portion of it sort of kick up in those later years that is shown in that graph. So that's important for us to start that critical mass and see that transmission investment continue to grow. The reason why we did the Transource deal was to pursue competitive transmission development projects in the advent of Order 1,000 for -- certainly wanted to set the tone for a comparative transmission going forward, and it was important for us to really put together an engine for that future growth. And we saw, certainly, from the Great Plains perspective, a near-term project that could provide an ability for us to put that critical mass in place and really give us an advantage going forward in the marketplace in the competitive access area. And it also is on the interface of MISO and SPP, so that provides some future prospects for us. And as well, it focuses on other state footprints like Missouri and Kansas. So overall, it was a very good thing. Great Plains is a great partner for us and one that we're happy to have involved with the transmission business with us. Our generation transformation activities continue into the market in EPA rules. We now have 4,600 megawatts that'll be retired over a time period, really detailed by the EPA rules end of 2014. But that could change based upon the extension years and also could change because of the markets. So we're staying pretty flexible when the retirements would actually occur based upon a resolution of some of those issues. But the 4,600 megawatts is a little different than the 6,000 megawatts we had mentioned to you previously at the time of the February 10 deal that we had 6,000 megawatts. If you take out 4 and 5, which we've already retired, and then the Big Sandy activity, that gets you in the 4,600-megawatt number. So -- but the current view is, is that, from a capital standpoint, there's a capital plan worked out, even with the aggressive EPA schedule. And certainly, we want to be able to mitigate costs to our customers as much as we can during this process. So we continue to be active on coming up with legislation that provides for more of a blanket extension of time to really give customers time to make that adjustment. And for us, when we retire these plants, the communities involved, the taxes involved, the socio-economic factors involved need to be dealt with in a very positive fashion. And by replacing generation, by coming up with other alternatives, these communities can adjust to that. And I think that's important for us as we deal with an economy that is where it is today. Turk construction is now 90% complete. We're moving along very well in that prospect, getting Turk done by the end of the year. And rate cases are being prepared to support that investment as well. So I have to admit, while I've been pleased with the progress of transmission, generation and many of our regulated operating company activities, our time has been spent here in the first quarter and before personally consumed by the ongoing events in Ohio, as we move to a competitive environment. I'm sure all of you have followed this closely. And I can't talk too much about what's going on because of the ongoing hearings in the capacity case, but without regurgitating the history of the capacity and ESP cases in Ohio, I'll give you my take on the subject. This is a case where AEP is asking for what other utilities in Ohio have been previously granted, a fair and reasonable transition to competition that maintains the ability for competitors to compete, but maintains the financial integrity of AEP while we unwind some of the commitments that have been made, specifically contracts with PJM for support of FRR-related capacity for our customers and the eastern pool agreement. The agreement that takes the transfer of capacity and energy among the companies in the eastern footprint. We need time to unwind those type of arrangements. And those commitments have been made previously with the concurrence of the commission, and certainly, we'd like to unwind those in a very rational way. The ESP plan that we filed on March 30 balances the interest of what we believe are the 3 main interests of the commission. We tried to be responsive to the concerns related to the previous stipulation and provide a clear path to competition with basically a hybrid of the approach of the stipulation, but adjusted with more Duke-like characteristics, such as energy-only options, leading to an earlier, about 6 months, full option and a transition charge to the retail stability rider. So our plan is balanced in these 3 areas, and I'll call it the 3 C's: Customers, competition and the company. Customer rates have been adjusted to mitigate the concerns of the low-load factor customers with a more moderate application of the rate increases over all classes of customers. And discounted capacity rates have been put in place that allows for competitors to successfully compete. We've shown that customers are indeed switching at the proposed $255 per megawatt day rate. And the company's financial integrity is maintained through the transition period, tied to a utility rate of return that puts us back into position basically at the December stipulation. So if you visualize a triangle with these 3 areas in each corner, there is a balance. And if you move capacity rates down, you're only lining the pockets of the competitor suppliers at either the customer's expense or the company's expense. And if it's at the customers' expense, the retail stability rider has to increase, causing higher increases in customer rates, and that's probably not a good outcome. And if it's at the company's expense, it's tantamount to taking capacity value that the company is committed for a 3-year period to PJM to run and giving it to competitors to subsidize the acquisition of our customers, which sort of seems a little bit un-American to me. It's really not competition, it's more a confiscation. So there is a balance that has been struck with this plan that I would hope the PUC will support. I know there has been much discussion about AEP's legal options, but I would much rather see this case resolved through the acceptable order of the commission so that we can all move forward with clarity around the execution that we spoke of on February 10. The capacity case is ongoing as we speak and the procedural schedule for the ESP case has been established that has oral arguments in early July with a decision thereafter. So it's been a very good quarter considering the headwinds that exists with the economy, and AEP will remain focused on the execution of the areas we've previously mentioned in February 10. Now I'll turn it over to Brian.

Thank you, Nick, and good morning, everyone. This morning, I'll explain the quarter-on-quarter variances to last year's results, provide some color on load and the economy at AEP service territories, give some insight into coal and gas switching, provide an overview of AEP's capitalization and liquidity, and then get to your questions as quickly as possible. Turning to slide 4. For the first quarter of this year, as Nick mentioned, AEP earned $389 million, or $0.80 per share in ongoing earnings versus $392 million or $0.82 per share for the first quarter of 2011. Weather accounted for a negative comparison to last year of $0.12 per share or $87 million. Overall, heating degree days were down 31% versus last year and 29% below normal, as this was the second mildest winter in the last 30 years for the AEP system. Customer switching in Ohio accounted for a negative comparison the last year of $0.06 per share or $42 million. This reflects a year-on-year decrease of total retail generation margin and is associated with AEP Ohio's total retail load that had shop by the end of the quarter of 28%. As you remember, in Q1 of last year, we were collecting provider of last resort charges in Ohio end of June. The loss of Ohio pool of revenues versus last year accounted for a negative quarterly comparison of $0.05 per share or $39 million. On the positive side, Transmission Operations contributed a positive $0.01 per share or $5 million. This reflects increased earnings from Electric Transmission Texas. You will continue to see growth in investment and earnings from ETT and our Transcos, as we put dollars to work to enhance reliability and system efficiency for our customers. Rate changes reflecting increased investment in our regulated utility operations accounted for a positive comparison to last year's first quarter of $0.08 per share or $63 million. Finally, operations and maintenance reductions accounted for a positive comparison to the first quarter of last year of $0.11 per share or $80 million. This reflects a combination of spending discipline in the face of weather and other earnings challenges, as well as the reversal of a regulatory obligation that was previously recorded. Turning to Slide 5, you will see that our weather-normalized residential and commercial sales were lower than prior year, while our industrial sector continues to show improvement, as Nick stated earlier. Overall, weather-normalized sales were down 0.4% for the quarter, reversing a 7-quarter positive trend that was largely driven by the increase in industrial sales. Although our residential and commercial sales were down for the quarter, a number of economic indicators are showing improvement within our service territory. First, the economy and AP service territory is growing faster than the U.S. economy and faster than it did in 2011. Real GDP growth for AEP service territory in the first quarter of 2012 is estimated at 4.4% compared to estimated U.S. growth of 2.2%. AEP's 4.4% growth compares favorably to that of the first quarter of 2011 of 2.8%. In addition, the unemployment rate in AEP service territory is lower than it's been since the start of the recession at 7.9%, and lower than the U.S. unemployment rate for the quarter of 8.2%. We noted that earlier this week, the 4-week moving average for U.S. unemployment claims rose slightly. We hope this is not a new trend for an economy that has been showing signs of improvement. The employment growth rate for AEP's footprint was better in the first quarter of this year than it was for all of last year, with employment growth in the West part of our seen system at 2.3%, beating the U.S. rate of 2.1%. Employment growth for the quarter in the East part of our system was only 1.5%, but still exceeded the growth rate for the region for last year. Contrary to this positive economic data, we should note that AEP's combined east territory's residential customer count was down 0.2% for the quarter, but that was more than offset by a combined west residential customer count that increased 0.6%. We are hopeful that the economic outlook will continue to improve and translate into improved electricity sales in the near term. Turning to Slide 6, we're looking at the top 5 sectors in our industrial customer class. Primary metals, AEP's largest industrial sector, is up 4% for the quarter-on-quarter period. If you exclude Ormet, our largest customer, which returned to full production in the first quarter of last year, primary metals were up 1.2% quarter-on-quarter. Chemicals and mining were both down for the quarter, but both sectors have shown quarter-to-quarter volatility throughout the recovery. The paper industry, as a whole, has been slowly declining over the past several years. As more aspects of our daily life become paperless, this trend is likely to continue. In addition of the sectors depicted on this slide, the transportation equipment manufacturing sector, AEP's seventh largest, is up 5.5% quarter-on-quarter and is being driven by improvements from a number of customers located primarily in the Indiana and Michigan and SWEPCO service territories. This corresponds with the fact that U.S. auto sales in the first quarter were the highest they've been since before the recession. The oil and gas extraction sector, AEP's ninth largest industrial sector, is up 6.7% quarter-on-quarter and is being driven by developments in the shale gas areas of our service territory, primarily the Eagle Ford development in Texas and the Marcellus development in the east. These increases are coming mostly from gas processing facilities, some of which have come online and others of which are still in development. Turning to Slide 7, I want to talk a little bit about the coal-to-gas generation switching that has occurred on AEP system and the outlook for the future. First, it is easy to see that coal-fired net capacity factors had decreased, while gas-fired net capacity factors have increase. This result is more pronounced in the east part of our system, where natural gas capacity is 14% of the total versus the west, where it is 62%. In the east, net capacity factors for natural gas units increased to 47% in the first quarter of 2012 from 22% in the first quarter of last year. Coal-fired net capacity factors correspondingly had dropped to 47% from 61%. The result is even more pronounced when we focused on our east combined cycle plants, which reached net capacity factors of 78% in the first quarter of this year, up from just 17% from the same period last year. If you were to exclude the new just [ph] and combined cycle facility, which came online at the end of January of this year, the east combined cycle capacity factor climbs to 85%. East combined cycle generation increased fully 149% quarter-on-quarter. So what does all this mean? With our east combined cycle fleet operating at such a high capacity factor, we would expect the rate of coal-to-gas switching to remain about the same through the balance of the year. That is, most of our combined cycle gas units are running close to flat out. With our gas consumption and cash generation up, and with the mild weather that we've experienced, our coal inventories have climbed to 45 days full burn inventory at the end of the quarter from 39 days at the end of last year. We expect inventories to climb over the second quarter. And just as we manage our inventories during the recession, we'll continue to do so now. All of that being said, our coal needs for 2012 are fully hedged and our needs for 2013 are about 80% met. Slide 8. Let's take a look at the company's capitalization and liquidity measures. First, GAAP total debt to total capitalization remained unchanged from last quarter at 55.3%, but the quality of that metric has improved as we added $800 million of AAA-rated debt to the balance sheet, as we executed our Texas Central securitized debt offering in March. Securitization financing reduced costs to TCC's customers versus traditional financing and brought a significant cash contribution to AEP. In addition, in February, SWEPCO issued a $275 million 10-year unsecured note at an attractive rate of 3.55%. Second, at the end of the first quarter, our credit metrics remained solidly BBB. AEP's FFO to interest coverage stands at 4.7x and our FFO to total debt is at 20%. During the quarter, fixed reaffirmed AEP's ratings and Moody's reviewed and left unchanged their ratings for the company and several subsidiaries. Turning to liquidity. Our sources included our core revolving credit facilities and cash on hand, which, together, totaled approximately $3.5 billion. Our uses of liquidity include a commercial paper and letters of credit, which, together, totaled approximately $500 million. When netted against one another, the company's liquidity at the end of the first quarter was nearly $3 billion. Lastly, our pension obligation was funded at 90% at the end of the first quarter. This is an improvement from 86% funded at the end of the year in 2011. As our pension funding approaches 100% through improved investment returns and past significant corporate contributions, we are derisking the investment portfolio. At the 90% funded level, our portfolio asset targets are 40% equities, 10% alternative investments and 50% fixed Income. As you can see, the platform is strong, as we seek a positive ESP order and transition to retail competition in Ohio. As Nick noted earlier, due to uncertainty in our Ohio regulatory outlook, we are unable to affirm our previous earnings guidance for 2012 at this time. As a management team, we are committed to an earnings growth rate of 4% to 6% and a dividend level supported by our regulated earnings. Thank you for listening today. And with that, Linda, I'll turn it back over to you to take questions.

[Operator Instructions] And our first question comes from the line of Greg Gordon from ISI Group.

I've got a couple of questions. First, can you comment on the staff position that was recently filed in your capacity case, which I know is separate from your ESP filing? I know that they made some opinions on what they felt was sort of a fair capacity rate. And while I know that that's completely independent from the ESP case, I'm wondering if we can take anything from that as it might be -- as the ESP case unfolds?

Yes, well the capacity rate that came out was actually pretty reasonable, it's the adjustments, I guess, that there's some concerns with. And we expect to get their work papers here Friday, and that'll be helpful to us in terms of determining how exactly they came up with those numbers. But since that case is -- the hearings are ongoing now, I'd be hesitant to speculate on it. But certainly, we'll review that and see what the effect will be.

Right. Because it appears that they come to the conclusion that your sort of Tier 1 capacity rate seems reasonable, but they didn't opine on the level of your sort of Tier 2 -- what a Tier 2 capacity rate might be? Is that fair or unfair?

Greg, I think the 145 that they netted to is clearly below what we'd view as acceptable. I think the 255, which is -- and they had something close to that on an adjusted basis before they took some adjustments that were probably overstepping is probably closer to what we'd consider to be reasonable.

Okay, great. And then the second question, where do you stand in your current pending FERC filing? And when is the expectation that we might or might not get a decision on that case?

On the FERC capacity case, you mean, Greg?

Yes, correct.

Well, that capacity case is in, and we're waiting on the FERC response to it. And we're obviously unable to tell when FERC would actually render an order, but the case certainly is there and ready for them to render an order.

And next we'll go to the line of Dan Eggers from Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: I guess there's so much going on in Ohio in the quarter as far as ESP on and off. Can you just help detail what would've gotten picked up in first quarter results from kind of the ESP plan and what the reversals were kind of around costs and that sort of stuff that affected the first quarter results?

So Dan, obviously, we've detailed what the customer switching is, and that's reflective of current capacity prices that are in play. There was some pickup in Transmission Operations on Slide 11, as we picked up some of the -- they're paying us for generation and transmission. And some of that migrates to line 11 or -- I'm sorry, the transmission line on Slide 11. And then, of course, we noted a, in O&M, a previously recorded regulatory obligation that has to do with about the $35 million partnership with Ohio Component. So it's really those pieces. It's the customer switching and the partnership with Ohio Component. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And I guess, Nick, you talked about comfort with the environmental CapEx plan, the CapEx plan. With the amount of your coal-to-gas switching you guys are seeing and the lower run rate on the coal plants, are you reevaluating that plan one more time before making any firm decisions, given the lower economic value presumably?

Yes, Dan. We continue to look at the options that we have available to us. And obviously, we've committed the capacity in PJM. So it's a matter of how much we have to -- you have to utilize those units. And obviously, they're being utilized less. As Brian said, the capacity factors are much lower. So that gives us some optionality in terms of how the units are operated during the year. And then in terms of retirements, we're looking at the dates associated with those as well. You have the -- and really, it's a question of whether you need the capacity and does it stay online into 2014 or 2015 or even 2016? But if the gas market is lower and capacity becomes available, then we'd have to look at those options as well. So we are looking at that on a regular basis on what those options can be. I was just saying that in the worst case, it appears that we're okay from a capital perspective. And then, if we do get extensions or if we decide to convert to gas in some fashion with gas burners or whatever, we'll have that optionality to do it. So, really, it's a capacity and an energy question. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And I guess, Brian, just one last question on the cost management. Of the 80, the 35 was the reversal and kind of 45 was your better cost management. Is that something we can continue to expect will happen on a quarterly basis for this year? Or were there some things that kind of pulled up that we'd assume more of a normalization in cost?

Absolutely, Dan. I think you've always heard from us that if whether in our system sales and regulatory aren't coming in as we had forecast they would for the year, and all 3 of those things are true for this year, that we would manage our O&M accordingly. And so we are currently in the process of, A, having cut some significant components of O&M ,but we're in the process of evaluating how we might do that more aggressively, not just for this year, but really, as Nick has talked about in the past, trying to reposition the cost structure of this company for the competitive environment that we're moving into.

Yes, I think that's one basic tentative of the February 10 discussion we had around capital and O&M discipline in response to the environment that we're in. There's no question that where we're at in the economy and as we follow along with that, along with the other issues that we have ongoing, we have to be able to be flexible from that spending standpoint. We're -- and again, it's in the overall context of that repositioning of the company to those growth areas. And we are very focused on, during this year, working on those activities. So we want to reinforce resources for those growth areas. And certainly, at the same time, evaluate the rest of the organization and make sure we're being as responsive as we can to the operating companies, which really goes to the operating company model.

And next, we'll go to the line of Paul Ridzon from KeyBanc.

When you talk about your residential and commercial being down on a weather norm basis, is that being distorted by shopping at all, or is that deliveries versus kind of generations sold?

Paul, that's total connected load. So it's not being distorted at all by customer switching.

And then, you're $0.06 negative on switching. I think you've got $0.21 in the budget that you've laid out in February 10. Are we running to plan?

Quarter-to-date, Paul, we are. But so much of that depends on what happens with this ESP case, and particularly, the capacity case. And if we get a negative outcome on the capacity case, and we go to something that looks like RPM, that could significantly accelerate shopping. And so the run rate for the year, given the uncertainty that we face after June 1, is something that's certainly in question. And we wouldn't anticipate that you could just extrapolate the year-to-date numbers and come up with a reasonable outcome with what the capacity case gets resolved at.

And then lastly, when you say you're 80% hedged on your coal buy for '13, that assumes the same kind of fuel mix as you're kind of laid out in the first quarter?

Yes, that's the same kind of fuel mix, I think, and 80% hedged. That -- it's give or take because you're obviously looking during the year at what the actual coal requirements are going to be. So we continually -- and we're becoming more flexible in terms of our coal contracting to ensure that we do have the flexibility if natural gas prices continue to be low, which we expect they will, that we'd be able to respond from a contractual standpoint.

Is building your coal piles more a function of weather or fuel mix?

I think it's both. Weather and -- it's weather and natural gas prices. Because one of -- I guess, one of the beauties of our system, we bought 5,000 megawatts of gas in the last few years, or built 5,000 megawatts and it gives a lot of flexibility in terms of if you have low gas prices, they're competing on a marginal basis with coal-fired generation then we can make those adjustments. What we're having to change, obviously, is sort of this black swan event of natural gas prices and making us think about what the future coal contracting provisions will be so that we ensure that they're flexible because there was always an assumption that coal is going to be lower than natural gas. Well, that's not the case, so we need to be flexible on both sides.

And now, we'll go to the line of Jonathan Arnold from Deutsche Bank.

Can I ask first on the sales numbers in Q1? Obviously, the weather was particularly abnormal and then there's negative nearly 3% number you have normalized in residential. Is that -- how confident are you that that's kind of a good reflection of the real underlying usage or the weather models is sort of thrown off by a very unusual winter?

Jonathan, it's hard to tell at this point. If you look at that chart on Slide 5, you'll see there's some -- been some pretty extreme volatility in that residential number Q-over-Q. Second quarter of last year was up 4.4%, and then it went to moderately negative in the third quarter. So I think until we see a trend that we can hang our hat on, we really need to watch that data. We don't see anything that is a give up the ghost on the residential customer account or usage for us. But obviously, we're watching that. We'll continue to watch that quarter-to-quarter. We don't like seeing it down 2.8% versus last year. But as you stated, it is an extreme weather year, and making sure that our weather normalization calculations are right when you have such extremes as we're having right now. And to be frank with you, as we have last year, you really need to watch the trend over time.

So you're kind of leaving the full year forecast where it is until you get a little better sense of the rest of the year?

Absolutely.

That's right. That's right. Because even in today's Dispatch, I think there was a -- Columbus Dispatch, there was an article on housing sales and housing prices moving up. So it's a very sensitive part of the economy right now, and when you look at it, we've had industrials. And as long as we have sustained industrial pickup, you'll see commercials come back in and residential, obviously, come back in as well. And I think that's going to be a positive for AEP.

Okay. And then if I could on another topic. You talked -- you've obviously talked a lot about Ohio, you talked about positioning for a more competitive future. Can you talk a little bit about competitive activity outside of your territory? How active are you guys able to be, given the amount of focus I'm sure you have at home right now? And obviously, you talked a little bit about the BlueStar integration. But just -- what are you doing strategy-wise in terms of going after margin? And how -- where would you describe yourselves on the trajectory of getting where you business plan needs to be?

Jonathan, I'm pleased with the progress of the integration of BlueStar. And they are also participating in Illinois markets, participating in other markets as well. As I've said earlier, though, we want to make sure that we're only participating in markets that we understand. And that would be primarily MISO and PJM-related markets in Texas. We continue to pursue the -- getting a name for a company in Texas. You can't name it AEP, apparently, so we have to name it something else but we're starting that business back up. And I think it's important for us to make sure we take advantage of the back-office systems of BlueStar, which is a major, major positive for us in that transaction. And the people of BlueStar, we have been very, very pleasantly surprised that -- not that there was a surprise, but certainly, the people involved have been very good for our business and have mixed very well with the AEP retail people. So all -- as you said, there's a major emphasis right now on movement in the Ohio market and we're going to make sure that, that happens. But also, we'll continue to progress in these other markets as well. So I'm very happy with the progress there. And remember, it's primarily put in places of hedging activity for the anticipated generation to be separated in Ohio. So we're very much getting prepared for that.

You've talked about this as a cost-saving opportunity. But isn't there -- you're not going to have to add a load of people and capability and structure?

No, we've got a pretty significant number of people with the BlueStar acquisition so it really helped us from a marketing standpoint, but also, from the back-office and system standpoint. And we want to make absolutely sure that as we move forward, that our back-office systems are keeping up with the marketing systems upfront so that we ensure the financial integrity of the business. And we certainly believe that there's margins to be made out there. And when you look at the DSM activity and the other energy support services that can be provided, those services provide margins as well. So I'm happy with the way that's progressing to really develop a platform for us for the future. That's one of the silver linings in all this. I mean, I think Ohio certainly wants to move the competition. And we're moving the competition. We support that. And we support it because there's an opportunity, a real opportunity here, to grow the business in a different way. And we just need to make sure there's a transition that makes sense for us to get there, and that's what we fully support.

And next we'll go to the line of Jim von Riesemann from UBS.

I just have a question on clarification. Nick, did you say earlier that you're affirming your 4% to 6% earnings growth? Or were you affirming your strategy to get to that 4% to 6%?

No, we're still affirming our 4% to 6% long-term earnings growth.

How do you get there if you had to withdraw 2012 guidance?

Well, withdrawing -- as far as the guidance is concerned, it really is determinative based upon what the Ohio outcome is so it depends on what base you're starting from. And I think you can still have earnings growth focused on the regulated businesses -- the other regulated businesses, including transmission, distribution, all the operating companies, and also, the additional transmission business. And that's really -- that confirms the growth rates. So that's -- and then, from an Ohio standpoint, you really do have to look at the risk involved where the case is not a normal case. It's something that we're very focused on, and that outcome will be determinative of what that guidance range ultimately lines up being.

And next, we'll go to the line of Anthony Crowdell from Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Just hopefully a quick question. We spent some time in Columbus this week and kind of one of the takeaways of it was when you had another filing of an ESP last week. I think there's 2 other filings on this, capacity preceding. It seems that most of the intervening parties, if not all including the commission, are pretty fatigued dealing with all these ESPs and capacity and everything else. I mean, is this an opportunity for AEP to maybe reach a settlement, maybe the parties, there's some tight budgets there, people don't have the staff. Is this an opportunity maybe for AEP to reach a settlement with interveners regarding ESP and the capacity filing?

I just think we've been at this for over 1.5 years, and there's a lot of people who are fatigued about this case. And we would very much like to get this thing over with. I think if you had a recognition of the other parties involved that yes, AEP does have a transition. Yes, AEP does have a unique situation with its pool agreement and with the commitments made on behalf of the customers in PJM. Those are contracts that we need to get out of. And if given that time, there's an opportunity for settlement. But based upon the last scenario we went through with the stipulation, it's pretty apparent, unless there's some dramatic shift in the positions taken by some of these parties, it's going to be very difficult, indeed, to get a settlement of the parties in this case. I think this is going to be a case where the commission is just going to have to balance the interest involved and make a credible decision. And I think that's key because if they do that, then we get our cases filed at FERC again, we get moving along with all the precursors to move to a full competitive environment with robust competitors. And that's a tone -- a positive tone, that could be set for the state. So I think it's important for that to happen. I'm just skeptical whether there can be a settlement of all the parties that's delivered to the commission this time around.

And next we'll go to the line of Steven Byrd from Morgan Stanley.

Just building on the last question. You've laid out a potential timetable for a resolution in Ohio. Just given what you're seeing today, could you talk a bit about just the factors that could impact that timetable and just general comfort with that timetable, given the latest that you're seeing in terms of discussions?

I think that, certainly, we're committed to trying to get the case over with, and I think the commission has also said publicly that they're focused on getting this case moved along pretty quickly. The procedural schedule is set so that due process could be given to all the parties. But we also know that there is plenty of information that's already been provided throughout the entire case. So I don't think there's anything new. Anybody's going to turn over. There's no new rock uncovered here. So it could give the ability to move along more quickly. I think that -- I'm actually optimistic that the schedule will stay pretty much intact because there's been plenty of time given for the parties based upon the issues that we've already dealt with. I also believe that if you get a reasonable outcome and the capacity case or a FERC orders in the capacity case, it could bring the parties closer together. And I just think that there are some major milestone precursors there, the capacity rate, in particular, that could have a benefit in terms of bringing the parties together. That's also an opportunity for a quicker solution.

And then just following up on a different subject on coal hedging. You have mentioned the you're fully hedged for 2012. Given what we're looking at in terms of the gas [indiscernible] fall. Is there some possibility of potentially being over hedged? And how do you think about flexibilities if you were to need to reduce shipment deliveries that are something where you have to deal with penalty payments? Or is there quite a bit of flexibility here? Can you just talk a little bit to that?

Yes, Steven, we have very good relationships with the coal suppliers that we have, and we're working through areas of flexibility that could exist. Also, from a contracting standpoint, we typically have a varied mix of coal supplies, long-term, short-term, that can be managed. The issue that we have is that you have coal that's specific to specific units and some inventories are low, some are higher. And we're looking at the possibility of moving coals around to the various areas to mitigate the impacts of coal stockpile increases in the event natural gas prices stay low. So all of those kinds of options are being considered and looked at and actively pursued.

Okay, great. And just where you look at today, is there a potential that the hedge level is above the expected usage for the year? Or do you think -- do you see it sort of essentially balanced?

Yes, I think we'll be okay because, obviously, it all hinges on a long hot summer, which is what we usually hope for in this business. But if you have that kind of activity, then we should be fine.

Next, we'll go to the line of Michael Lapides from Goldman Sachs.

A handful of questions. One, we've talked a lot about the capacity case and ESP case. Can you talk about the deferred fuel case? It's a big number, $700 million plus of outstanding deferred fuel balances, I don't remember the exact amount. How are you thinking about both the resolution of that case, whether it's separate from or tied into the capacity and ESP cases? And how you get cash recovering? Meaning, is it securitization? Is it over a long period of time? And also, the impact on the customer bill because that's -- like I said at the beginning, it's a big number.

Yes, of course, we'd like to get it securitized, and I think we have to get through the process to make sure we can do that portion of it. You have the reg assets sitting out there, and then you have the secure -- the fuel sitting out there, the fuel deferral. The reg assets appears to be a pretty clear of the path of the fuel issue we have to get through. But Brian, you may have some more details on that?

Yes, Michael, that's just in Ohio. We have a similar situation in APCO West Virginia where we have nearly $400 million of deferred fuel that we are filing to securitize there. And think we're on a faster track to be able to securitize that close to $400 million than we are in Ohio. In Ohio, the securitization law requires that the fuel case be final and unappealable before you'll be able to securitize. So the amounts that we're looking at in Ohio, we'll probably won't meet that threshold of having final orders until 2013. But we believe we could be there as early as this year in APCO, West Virginia, with that $400 million.

And what's the total balance last deferred fuel plus, the capitalized interest on it, on the Ohio side?

It's about $500 million.

Okay. One other question and a little bit unrelated to the fuel balance items. Distribution case. Is that also still separate from -- and how are you kind of thinking about how that also gets resolved? Are you kind of looking at there's going to be some kind of global settlement and all 4 cases in Ohio come together?

Yes, the distribution case is pretty well done. So yes, so -- and the ESP case really is -- we still have the DRR and those kinds of activities in there. But as far as the distribution case, it's done.

And next, we'll go to the line of Steve Fleishman from Bank of America.

Just on the coal to gas switching data, the -- a follow-up on one of the prior question. Do you see any risk of forced bond of coal? Or you think you have enough flexibility? By the way, you mentioned you don't need to do that?

No, we don't have any risk of [indiscernible].

And then we didn't get there during the depths of the recession and we don't see the problem being as acute as it was then, and so we just don't believe that's even in the cards.

Yes. And also keep in mind, I mean, a lot of our contracts are relatively good compared to market and rail rates are obviously good as well. So the coal that's actually running sits pretty well in the marketplace. And as you go up higher in the stack and with the designer coals and so forth, that's where you run into those kinds of issues. So we're flexible in that regard.

Okay. And I'm also just curious, I realize your western region has, I'm sure, much lower coal-to-gas switching price points. Given that gas has continued to come down, is there a possibility that in the west we see these numbers move much more?

I don't -- you could see some movement but typically, you're constrained on coal in the western footprint. The delivery cost of coal in our western footprint is very attractive because it's PRB coal with a good contract, a good rail contract. So those -- it'll be hard for natural gas to compete on a basis with coal in our western footprint. And then from a natural gas perspective, you have older -- many of the gas units are single-stage units with higher heat rates, so you won't see them run as much as you would, like a new combined cycle facility, for example.

Okay. And then one last question on Ohio. It seems like at this point, the capacity case is going to run and be decided before the ESP. Is that correct?

Well, we don't know the answer to that. It very well could be. But it could be part of the ESP. We don't know at this point.

Okay. So the schedule could get moved out so that they're decided more in line?

Yes. And then you've got to look at what FERC doing as well. So that could play a part in the picture, too.

And next, we'll go to the line of Ali Agha from SunTrust.

Just wanted to clarify the timeline. I know you've talked on that a number of times on this whole Ohio issue. So one thing we do know is that you have temporary relief on the pricing on the capacity that is there until June 1.

Right.

Now you'd asked to expedite the capacity case and the ESP case. Can you say that, that did not play out, or is that still a possibility? They're still looking at things July 3 and beyond. So from your vantage point, can we just lay out a little bit again the chronology of events as you see this play out in Ohio?

Yes, I think you do have a gap there between the end of May when the present capacity rate drops off. And I think -- and you really have to go through the process of what the commission intended to begin with when they put that in place. And our view is, is that, that capacity rate was put in to keep the parties neutral there and dependency of all the -- all these other ESP cases going on. And there have to be, in our opinion, some mechanism put in place, whether we request an extension of the stopgap measure that was put in place or some other methods. So we don't know exactly how that would work out at this point. But certainly, as May rolls around, we see the progress of the case, we'll be making decisions on how we approach that with the commission.

Okay. And also, to be clear on your position on the capacity, Nick, I mean, last time around you guys were okay with the 2 pricing mechanisms where one was the PJM RTO, the other was the fixed 255. I think you, if I'm not mistaken, have little different positions, whether in the ESP or the capacity case. Where now talking about just a non-PJM pricing-related price. So just to be clear, what is your ideal position on how that capacity should be priced during this transition?

I think we have filed the 2-step type approach in the case, and the 140-something-rate was applied to those customers that already said that they would switch through the -- to the November timeframe. And those customers did have already switched based upon that premise would be included, including aggregation. And the 255 was placed there as a discounted rate. It's different, obviously, than the capacity rate that we're after. The capacity case would substantiate the 355 actual cost and we're doing the same thing in PJM. But this is -- the capacity rate, in those cases, are discrete components of a larger case in the ESP. So there's a lot of gives and takes within the entire model of the ESP. So that's where we can go to a 255 and 145 type of application on a tiered approach and it would still make sense in the overall sense with the stabilization charge and those types of things. So that's really the context in which we presented those different capacity rates.

Okay, got it. And I know there's obviously an ongoing process, but any signals or signs that you can share with us to suggest that the commission's views this time around may be any different from what played out last time around?

The only thing I can say is I think we've addressed the hot button points that the commission had expressed earlier. I can't say today where the commission is on the filing that we've made. Only they can do that. But when you think about the low load factor issue, we've addressed that. We've opened some portion up to auction and energy auction, then going to a full auction even earlier than what was originally anticipated. And then also, from the capacity standpoint, I think we've fortified the record to show that switching is occurring at that higher tiered 255 level. So I think we've done the things that we were asked to do. And it's really, like I said, is up to the commission to decide now.

Fair enough. And last question, also just clarifying your previous statement, so if I'm -- on the EPS outlook. So if I'm clear, what you're saying is, once you've concurrently on the commission that the '12 guidance, you'll come out with a new number. But off that, whatever that number is, regardless of what the outcome is, do you still believe '12 through '15, 4% to 6% EPS growth is doable?

Yes.

And now we'll go to the line of Andy Bischof from MorningStar Financial.

In regards to BlueStar, you mentioned you had about 100,000 customers. Can you remind me what the pace was when the acquisition was announced?

BlueStar had 22,000 customers, as I remember, and then AEP retail...

About 40,000.

Yes, about 40,000 customers. So they continue to make progress there.

Okay. And BlueStar has pretty significant capacity in terms of servicing customers before you have to add out into that back-end capability, correct?

Oh, absolutely. That's why we acquired BlueStar. And really, they have some of the best information systems relative to retail operations that we've seen, and we obviously looked at several.

Andy, they were building that business for a much bigger scale than what they had. And the management team over there, before we ever met them, had a very long view of what they wanted to do with that business. And so they've been very thoughtful on how they put their systems together, how they put infrastructure together. And it was that planning and thoughtfulness that we wanted in the management team, and the benefit of their systems and long-range planning that we got with the benefit of the acquisition.

Thank you for joining us on today's call. As always, our IR team will be available to answer any questions you may have. Linda, will you please give the replay information?

Certainly, thank you. Ladies and gentlemen, this conference will be available for replay after 11 a.m. Eastern time today through April 27. You may access the AT&T teleconference replay system at any time by dialing 1 (800) 475-6701 and entering the access code of 243109. International participants dial (320) 365-3844. That does conclude our conference for today. Thank you for your participation and for using AT&T executive teleconference. You may now disconnect.