美國電力 (AEP) 2012 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the first-quarter 2012 earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session; instructions will be given at that time.

(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 of 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's 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 the significant headwinds of the mild weather, low natural gas prices impacts on all systems sales, and the Ohio customer switching. It 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, though our 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've progressed, though there are some fundamentals within AEP 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 will discuss in more detail a little bit later. But even with the Ohio risk, we are still committed to our long-term strategy we set out for you on February 10, namely, movement to competitive environment. We will continue to move to that competitive environment in Ohio; we are embracing it, we support it, with the corporate separation that goes along with it, and the formation of our competitive generation, retail and marketing functions.

Our investment in our regulated businesses obviously will continue as well. Our focus on the growth aspects and repositioning 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 discussed on February 10. The transformation of 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 in 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 at an attractive average interest rate of 2.28%, which compared favorably to similar recently-priced deals. Proceeds for 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 a BlueStar Energy, a 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 am pleased with the progress in our repositioning of the transmission business. Earnings from transmission continue to improve, and with the recently announced Transource JV with the Kansas City Power & Light and Great Plains Energy and our continued formation of Transcos in our service territory, we continue to deliver more near-term projects to achieve the critical mass for future growth. Transource, in addition to the capital plan, we believe that it was a great project for us. It shows that critical mass in the near-term on the joint venture. Although there's not much spend in the first two years, it really does pick up in 2014, 2015, 2016.

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, as 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 and the advent of Order 1000. FERC certainly wanted to set the tone for competitive transmission going forward. And it was important for us to really put together an engine for that future growth. 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, it is on the interface of MISO and SBP so that provides some future prospects for us. And as well, it focuses on other state footprints like Missouri and Kansas. Overall, it was a very good thing; Great Plains is a great partner for us, and one that we are happy to have involved with the transmission business with us.

Our generation transformation activities continue in response to the market and EPA rules. We now have 4,600 megawatts that will 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 market. So we're staying pretty flexible on 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 Sporn 5 which we've already retired and then the Big Sandy activity, that gets you to the 4,600 megawatt number.

But the current view is that from a capital standpoint, there is 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 socioeconomic 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. TERC construction is now 90% complete. We're moving along very well in that prospect, getting TERC done by the end of the year. 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, my 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 in ESP cases in Ohio, I will 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 dictates the transfer of capacity and energy among the Company's northeastern footprint. We need time to unwind those type of arrangements and those commitments that 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 three 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 auctions leading to an earlier by six months full auction and a transition charge through the retail stability rider. So our plan is balanced in these three areas and I call it the three Cs -- 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 in the position basically of the December stipulation. If you visualize a triangle with these three areas in each corner, there is a balance. And if you move capacity rates down, you are only lining the pockets of the competitive suppliers at either the customer's expense or the Company's expense. And if it's at the customer's expense, the retail stability rider has to increase, causing higher increases in customer rates, and that is probably not a good outcome. And if it's at the Company's expense, it's tantamount to taking capacity value that the Company has committed for a three-year period to PJM to run, and giving it to competitors to subsidize the acquisition of our customers, which sort of seems a little un-American to me. It's really not competition, it is more 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 an 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 the decision thereafter. So, it's been a very good quarter, considering the headwinds that exist with the economy, and AEP will remain focused on execution of the areas we previously mentioned on February 10. Now, I will turn it over to Brian.

Thank you, Nick, and good morning, everyone. This morning I will explain the quarter-on-quarter variances to last year's results, provide some color on load and the economy in 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 to 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 it shot by the end of the quarter by 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 POLR 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 in 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 a reversal of a regulatory obligation that was previously recorded.

Turning to slide 5, you'll 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 0.4% for the quarter, reversing a seven-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 were showing within our service territory. First, the economy in AEP's service territory is growing faster than the US 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 US 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 in AEP's service territory is lower than it's been since the start of the recession at 7.9%, and lower than the US unemployment rate for the quarter of 8.2%. We noted that earlier this week, the four-week moving average for US 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 this year than it was for all of last year, with employment growth in the west part of our system at 2.3%, beating the US 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 territories 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 hoping that the economic outlook will continue to improve, and translate into improved electricity sales in the near term.

Turning to slide 6, we look at the top five 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 paper-less, this trend is likely to continue.

In addition to 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, Michigan, and SWEPco service territories. This corresponds with the fact that US 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's system, and the outlook for the future. First, it is easy to see that coal-fired net capacity factors have decreased, while gas-fired net capacity factors have increased. 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 have dropped to 47% from 61%. The result is even more pronounced if you focus on our east combined cycle plants, which reached net capacity factors of 78% in the first quarter of this year, up from just 17% in the same period last year. If you were to exclude the new Dresden combined cycle facility, which came online at the end of January this year, the east combined cycle capacity factor climbed to 85%. East combined cycle generation increased fully 149%, quarter-on-quarter.

So what does all of 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 gas 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% net.

Turning to 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 offering in March. Securitization financing reduce 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 first-quarter, our credit metrics remained solidly BBB. AEP's FFO-to-interest coverage stands at 4.7 times, and our FFO-to-total-debt is at 20%. During the quarter, Fitch 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 included 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 that 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 able 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 will turn it back over to you to take questions.

Thank you. (Operator Instructions). And our first question comes from the line of Greg Gordon from ISI Group. Please go ahead.

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's completely independent from the ESP case, I'm wondering if we can take anything from that as it might -- as the ESP case unfolds?

Well, the capacity rate they came up with was actually pretty reasonable; it's the adjustments that there are some concerns with. And we expect to get their work papers here Friday, and that will 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 will 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 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. Second question, where do you stand in your current pending FERC filing, and what is the expectation that we might or might get a decision on that case?

On the FERC capacity case you mean, Greg?

Yes, correct.

Well, that capacity case is in, and we are 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.

Okay, thank you, gentlemen.

Yes. Thank you.

Thank you. The next question comes from the line of Dan Eggers, Credit Suisse.

Hey, good morning, guys. There is 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 around cost and that sort of stuff that affected the first-quarter results?

Do you have the data?

I do. So, Dan, obviously we detailed what the customer switching is, and that's reflective of current capacity prices that are in play. There was some pick up in transmission operations on slide 11, as we picked up some of the -- they are paying us for generation and transmission, and some of that migrates to the transmission line on slide 11. And then, of course, we noted 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.

Okay, and Nick, you talked about comfort with the environmental CapEx plan, the updated CapEx plan. With the amount of coal to gas switching you guys are seeing and a 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 to capacity in PJM, so it's a matter of how much we have to utilize those units. And obviously, they are 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 are 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 to 2014 or 2015 or even 2016. But if the gas market is lower and capacity becomes available, than we would have to look at those options as well. So we are looking at that on a regular basis, and what those options can be. I was just saying that in the worst case, it appears we are 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 will have that optionality to do it. So it really is a capacity and energy question.

Okay and Brian, just one last question on the cost management. Of the 80, the 35 was the reversal, and 45 was better cost management. Is that something we can continue to expect will happen on a quarterly basis for this year? Were there some things that pulled out that we would assume more of a normalization in cost?

No, absolutely, Dan. I think you have always heard from us that if weather and off-system sales and regulatory aren't coming in as we had forecast they would for the year, and all three of those things are true for this year, that we would manage our O&M accordingly. 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've not 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 are moving into.

I think that's one basic tenet of the February 10 discussion we had around capital and O&M discipline, in response to the environment that we are in. There is no question that where we are 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. 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.

Got it, thank you, guys.

Thanks, Dan.

Thank you. And next go to the line of Paul Ridzon from KeyBanc. Please go ahead.

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 generation sold?

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

And then, your $0.06 negative on switching, I think you've got $0.21 in the budget that you 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 is 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 without knowing with the capacity case gets resolved at.

And then lastly, when you say you're 80% hedged on your coal buy for 2013, that assumes the same kind of fuel mixes you laid out in the first quarter?

Yes, that's the same kind of fuel mix, I think 80% hedged. It's give or take, because you obviously looking during the year, at what the actual coal requirements are going to be, so we continually, and we are 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 will be able to respond from a contractual standpoint.

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

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

Thank you very much.

Thank you. We now will go to the line of Jonathan Arnold from Deutsche Bank. Please go ahead.

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

Jonathan, that is hard to tell at this point. If you look at that chart on slide 5 you will see there's 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 count or usage for us, but obviously, we are watching that. We will continue to watch that quarter to quarter, we don't like seeing it down 2.8% versus last year, but as you stated, it was 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 had last year, you really need to watch the trend over time.

So you believe in 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 because even in today's Dispatch, Columbus Dispatch, there was an article on housing, 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 will pick up you will see commercials come back in and residential obviously come back in as well, and I think that's going to be positive or AEP

If I could, on another topic, you have talked a lot about Ohio, talked about positioned for the more competitive future. Can you talk a little bit about competitive activity outside of your territory, how active are you able to be given the amount of focus I am sure you have at home right now? And obviously you have talked a little bit about the BlueStar integration but just what are you doing strategy wise in terms of going after margin and where would you describe yourselves on the trajectory of getting where your business planning 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 said earlier, though, we want to make sure 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 even getting a name for the company in Texas. You can't name it AEP apparently, so we have to name it something else, but we are 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 was a major, major positive for us in that transaction, and the people of BlueStar, we've been 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 it AEP retail people. So as you said there is a major emphasis right now on movement in the Ohio market, and we are going to make sure that happens, but also, we will continue to progress in these other markets as well. So I'm very happy with the progress there, and remember, its primarily put in place hedging activity for the anticipated generation to be separated in Ohio, so we're very much getting prepared for that.

You have talked about this as a cost savings opportunity but isn't there -- are you not going to have to add a whole load of people and capability and structure?

No, we 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 systems standpoint. And we want to make absolute sure that as we move forward, that our back office systems are keeping up with the marketing systems up front, so we can be ensure the financial integrity of the business. And we certainly believe that there is 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 provided 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 of this. I mean, I think Ohio certainly wants to move the competition and we are moving the competition. We support that and we support it because there is an opportunity, a real opportunity here to grow the business in a different way, and we just need to make sure there is a transition that makes sense for us to get there, and that's what we fully support.

Thank you.

Next we'll go to the line of Jim von Riesemann from UBS. Please go ahead.

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

No we are still affirming our 4% to 6% long-term earnings growth.

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

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

Okay, thanks. I just needed that clarification. Thank you.

Next we'll go to the line of Anthony Crowdell with Jefferies.

Hopefully just a quick question. We spent some time in Columbus this week, and kind of one of the takeaways was we had another filing of an ESP last week. I think there's two other filings on this capacity proceeding. 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 are some tight budgets there. People don't have the staff. Is this an opportunity for AEP to reach a settlement with intervenors regarding ESP and the capacity filing?

I just think we've been at this for over a year and a half and there's a lot of people with fatigue 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 is 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 interests 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 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.

Great, thank you.

Next we'll go to the line of Stephen Byrd with Morgan Stanley. Please go ahead.

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

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 can begin with 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 turnover. There's no new rocks to uncover here so it could give you the ability to move along more quickly.

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 in the capacity case or 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 to 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.

Thank you. Just following up on a different subject, on coal hedging, you had mentioned that it's fully hedged for 2012. Given what we're looking at in terms of the gas curve being involved, is there some possibility of essentially being overhedged, and how do you think about flexibility if you were to need to reduce shipment deliveries, et cetera? Is it 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?

Stephen, 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 could managed. The issue that we have is that you have coal that is 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.

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 see it essentially down?

Yes, I think we'll be okay, because it all hinges upon 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.

Thank you very much.

Thank you, and next comes from the line of Michael Lapides from Goldman Sachs. Please go ahead.

A handful of questions. One, we've talked a lot about the capacity case and the 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 in ESP cases, and how you get cash recovery? 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 fuel sitting out there, the fuel deferral. The reg assets appears to be a pretty clear path. 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. I think we are 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 amount that we're looking at in Ohio probably won't meet that threshold of 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 left? 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? Were you looking at there's going to be some kind of global settlement in all four cases in Ohio coming together?

Yes the distribution case is pretty well done, and the ESP case really is. We still have that DRR and those kinds of activities in there but as far as the distribution case, it's done.

Okay, thank you.

Next, we'll go to the line of Steve Fleishman, from Bank of America. Please go ahead.

Thanks. Just on the call to gas switching data, following up on one of prior questions. Do you see any risk of force [darn] of call? Do 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 force darn.

Okay.

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 in even in the cards.

Also, keep in mind, all 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 with the designer coals and so forth that's where you run into those kinds of issues, so we're flexible in that regard.

I'm also just curious, I realized your Western region has, I'm sure, much lower coal to gas switching price points. Given that gas is continuing to come down, is there a possibility that in the West we see these numbers move much more?

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. It will be hard for natural gas to complete on a basis with coal in our Western footprint. And then from a natural gas perspective, you have older -- many gas units or single stage unit 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 that capacity case is going to run in 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 a part of ESP we don't know if this point.

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

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

Okay. Thank you.

Next we'll go to the line of Ali Agha, from SunTrust. Please go ahead.

Just wanted to clarify that the timeline, I know you talked that about 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 capacity that is there until June 1?

Right.

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

Yes, I do think you have a gap there between the end of May when the present capacity rate drops off, and I think, 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 that capacity rate was put in to keep the parties neutral, their independency of all these other ESP cases going on. And there have to be, in our opinion, some mechanism put in place, whether we are requesting an extension of the stopgap measure that was put in place, or some other method. So we don't know exactly how that would work out at this point, but certainly as May rolls around, we will see the progress of the case, we'll be making decisions on how we approach that with the Commission.

And also, to be clear, on your position on the capacity. Last time around, you were okay with the two pricing mechanisms, where one was the PJM RTO, the other was the fixed 255. I think you, if I'm not mistaken, have a little different positions, whether the ESP or the capacity case, where now you're talking about a non-PJM pricing related price. 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 two-step type approach in the case and the 140-something rate was applied to those customers that already said they would switch through the November timeframe. And those customers have already switched based upon the premise, would be included, including aggregation and the 255 was placed there as a discounted rate. It is different than the capacity rate that we are after, the capacity case, we are substantiating that 355 actual cost, and we are doing the same thing in PJM. The capacity rate in those cases are discrete component 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 this is 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 could say is that I think we the dress 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 to auction, an energy auction and then going into a full auction even earlier than what was originally anticipated. And then also from the capacity standpoint, we fortified the records that show that switching is occurring at that higher tier 255 level, so I think we have done the things that we were asked to do, and it's really, like I said, it's up to the Commission to decide now.

And last question, just clarifying your previous statement, on the EPS outlook, so if I am clear, what you are saying is once you got clarity on the Commission that the 2012 guidance, you will come up with a new number but off that, whatever that number is, regardless of what the outcome is, you still believe 2012 through 2015, 4% of 6% EPS growth is doable?

Yes.

Got it. Thank you.

Thank you, Ali. Okay, one more question.

Thank you. And that will go to the line of Andy Bischof of Morningstar Financial. Please go ahead.

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

BlueStar had 22,000 customers, as I remember. And then, AEP retail, about 40,000 customers, so they continue to make progress there.

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

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 in how they put their systems together, how they put their 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 was the benefit of the acquisition.

Great, thanks so much for taking my call.

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 11.00 AM 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 access code of 243109. International participants, dial 320-365-3844. Those numbers again are 1-800-475-6701 and 320-365-3844 with the access code of 243109. That does conclude our conference for today. Thank you your participation and for using AT&T Executive Teleconference. You may now disconnect.