美國電力 (AEP) 2012 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the second 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. (Operator Instructions).

As a reminder, this conference is being recorded. I would now like to turn the conference to our host, Treasurer Chuck Zebula. Please go ahead.

Thank you, Josh. Good morning and welcome to the second 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 today for opening remarks are Nick Akins, our President and CEO, and Brian Tierney, our CFO. We will take your questions following their remarks. I will now turn the call over to Nick.

Thank you, Chuck Zebula. Overall we had another good quarter for AEP. We produced GAAP and operating earnings of $0.75 and $0.77 a share respectively, and brought our year to date earnings to $1.55 and $1.57 per share respectively. So it turned out to be a pretty good quarter for us.

As Brian will discuss in more detail a little bit later, our service territory really continues to show progress did, although very tenuous, in the economic recovery. We continue to see industrial growth driven by primary metals and oil and gas activities. But we're now also seeing commercial growth for the first time in years.

Residential continues to lag, so we're hopeful the economy will continue to improve and show that sustainability, particularly from an industrial standpoint, manufacturing as well as moving into the commercial side of things and then residential will pick up as well. So hopefully this economy will continue to make progress.

I know that everyone's focused on the election year this time of the year, and hopefully we will have a return of optimism that will permeate through the economy that we deal with.

Looking at the quarter, it really does show the discipline of cost control and the diversity of the AEP system to overcome the challenges, and particularly with AEP Ohio, but also the POLR charges and customer switching. You know, Ohio has not been a good story for AEP over the last year or so, but we're working really hard to turn this around. All of our other state jurisdictions have improved over last year, but as you all know, all eyes are on Ohio and very focused on August, which we believe is August 8.

Before getting into Ohio and other issues, I want to reiterate that our strategy that we put before you on February 10 is still intact, and it really does bear repeating. The major issues that we're focused on is certainly movement to the competitive market in Ohio with corporate separation and the formation of our competitive generation retail and wholesale trading and marketing functions. Now that is going to be key for us to execute for in the future, after we get this August 8 order.

Investment in our regulated businesses. We will continue to invest in our regulated business as we've just described. Just that investment will provide for continued investment commitment to the growth of 4% to 6% from an earnings perspective.

And we will continue to focus on growth in our transmission business as well, and repositioning that business around the critical mass to make sure our earnings are provided near term as well as long-term. And that dividend strength certainly is secured by the regulated businesses as we go forward as well.

So as we transform ourselves, certainly we will transform from a resource perspective as well. Generation resources in response to the EPA and certainly from the products of natural gas and other fundamental conditions out there will continue to change. But we're very focused on providing plans to really emerge as a more diversified fleet as we go forward.

So, as we looked at some of the issues that we deal with during the year, it became apparent that these basic strategy components remain a focus. And it will really enable us to look ahead to the execution that is necessary to reposition the Company for the future.

I have been CEO for about eight months now, and have been fortunate to preside over two of the most damaging storms in AEP's history -- one what I would call a regulated storm and the other a weather-related storm. Let me cover the weather-related storm first, which I've never heard of before -- the storm actually occurred, a super derecho, which occurred in late June. I've never heard of it, but I'll certainly focus.

During the day it was a 10% chance of thunderstorms. Well, that was a pretty damaging 10%. Six of AEP's states from Indiana to Virginia were affected, some 1.4 million customers, and an additional 300,000 customers were affected in the follow-up storms that ensued.

We marshaled crews from our Western footprint, certainly from the indigenous operating companies that were affected, but also all over the country from California and elsewhere and Canada as well to support the restoration efforts. I'm very proud of our response. And our management team, including myself, visited with crews working throughout our various states to make absolutely sure that the necessary resources were dedicated to restoring power to our customers. Working for almost 2 weeks, 16-hour days in almost 100-degree heat was an extreme challenge that I'm confident we performed and executed well from an operational and a safety perspective.

The storm was expensive, approximately $230 million, much of which will be deferred from [future] recovery as Brian will provide more detail on a little bit later. But it is -- in an odd and perhaps morbid way, it gave the management team a brief reprieve from the challenges of the other storm that occurred, the regulated storm we call Ohio. So, let's talk about that one.

These clouds are starting to clear up as well. The capacity order of the PUCO demonstrated a couple of major points. The Commission is focused on providing competitors the ability to compete quickly for customers by putting in place RPM pricing provisions.

And they're also focused on the financial integrity of AEP, evidenced by the capacity cost being set at $189 per megawatt day, with a deferral mechanism to be resolved in the ESP filing. That is the first step.

So after a significant belly blow in February, AEP is back on its feet and have taken the first step. Now comes the important part, the second step, to demonstrate that we're walking again before we run.

The August order, we presume, will come out August 8. That order for the ESP will need to define several key issues. The deferral mechanism for the capacity cost delta from the RPM rates; the level of the RSR, the rate stability rider, to ensure the financial integrity of AEP; the distribution investment rider; and we'll also need to define the start of the recovery of the deferred fuel that has been on the books for quite a while.

The other major issue is corporate separation. We will need to get the approval for that and we expect that as well.

Overall, we need to address the financial needs of AEP Ohio and the ensuing corporate separation to ensure the credit quality and the cash requirements are met for the emerging entities. You can't start a generation company with a fistful of deferral IOUs. We must have cash as well to solidify the balance sheets of the gen co and AEP Ohio going forward.

So, make no mistake; AEP is focused on emerging from this storm with a financially secure company and a clarification of execution to move toward a competitive market in Ohio.

The development of our retail effort continues to move forward positively. I recently visited our team in Chicago, the former BlueStar team, and they are very focused on advancing the retail efforts, but they're also focused on margins. That is one key issue.

I'm not interested in signing up every customer we can sign up. I am interested in marsh margins associated with that because we are providing a hedge, ultimately, for the generation that is separated, so we want to maximize value associated with that. So, now we need the structural pieces of the unregulated generation fleet to fall into place so that we can effectively hedge and compete so this supply -- and as we discussed with you all in February, so for AEP all of our sights are set on moving forward.

We continue to see 4% to 6% long-term growth, dividends supported by the regulated companies and do not foresee the issuance of equity during this transition. We're not likely to issue guidance until after the Commission renders an order on any rehearing request, so by then, we may be looking at '13 and '14 projections. But I have a feeling you all are looking at that already anyway.

So with all that said, we do continue on a very positive path in other aspects of our long-term strategy as well. Our transmission efforts continue to move forward.

As examples, as we are now turning dirt on some significant projects. We have a cell substation in Ohio that is a $239 million investment, a $200 million project in Indiana, another $200 million in major projects throughout our Transco's as well as the Prairie Wind construction is now turning dirt. So we're starting that process of construction that really can provide the earnings growth for the future.

You know, we're very disappointed in order yesterday regarding the Pioneer project. Both the technical and factual basis, we believe, was not fully recognized in the order. The new line doesn't even interconnect with NEPSCO, only Duke and AEP.

And you can't interconnect the AEP 765 KV into NEPSCO's 138 KV system. Technically that just doesn't work very well. And we have a substation pretty close to that that is accommodating to 765 KV. So, really look at those factual issues that needs to be revisited.

Overall the decision really sends a wrong message to promoters of transmission solutions. So we're evaluating our options on this as we go forward, but certainly we will make our position known both publicly and probably through filings as well.

However, this doesn't impact the AEP earnings forecast for transmission, because as we described earlier, we're repositioning the transmission business to focus on short-term as well as long-term projects to provide the critical mass for earnings growth. So we had plenty of projects to take its place. That project management discussion we had earlier, along with the amount of projects that are being placed in the near-term perspective from a Transco and other longer-term projects perspective, we'll be able to certainly focus on entering this path and secure that for the future.

So we spend so much time on Ohio we forget there are other state regulatory matters that are moving forward. Our Indiana rate case, the $170 million rate case, has concluded its hearings and we expect an order by the end of 2012.

Intervener exceptions are due August 15. We have submitted our version of what the order should look like, so we will look to that toward the end of this year.

The Turk ultra-supercritical pulverized coal station is now 92% complete. And we're looking forward to the first firing of the boilers so that we can move on with getting that unit operational and into rates in those various jurisdictions.

Also, we continue our focus on further developing our EPA response plans. We now estimate our capital spend to be approximately $6 billion. It could be a little bit higher than that, but nominally $6 billion over the next five or so years to accommodate the retrofits and retirements of our generation facilities.

We continue to be focused on legislation to provide for a two-year extension so that we can ensure reliability and reduce the cost of compliance. It makes a lot of sense for our ultimate customers and the economy in general.

And lastly, I will talk about our repositioning study. We have engaged McKenzie and Associates to work with us on our plan to refocus our business on growth and efficiency of operations, and enable us to continue to prioritize our business functions around the OpCo model and the growth engines of transmission and the development of competitive businesses. Our growth will continue to be fueled by the regulated business, but we must optimize our cost structure to enable more investment earnings growth.

We expect to conclude this study by the end of the year with a sustainable process and organizational value that begins in 2013. So, again, all eyes are on August 8, we assume, and then we expect expedient and deliver it -- execution and progress towards the strategic goals that we have discussed. And now I will turn it over to Brian.

Thank you, Nick. Turning to slide four, operating earnings for the second quarter were $370 million, up $18 million from the prior year's level of $352 million. This resulted in earnings per share of $0.77 for the quarter, an increase of $0.04 per share from the second quarter of 2011.

In summary, the favorable effect of lower O&M expense was partially offset by an increase in the impact of customer switching to alternative electric suppliers in Ohio. The quarter-on-quarter detail shows a decline in earnings per share of $0.08 related to the level of customer switching.

In addition, this year's results were adversely affected by last year's October unfavorable decision [on remand] from the Public Utility Commission of Ohio related to POLR service. Last year's results included POLR revenues while this year's do not.

These unfavorable drivers were more than offset by lower O&M expense and favorable other items. O&M expense was down for the quarter adding $0.13 per share to earnings. The lower O&M reflects decreased plant outage work and lower storm expenses compared to 2011.

In addition, the unfavorable [goals] in O&M spending reflects management efforts to maintain tight controls on spending across the organization. The $0.04 per share improvement in other items reflects the favorable effect of a partial reversal of a 2011 fuel provision in Ohio.

At the beginning of the call, Nick mentioned the devastating storms that hit our eastern service territory beginning on June 29. In addition to being destructive, the storms were also costly.

As Nick said, current estimates of the storm's total cost are about to $230 million spread across our eastern operating companies. We believe approximately $70 million will be classified as capital and will be recovered in various future rate proceedings. Of the remaining $160 million of O&M, we believe we will ultimately be able to defer for future recovery up to $130 million.

We recognized $4 million in expenses related to this series of storms in the second quarter, leaving an estimated remaining expense for the third quarter of about $26 million.

Turning to slide 5, operating earnings for the year-to-date period were $759 million, up $15 million from last year's level of $744 million. This resulted in an earnings per share $1.57 for the year to date, an increase of $0.02 per share from 2011.

Similar to our discussion of the second quarter results, the year-to-date results reflect favorable lower O&M expense offset by the effect of customer switching in Ohio, the unfavorable POLR decision and mild first-quarter weather. In detail, weather adversely affected the year-on-year results by $0.12 per share. While the weather impact in the second order was comparable, the effect of the mild winter throughout our service territory is evident in the year-to-date results.

Customer switching for the first six months of the year has lowered earnings by $0.13 per share. By the end of June, 34% of AEP Ohio load had switched to alternative suppliers.

The effect of the unfavorable POLR decision adversely affected earnings by $0.10 per share. On the positive side, rate changes in net of POLR have supported earnings by $0.07 per share.

O&M expenses are favorable by $0.25 per share, driven by lower spending related to plant outages and our overall efforts to control costs. Finally, other items added $0.05 per share to the results, largely due to the partial reversal of the 2011 fuel provision in Ohio.

On slide 6, you will see in the bottom right quadrant that weather-normalized total retail sales were up 1% for the quarter and 0.3% for the year-to-date period. The growth is coming from sales to the commercial and industrial classes, while normalized residential sales continue to struggle.

Before I get into the period variances by customer class, let me give you an overview of the economy in our service territory. We continue to see economic improvement, although the growth is not easily evenly distributed across our service areas.

One of the best indicators of relative strength of a local economy is employment growth. Over the past three months, employment growth in AEP's metropolitan areas has increased 2%, which is better than it has been over the past year and stronger than the 1.4% employment growth for the US in total.

The employment situation remains weaker in our eastern service territories, where there are approximately 91,000 fewer jobs than before the recession began and the unemployment rate is 7.9%. That being said, employment growth in our East region is up 1.8% over the past three months.

Job growth in our Western service territory has been stronger. Over the past three months employment growth in our Western region has been 2.3% above last year. Current numbers indicate there are 17,000 more jobs than when the recession began.

The strongest improvement has been in Texas, with job growth of 2.9% over the past 12 months. And current employment numbers indicate there are 26,000 more jobs now than at the pre-recession peak.

Now let's look at the customer classes. The industrial sector posted the ninth consecutive quarter of growth since the recession. Industrial sales are up 1.8% for the quarter and 2% for the year, driven by strong activity in the oil and gas and transportation equipment manufacturing sectors. I will talk more about this in more detail in the next slide.

On the top right of the slide, AEP sales to commercial customers grew 1.6% for the second quarter and are 0.6% up for the year. Commercial sales growth closely tracks employment growth. The employment growth we discussed earlier is driving the recovery we are experiencing in this class. Not surprisingly, commercial sales have been stronger in our West region, and especially in Texas, where the job growth has been the strongest.

AEP's weather-normalized sales to residential customers were down 1.9% for the quarter and 2.4% year to date. Part of this is driven by customer counts. In our eastern service territory we have approximately 4000 fewer customers than we had last year.

Our Texas property has experienced a notable increase in residential customer counts. This was related to strong employment and population growth.

The chart on page 7 shows the growth in industrial sales for our five largest sectors. As you can see, year-to-date growth in primary metals is 1.4%, yet sales to the sector declined in the second quarter. Our largest metals customer was still ramping up to full production during the first quarter of last year. More recent data shows that the primary metals sector has stabilized at roughly 75% of the prerecession level.

Also on this chart, you will notice that sales in the petroleum and coal products sector have been improving, with sales up 8% in the second quarter and 7.1% for the year-to-date period. While growth in this sector has been solid across our territory, there was a major expansion at a refinery in East Texas that drove much of the growth much of the growth for the quarter.

Besides the sectors shown on the chart, we are also seeing impressive growth in a couple of other sectors. Oil and gas extraction sales are up 1.3% for the quarter and 3.9% year to date.

In addition to new customers, several existing customers have expanded their current operations. Most of these expansions are related to the shale gas activity, particularly in our Wheeling, West Virginia and Texas territories.

The transportation equipment manufacturing sector, which represents 4.2% of the Company's industrial sales, has also demonstrated a significant increase of 10.9% for the quarter and 8.7% for the year-to-date period. This improvement is related to US auto sales, which reached the pre-recession annualized levels earlier this year.

We have experienced load growth at existing automotive manufacturers in West Virginia and Louisiana. In addition, drivers in the US are maintaining and not replacing their vehicles as often as they used to. This has resulted in growth of some of our motor vehicle parts manufacturers, especially in Michigan and Ohio.

Turning to slide 8, you can see that as the Company's coal capacity factors have decreased on a quarterly and year-to-date basis, our natural gas capacity factors have increased. For both the quarterly and annual periods, our generation for natural gas has increased approximately 80%.

For our East combined cycle units, the increase in capacity factors on generation is even more pronounced. With the addition of the Dresden generation facility to our Waterford and Lawrenceburg plants, East combined cycle generation has increased 250% for the quarter and 181% for the year-to-date period.

With year-to-date capacity factors for these plants approaching 70%, the ability to realize incremental coal-to-gas switching within our Eastern fleet is reduced. This switching, and the general pricing environment for coal, natural gas and electricity has led to an increase in our coal inventory from 45 days at the end of the first quarter to 48 days at the end of the second quarter. This is about 6 days more inventory than at the end of the second quarter last year.

Our coal needs for 2012 are fully hedged and our needs for 2013 are about 90% hedged, with many units fully hedged.

On slide 9 you will see that our balance sheet, credit metrics and liquidity remain strong. Our debt to total capitalization has remained fairly constant over the last three quarters and currently stands at 55.2%. Our FFO to interest coverage and our FFO to total debt remain solidly BBB for a company with AEP's business risk profile.

The Company's net available liquidity stands at $2.8 billion and is supported by two large credit facilities which mature in June of 2015 and July of 2016. That being said, there are some pending developments that could impact the credit quality of Ohio Power Company. Specifically, the capacity case allows for the deferral of the difference between $189 a megawatt day and the RPM price.

It is our belief that the ESP order will address the recovery mechanism for the deferral of these costs in addition to other items. Unfortunately, at this point we do not know how or when the deferral will be recovered. Both timing and recovery are important items in determining the credit outlook.

The credit risk for Ohio Power has been outlined by all three rating agencies. Earlier this month, S&P issued a bulletin immediately after the capacity order stating that while there are no immediate effects on ratings, they consider deferrals of changes in capacity prices to be unsupportive of credit quality, because cash flow would decline and could result in financial measures inconsistent with the current rating. We have informed stakeholders about the importance of supporting investment-grade ratings for Ohio Power.

In addition, the balance sheet for this Company is able to absorb some level of deferrals, especially if we're able to begin recovery of our deferred fuel costs and securitize our existing regulatory asset balances. These last two items will be credit-supportive. There are likely to have positive and negative items to appear on the credit score card for Ohio Power, yet the overall tally is not known.

However, our metrics are solid today, and we have a focus on reducing our business risk in Ohio through the transfer of two large plants to regulated affiliates, sizing our cost structure to a competitive environment and hedging our output. As Nick said, we are committed to investment grade credit and at this time do not see the need for additional equity beyond the DRIP due to some flexibility in our capital spend profile and securitization opportunities in both Ohio and West Virginia. Our Ohio team is working hard to achieve an outcome in our ESP case that preserves the financial strength of Ohio Power and our new competitive generation company.

Turning to slide 10, for the remainder of 2012 I have already detailed the estimated cost impacts of the late June and early July storms. We have shown where the economy is recovering in our service territories and the resulting impact on load. The industrial and commercial load classes are headed in the right direction, yet recent residential load trends have been weak.

Regulatory uncertainty in Ohio has been a concern for the AEP story for some time. In early June we started to get some clarity on Ohio regulatory outcomes, but a big piece of that picture is expected to come with an order in early August. We're working hard to get a reasonable outcome.

Our earnings so far this year have been the result of positive non-Ohio utility performance and expense discipline offsetting earnings challenges in Ohio. We will maintain that discipline.

Most of all, we are looking forward to being able to share with you a plan in Ohio that has a clear, reasonable transition to a competitive generation model and a stable regulated wires company with a financially sound AEP Ohio throughout the transition period.

With that, I will turn the call over to the operator for questions.

(Operator Instructions) Anthony Crowdell, Jefferies.

Good morning. I have a question on customer switching. And I believe on the call you had said that about 34% of your Ohio customers have switched, and I want to know how that compares to the expectation you guys filed in Ohio, and I believe that was Bill Allen's testimony. Are you in line with that or are -- is the switching ahead of what you guys are forecasting?

I think it is lower than expectations. However, after this last order we would expect switching to accelerate.

Great, thank you.

Dan Eggers, Credit Suisse.

Question number one is, O&M has been one of these great success stories for 2012 so far. Can you just maybe give a little more color on how much of the year-over-year savings is kind of durable and sustainable, versus kind of timing-related around maintenance schedules and that sort of thing with the fleet, and what kind of inflation we should be kind of modeling off in this level?

Yes, Dan, we've had some pretty good savings. Actually our employees have responded quite credibly to the reductions from the Ohio-related activities, and we have adjusted.

Some of those -- the majority have been sustainable type of reductions, although some of them are not and -- such as the deferral of outages and those types of things. But that is the whole reason why we are having the repositioning study done, where we are going through and defining sustainable cost reduction opportunities, either through process-related activities or organizational activities.

And we recognize that cost-cutting -- we can't continue a process of cost cutting and cost cutting. We have to have a view going forward of sustainable reductions that provide us a base where we can continue to progress as a Company. So that is what we're really focused on. Brian, you may have some additional detail.

No. You hit the nail on the head, Nick. When we had talked about guidance that has since been suspended for 2012, we talked about O&M in that $3.4 billion range. I would probably put it in the $3.3 billion to $3.4 billion range. And with what we're doing with McKenzie, we anticipate it being in a similar range for next year.

So we should see flat O&M next year. That is interesting.

Nick, I guess with the gas plants running really well, gas prices, low coal prices, kind of running into some cash pressures, are you guys doing any work to reevaluate the environmental plan for EPA compliance? At $6 billion as far as -- I mean less plant investment and more new generation, or how is that dialogue going internally?

That continues to be a work in progress, Dan. It changes as we get new information, and changes as a result of discussions we have with the states and with the EPA. And of course we continue to work, as I've said, on the legislative side because EPRI has done an independent analysis showing that it costs one-third less if you wind up with a two-year extension, if you're able to optimize that.

But I think it is important for us to go through the process in concert with the states, and it really focuses on that operating company model where we're working with them to determine what the proper solution is. And you're right; we continue to search. And as you see some of the changes that have been made, such as with the big Sandy scrubber proposal being pulled at this point, we are reevaluating that. We have some activity in Oklahoma around coal-fired generation as well that we've adjusted to.

You will continue to see those kinds of adjustments, because what we're trying to get to is, number one, a portfolio that each of our operating jurisdictions support, and then secondly, a portfolio that provides some risk management around a balanced portfolio going forward. So, for us, it is a relatively high hurdle for us to be putting scrubbers on our facilities.

In many cases, it is already done. In some cases it continues to be an evaluation, even for units such as the 1300 megawatt units at Rockport. Paul Chodak over at I&M is working with the regulators to determine what the proper opportunities are for that, so that we can meet the emission reduction guidelines. And that is being discussed in all of our jurisdictions.

So, you bring up a great point and it is something that we're very focused on and we will continue to try to optimize. Matter of fact, when we first started this process we were looking at $8 billion, and it has come down to just over $6 billion. And we expect it to continue to be refined as we go forward in concert with the states.

Great, thank you guys.

Paul Patterson, Glenrock Associates.

Good morning guys. Just the fuel deferral reversal, I'm sorry I missed the exact number. What was -- Brian said it and I just missed it. Could you repeat it? (multiple speakers)

We didn't mention a number specifically. It was about $30 million. There was a clarification in an order that came out this year that meant that instead of having deferred $65 million, we only needed to defer the Ohio retail jurisdiction component of that. So that allowed us to reduce the Ohio deferral expense amount by $30 million.

Okay. And is there any ongoing impact we should think about or is it just sort of a this-quarter event?

There is no ongoing effect of that.

And then the depreciation for shorter generation line, could you give us a sense as to what is causing that and how much that was in the total $50 million increase for depreciation?

Yes, for year to date, Paul, it's about $32 million. And that is associated mostly with the Ohio assets that we know we will be retiring by 2015. So we had to increase the depreciation on those particular assets to that 2015 terminal date. And for year to date, that increase in depreciation is about $32 million.

Okay, and then that will be going off, right? Is that how we should think about it on an annual basis?

You should think about those increased amounts through 2014 to get to that January 1, 2015 retirement date.

Okay. And then the securitization that you mentioned, do you guys feel you can do that with the current legislation in place? I'm talking about the deferrals, excuse me, on the capacity charge. Do you think you can do that with the current legislation or current -- I'm sorry, [current laws] do you need new legislation to enable that?

Yes, I think we could be able to do that. Obviously there's different views of what the law says, but there is flexibility in that and we believe we can do that.

Okay, and would that be something that you think you could do before sort of although the -- because I'm just assuming we're going to get the appeals in this, considering how contentious this stuff has been. Do you think that that would -- in terms of securitization, the timing of the potential for securitization, how should we think about that? Do you think that we would have to -- obviously get through a hearing, but beyond a hearing do you think we would have to wait for an Ohio Supreme Court decision or -- do you follow me?

Most likely we would, but nevertheless we would start the financing and so forth associated with that.

And Paul, I would like to distinguish that as the capacity deferral from the capacity case, and distinguish that from the Ohio reg assets, where were going to file later this month to be able to securitize a little bit over $300 million of Ohio reg assets and Ohio fuel from the 2009 through 2011 period, which is a little bit over $500 million. And we do believe that everything is in place to be able to securitize those amounts, particularly the reg assets and then the fuel pending a final order in those cases.

Did you mention West Virginia?

Well, that's another jurisdiction altogether. In West Virginia we think we will be able to securitize about $400 million of deferred fuel in early 2013 as well.

Okay, thanks for the clarification. I appreciate it. Thanks a lot, guys.

Jonathan Arnold, Deutsche Bank.

I noticed you didn't highlight retail rate increases as part of the -- as an individual driver. And then the slide that kind of was that you went backwards in the quarter versus last year, is that just timing? And how should we be thinking about rate increases as a driver of overall earnings for the year?

In the back part of the slides, Jonathan, you will see we netted together POLR and rate increases. So what you're seeing is the overall negative impact of having lost the POLR outcome. But that is offsetting positive rate increases in other jurisdictions.

Oh, okay.

Yes, we continue to benefit from rate increases in the other jurisdictions.

Okay. On sales, I guess last quarter you had the weak Q1, particularly in residential, and you didn't adjust the annual forecast. And now the annual forecast is not on the slide; it is more a year-to-date number. How should we be thinking about your expectations versus the numbers you had for the year a quarter ago?

Jonathan, we're coming in lower than what we had forecast for the year. And that is largely being driven by the residential customer class. That is part of what we're striving to offset with some of the cost reductions that we have talked about, and that lag in the residential customer classes is definitely impacting the overall retail sales on an annualized basis.

Yes, Jonathan. I think it remains to be seen what the reasons for that are, but typically when you have industrials come off and industrials come off afterwards, and then residentials either empty homes or people decide, well, I can't find another job, so they leave. So it's that piece of it. So you have this recovery that is occurring, at least we call it that at this point, with an industrial being sustainable, commercial starting to pick up, residential hopefully would pick up as a result with the job creation that Brian had talked about previously.

But the other side of the coin could be from an efficiency standpoint. Customers are -- because of the economy or because of efficient appliances and so forth, what does the future hold in terms of residential class? So it remains to be seen, but something we're watching very closely.

What is a good number for the year when you aggregate industrial and residential, about flat? Is that a good -- kind of what you're thinking?

No, I think closer to the -- up 0.5% to 0.75%.

(technical difficulty) So you must be expecting residential to be a little bit less negative as you move into the back half of the year.

Yes, we believe so.

Can I -- one other for Nick, you mentioned having been up and visited the people at BlueStar.

Yes.

Can you give us a bit more of a sense of where they are in their business plan, where you are kind of targeting? Are there any wins they might have had, just to put flavor of how you feel about operations there?

Yes, it's sort of interesting when I visited we're trying to keep this really a separate culture from the rest of the organization, because we really do want it focused on that competitive environment. And walking into the place, having a lot of young people in shorts and flip-flops, and -- but it is a different environment. But it is one that is very focused.

It is clear that they are focused on and energized by what Ohio can provide for them, particularly from the unregulated generation side, to have this slug of generation being provided they hedge against and provide deals in the market. They are very focused and active on doing that.

And one of the things that struck me in the discussions with them is how much -- they didn't talk about let's go get as many kilowatt hours as we can. That wasn't part of the deal. It was let's go get these contracts, do it wisely, do it with the controls in place, but focus on margins.

And I think this organization, the back-office system integration continues to work very well. Matter of fact, I think all of our customers -- our existing AEP retail customers switch over to the BlueStar systems here in the next -- I think it is the next week or two, two weeks. So, it's happening very quickly and that integration process is going very well.

We have AEP retail employees together with BlueStar employees now. Matter of fact, we moved several AEP retail employees to Chicago to really focus on that effort. And I see the mix of the two cultures going extremely well, because they are fueled by the prospect of just amazing growth potential. So that is my view of it.

I think it is going to be a very positive thing for us, particularly when we get the corporate separation out of the way and they can start actually planning on making deals based upon the availability of that generation, and long-term deals at that. While I was there they were signing up deals. Matter of fact, they told me several deals as I was leaving, that they were very proud of from a long-term perspective. So they are making considerable progress and I'm happy with that progress.

Are they active in kind of the Illinois aggregation space?

Oh, yes. Matter of fact, they're operating in several states right now, certainly Illinois in a big way. But they are also focused on other activities particularly in Ohio. They're ramping up for Ohio and in the process of marketing in Ohio, and we were successful in the aggregation of Upper Arlington, which was a major one for us. So they are certainly making considerable progress.

Now they are starting to think about, okay, what areas do we want to focus on? We have told them move forward with those activities as quickly as we can, but only focus on those areas that we understand. And that really is going to drive you toward the MISO markets, the Northeast, they have New York and Maryland and other retail areas as well that we also opportunity participate in auctions in, so as well as our own territory.

And, they are also faced with the prospect we did -- we're in the process of getting approval to start up our AEP retail organization back in Texas, the lower than 1 megawatt customers. That filing is waiting for the commission approval right now. So, we are very focused and they are as well, and it really is moving forward well.

Thank you very much.

Stephen Byrd, Morgan Stanley.

Good morning. Looking at the coal gas switching numbers for your combined cycle, and just wondered if you could get some color on during the peak summertime for your combined cycles what general output level are you expecting. Are there any physical constraints or any other constraints we should be thinking about?

I think our capacity factors have been pretty high for the gas units, running in the -- I guess in the 70% -- 78% to 80% capacity factor during the July time we have had thus far, and generally around that 70% to 80% capacity factor, I think which is sort of amazing given what we are dealing with.

I think from a coal-fired generation perspective it's dropped off considerably. As long as we are not having sub-$3.00 per MMBTU per [OSS], the capacity on the gas units are going to be continuing to be high. There is no capacity constraints that we have on the gas units at this point in time, and I think our numbers were slightly down last month because that is when we took some outages on some of the gas units.

But we are pleased with our gas capacity factors and our ability to respond, actually. Just as an additional add-on to that, we are continuing to be concerned about the reliability implications of what the EPA is doing, because one thing we have not talked about is the capacity factors of those small older coal-fired units that are depending -- dependent upon during the peak. As we had last year, these units are being called on and connected to the system 54% of the time and are running in the order of 30% capacity factor during these peak months. So, they are still needed and we're going to have to work through that process.

And even with those committed to provide the peak, and obviously they have minimal one-time obligations and minimum load obligations, we still achieved almost 80% capacity factor on the gas units. So that pretty well tells you we are really switching back and forth based upon what the peak requirements are, but utilizing the energy component through the natural gas as much as we can.

That is very helpful, thank you. And this builds a little on what Dan had asked earlier, just because you think about environmental compliance but you also add on the pressure of low natural gas. You mentioned many of these units really are quite needed from a reliability point of view.

Is there a chance over time that some of these smaller units will be candidates for retirement over and above what we've looked at in the region already? Or are we kind of reaching the point where we are really going to need most of those coal plants to be around from a reliability point of view?

I think the surviving coal units you're going to need for reliability. The smaller coal-fired units we are going to have to step through the process and determine physically on the system, do we need capacity at those particular areas. And in many cases, these units are running with reliability must-run status during these peak months.

So, we're going to have to solve that equation. And that could lend itself to more natural gas-fired capacity or transmission solutions as a result. Either way, we will benefit.

Great, thanks so much.

Paul Ridzon, KeyBanc Capital Markets.

As Ohio starts to build out its shale presence, is that your territory?

Yes it is. Yes; matter of fact, not just the Ohio shale. We have about every shale gas play there is, from Texas, Louisiana, Arkansas on up to the Marcellus Shale and the Utica Shale, so we're benefiting from that.

And you indicated a two-year extension on EPA compliance (multiple speakers) capital of 33%?

What I had said was that if we had the two-year extension, then we have more of an ability to approach the technological side of things. And that's why I was pointing to the EPRI study, which is an independent organization, Electric Power Research Institute. They did a study and said that if you were to take an additional two years by utilizing technologies, you could actually save half of the units that are scoped for retirement for that period of time, and achieve the same emission reductions at one-third less cost.

So, instead of $300 billion cost in the country to address the EPA issues, it would cost around $200 billion, which that is a substantial cost savings, particularly when you are talking about the impact on the economy. And as we go through this process, we're going to have to determine with the EPA, and perhaps legislation would give you a lot more flexibility and a lot more security around the solutions. And that is what we are trying to achieve.

So it's a technology thing, it's not a debottlenecking of capital inputs?

No, we have a plan. We have a plan now for the capital plan associated with addressing the present EPA requirements. If we're -- the extension is really to focus on giving time for a liability standpoint and from a supply chain management standpoint to ensure that we're doing it in a cost-effective manner and from a reliability standpoint.

When you look at your retail business, what is the net/net of kind of losses versus gains?

Do we have those kinds of numbers, Brian?

Paul, we can have (inaudible) get that for you.

Okay, thank you very much. Congratulations on a good quarter.

Yes, thank you.

Michael Lapides, Goldman Sachs.

Yes, hey guys. Congrats on a good quarter. A couple of model-oriented questions and then one strategic one. On the model-oriented one, how should we be -- is the impact of POLR that you have seen in the first and second quarter, do you expect a similar run rate for the second half of the year?

We do through portions of the third quarter, but then it was shut off during the third quarter. So, not a similar run rate for the balance of the year.

Okay. Other O&M -- do you expect to realize similar year-over-year O&M cuts in the second half of the year? Or were the O&M cuts you realized this year largely front-end loaded?

I think we expect to have -- and this goes back to the discipline. We will continue to have those kinds of sustainable cuts through the rest of the year. But keep in mind, we sort of plan the year based upon what we think the year is going to turn out to be.

And then toward the end of the year, if we lined up with additional ability to move projects up -- because last year we moved projects from '12 into '11. We may move projects from '13 into '12 or vice versa. So it really changes based upon how we see the year going.

So we expect that to continue. It's a continual process for us, and it shows that discipline around cost side, I think.

Got it. And last question, when you think about Ohio and where it fits into the broader kind of spectrum of AEP businesses, I mean you guys have over the last few years progressed a ton in terms of getting closer to or actually earning your authorized rates of return. Meaning, you are showing that you are a good team in terms of running and realizing returns out of regulated businesses.

You've gone out and bought BlueStar. And you are now entering a new competitive business both on the retail and wholesale side. And I just want to kind of ask that question.

Is that really core to AEP? I mean is what AEP really good at is running a regulated business, and that as you migrate towards more of a merchant model in Ohio and more competitive model, do you wonder about whether that is really non-core to what your strengths are, and that whether those businesses really fit within the broader bubble of AEP?

That's a great question, Michael, because, yes, we are thinking about that in terms of the future and certainly our Board is, too. As we think through this process, and it goes back to the February 10th presentation that we did for everyone, it was really there to say that we are a regulated utility. That is what we do.

Now, we are doing the best we can obviously with -- we're going to have some unregulated generation. We still have one of the most outstanding wholesale trading operations there is in the country. We're going to put that together with a retail organization and make sure there is a competitive business is viable for the future.

Now, the decision will be made later as to whether that makes sense for us or not. But it will be based upon, as we said in the February 10th meeting, if we can make it look quasi-regulated where there is long-term contracts, there's hedging associated with activities and the market sees that we have a business that makes sense for us in the future, then we will continue with it. But I think it is important for us to rationalize that process over the next two to three years and fully understand what that business looks like.

The other issue, too, is we don't know what happens across the country or what happens in the next two to three years in various fundamentals, or whether states go to competition or elsewhere. So, it really winds up being a very credible option for us in the future. Hopefully it will be complementary. But again, we are very focused on providing regulatory earnings certainty for our investors, and that is something we're very focused on.

Okay, thanks guys.

Bill Apicelli, ISI Group.

Hi, thanks. My questions have been asked and answered.

Kit Konolige, BGC Partners.

Good morning guys. I get Chuck's pronunciation too, right. (laughter) (multiple speakers) A couple of follow-ups.

So, looking towards the August 8th order, can you just remind me? Maybe I missed this, but do you expect to get details -- the commission to provide a detailed roadmap for recovery of the capacity deferrals at that time?

Yes, it should be, because one of the expectations out of the order is to define exactly what that deferral mechanism is. So we will wind up with that, and certainly as a result of that, we need to understand the cash position as well. And then we will step forward with the financing and the activities associated with separation of the generation function from AEP Ohio, so we have to have that kind of detail.

So in the August 8th order also, then, you expect -- is the separation agreement going to be part of that? And is it going to be clear, the ability to transfer the couple of large coal plants to the regulated entities?

Yes, we expect the corporate separation order to be done at the same time.

Very good. And then -- so, one other separate area, then. On the switching outlook following the capacity order now, can -- maybe I missed this, but can you give us kind of an updated look forward on, now given where you are now and given what you know about the ability of competitors to charge at RPM rates, what is the outlook for switching for the rest of the year or even the next couple of years?

Yes, I think we should expect to see acceleration of switching as a result. And I would also believe that the certainty around the ESP order on February 8 will help in that regard. So, from a competitive standpoint and knowing what the process is, the market will more fully understand.

The other thing, too, is they will understand what our reaction is, because obviously we are looking for a decent outcome out of this thing. Otherwise we have other options that we need to consider, and that can produce lack of clarity for the market. So, it is pretty critical that we get this train back on the tracks in a positive fashion.

Josh, we have time for one more question.

Raymond Leung, Goldman Sachs.

Hey guys, Raymond Leung, nice try. A couple of questions. One, to follow one of Michael's question about the regulated and unregulated business, as you guys think about it, what's the sort of the right composition mix do you think you should have between regulated and unregulated as you sort of think about that business longer-term? And then I have a couple of other housekeeping questions.

At the end of the day, it's that percentage where I can get a regulated PE and still have a competitive business that looks regulated. So I think in our February 10 we had 86% regulated, 14% unregulated including the 4% of our River operations area.

So, as I said we are a regulated utility, so as -- in my opinion, for our shareholders not to experience the volatility in such a large manner associated with the competitive business, we would want a substantial part of our business -- enough where we continue to fall in the integrated regulated utility category.

Okay. And in terms of BlueStar, what type of margins should we expect? Have you provided any type of range or how we should think about that business in terms of profitability?

Brian?

We have not. We anticipate margins in the high single digits to mid-double digits, mid-teens.

Is that on a percentage or a dollar per (inaudible)

Dollar per.

And then last thing, in terms of your financing plans, I think you indicated about $1 billion for this year. Can you elaborate on that and maybe in the updated thoughts on how you're going to find the nonregulated side of the business?

Sure. Let me start with the first part of that. We have a maturity coming due at APCo here in the near term and we also have some needs for our transmission business, as well as wanting to take advantage of some of these low term interest rates to fund our business for the long term. So, a combination of those things are what -- are going to add up to that $1 billion need for the end of the year.

And then in terms of the deregulated competitive business, we have not talked about how we're going to fund ultimately the competitive Ohio generation, whether we're going to do it at the gen co level or the parent level. But we do believe we are going to have some interim financing needs until we get to that long-term solution, and we will be looking to put those interim needs in place by the end of the year.

Great, thank you guys.

Thanks, everyone, for joining us on today's call. And as always, our IR team will be available to answer any additional questions that you may have. Josh, can you please give the replay information?

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