American Electric Power Company, Inc. (AEP) Q2 2012 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the second quarter 2012 earnings conference call. [Operator Instructions] As a reminder, this conference is being recorded. I'd now like to turn our conference over 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. The 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. And as Brian will discuss in more detail a little bit later, our service territory continues to show progress. 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 that the economy will continue to improve and show that sustainability, particularly from an industrial standpoint, manufacturing as well as moving to 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 during this time of the year and hopefully, we'll 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, in particular related to Ohio where our loss of the POLR charges and customer switching. Ohio has not been a good story for AEP over the last year or so, and -- but we're working really hard to turn this around. All of our other state jurisdictions have improved over the 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 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 in retail and wholesale trading and marketing functions. That's going to be key for us to execute for in the future after we get this August 8 to order. Investment in our regulated businesses. We will continue to invest in our regulated businesses. And as we've described, just that investment will provide for continued commitment to the growth of 4% to 6% from an earnings perspective. And we'll continue to focus on growth in our transmission business as well and repositioning that business around the critical mass to make sure earnings provide in 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'll transform from a resource perspective as well. Our generation resources in response to the EPA and certainly from the price 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 all -- 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 will really enable us to look ahead to the execution as necessary reposition the company for the future. I've been CEO for about 8 months now and have been fortunate to preside over 2 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 had never heard of before the storm actually occurred, a super derecho, which occurred in late, 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%. 6 of AEP states from Indiana to Virginia were affected and some 1.4 million customers. And additional 300,000 customers were affected in the follow-up storms that ensued. We marshaled crews from our Western footprint and certainly from the indigenous operating companies that were affected, but also all of the country, from California and elsewhere, and in Canada as well to support the restoration efforts. I'm very proud of our response. And our management team, included -- including myself, visited with crews working throughout our various states to make absolutely sure that the necessary resources were dedicated, restoring power to our customers. Working for almost 2 weeks, 16-hour days and almost a 100-degree heat was an extreme challenge that I'm confident that 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 for future recovery as Brian will provide more detail on a little bit later, but it is and 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 PCO 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 the deferral mechanism to be resolved in the ESP filing. That's 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 -- needs 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's been on the books for quite a while. The other major issue is corporate separation. We'll 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 Genco and AEP Ohio going forward. So make no mistake. Your 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's one key issue I'm not interested in signing up every customer we can sign up. I'm interested in margins associated with that because we are providing a hedge, ultimately for the generation that 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 that this supply. And as we discussed with you all in February, so for AEP, all of our sites are set on moving forward. We continue to see 4% to 6% long-term growth, dividend supported by the regulated companies and do not perceive the issuance of equity during this transition. We are 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, we are now turning dirt on some significant projects of a cell substation in Ohio, that's a $239 million investment; a $200 million project in Indiana; and another $200 million of major projects throughout our Transcos, 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. We are very disappointed in the 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 the EPSCO, only Duke and AEP. And you can't interconnect AEP's 765 KV into an EPSCO's 138 KV system. That's -- technically, that just doesn't work very well. And that we have a substation pretty close to that, that's accommodating to our 765 KV. So really, look at those factual issues needs to be revisited. Overall, a 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'll 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 have 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 near-term perspective from a Transco and other longer term projects perspectives, we'll be able to certainly focus on an earnings path and secure that for the future. So we spent 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 as hearings and we expect an order by the end of 2012. Intervener exceptions are due August 15. We submitted our version of what the order should look like, so we'll 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 fire in the boilers so that we can move on with getting that unit to 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, could be a little bit higher than that but nominally, $6 billion over the next 5-or-so years to accommodate the retrofits and retirements of our generation facilities. We continue to be focused on legislation to provide for a 2-year extension so that we can ensure reliability and reduce the cost of compliance. That makes a lot of sense for our ultimate customers and the economy in general. And lastly, I'll talk about our repositioning study. We have engaged MacKenzie and Associates to work with us on our plan to refocus our business on growth and efficiency of operations and enable us to do -- to continue to prioritize our business functions around the opco [operating company] 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 for earnings growth. We expect to conclude this study by the end of the year, with sustainable -- with a sustainable process and organizational value that begins in 2013. So again, all eyes are on August 8. We assume and then expect -- we expect expedient and deliberate execution and progress toward the strategic goals that we've discussed. And now, I'll turn it over to Brian.

Thank you, Nick. Turning to Slide 4. 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 planned outage work and lower storm expenses compared to 2011. In addition, the unfavorable variance 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 storms' total cost were about $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'll ultimately be able to defer for future recovery up to $130 million. We recognize $4 million in expenses related to the series of storm 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 earnings per share of $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 quarter 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 6 months of the year was -- 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 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 planned 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'll see on the bottom right quadrant that weather-normalized total retail sales were up 1% for the quarter and 3/10 of 1% 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 evenly distributed across our service areas. One of the best indicators of relative strength of the local economy is employment growth. Over the past 3 months, employment growth in AEP's metropolitan areas has increased 2%, which is better than it's been over the past year and stronger than the 1.4% employment growth for the U.S. 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 3 months. Job growth in our western service territory has been stronger. Over the past 3 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 prerecession 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'll talk more about this in more detail on the next slide. On the top right of the slide, AEP sales to commercial customers grew 1.6% for the second quarter and are 6/10 of 1% 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 accounts. In our eastern service territory, we have approximately 4,000 fewer customers than we had last year. Our Texas properties 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 5 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'll notice that sales in the petroleum and coal products sector had 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 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 U.S. auto sales, which reached their prerecession annualized levels earlier this year. We have experienced load growth at existing automotive manufacturers in West Virginia and Louisiana. In addition, drivers in the U.S. are maintaining and not replacing their vehicles as often as they used to. This has resulted in growth at 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 quarterly and annual periods, our generation from natural gas has increased approximately 80%. For our East combined cycle units, the increase in capacity factors and generation is even more pronounced. With the addition of the Dresden generation facility to our Waterford and Warrensburg 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 of 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 remained strong. Our debt to total capitalization has remained fairly constant over the last 3 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 our 2 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 risks for Ohio Power had been outlined by all 3 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 considered deferrals of changes and 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 are able to begin recovery of our deferred fuel costs and securitize our existing regulatory asset balances. These last 2 items will be credit supportive. They are likely both positive and negative items to appear on the credit scorecard 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 2 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 had 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 are working hard to get a reasonable outcome. Our earnings so far this year had 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] Our first question comes from the line of Anthony Kordell from Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: 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 you -- is switching ahead of what you guys are forecasting?

I think it's lower than expectation. However, after this last order, we would expect switching to accelerate.

Our next question comes from the line of Dan Eggers from Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just 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 a sustainable type of reductions, although some of them are not, and such as you have a deferral of outages and those types of things. But that's the whole reason why we're having the repositioning study done, where we're 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's what we're really focused on. Brian, you may have some additional detail.

No, that's it. You hit the nail on the head, Nick. When we had talked about guidance, but since it's been suspended for 2012, we talked about O&M in that $3.4 billion range. I'd 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. Dan Eggers - Crédit Suisse AG, Research Division: 2 [ph] is just implied O&M next year. Okay, that's interesting. Nick, I guess with the gas plans running really well. Gas prices, low coal prices, kind of remainder cash pressures. Are you guys doing any work to reevaluate the environmental plan for EPA compliance, $6 billion as far as maybe less plant investment, more new generation? Or how is that dialogue going internally?

Yes, that continues to be a work in progress, Dan. I mean, it changes as we get new information and it changes as a result of discussions we have with the states and with the EPA. And of course, we continue to work, as I said, on the legislative side because EPRI has done an independent analysis showing that it cost 1/3 less if you wind up with a 2-year extension if you're able to optimize that. But I think it's 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 are -- 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're reevaluating that, we have some activity in Oklahoma around coal-fired generation as well that we've adjusted to do. You'll 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's a relatively high hurdle for us to be putting scrubbers on our facilities. In some -- in many cases, it's already done. In some cases, it continues to be an evaluation, even for units such as the 1,300-megawatt units at Rockford. 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's being discussed in all of our jurisdictions. So you bring up a great point, and that's something that we're very focused on. And we'll continue to try to optimize, matter of fact, when we first started this process, we were looking at $8 billion, and it's 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.

Our next question comes from the line of Paul Patterson from Glenrock Associates.

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, Brian?

Yes, and we didn't mention the number specifically. It's about $30 million. There was a clarification and 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 that we should think about? Or is this just sort of a this quarter event?

Yes, there is no ongoing effect of that.

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

Yes. For year-to-date, Paul, it's about $32 million, and that's associated mostly with the Ohio assets that we know 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? That's -- 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. 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 -- sorry, current [indiscernible] legislation to enable that?

Yes, I think we could be able to do that. I mean, I think, obviously, there's different views of what the law says, but now, there's 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 all the -- because I'm just assuming that we're going to get 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 have to sort of -- obviously, get through a hearing, but beyond rehearing, do you think we'd have to wait for an Ohio Supreme Court decision or -- do you follow me?

Most likely we would. But nevertheless, we'd obviously start the financing and so forth associated with that. Brian?

Yes. And, Paul, I'd like to distinguish that as the capacity -- deferral from the capacity case and distinguish that the Ohio reg assets, where we're 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's 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'll be able to securitize about $400 million of deferred fuel in early 2013 as well.

Our next question comes from the line of Jonathan Arnold from Deutsche Bank.

I'm just curious, I noticed you didn't highlight retail rate increases as part of the -- as an individual driver and then the slides that kind of [indiscernible] -- that you went backwards in the quarter versus last year. Is that just timing or -- and how should we be thinking about rate increases as a driver of overall earnings for the year?

Yes. In the back part of the slides, Jonathan, you'll see that 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's offsetting positive rate increases in other jurisdictions.

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

Okay. [indiscernible] On sales, I guess last quarter, you sort of -- you had a weak Q1, particularly in residential, and then -- and you didn't adjust the annual forecast. And now the annual forecast is not on the slide; it's 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?

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

Jonathan, I think, it remains to be seen what the reasons for that are. But typically, when you have industrials come off and then commercials come off afterwards and then residentials, either empty homes or people decide, "Well, I can't find another job," so they leave, and so it's that piece of it. So you have this recovery that's occurring, at least we call it that at this point, with industrial being sustainable, commercial is starting to pick up, the 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 the efficiency standpoint. Customers are -- because of the economy or because of efficient appliances and so forth, what does the future hold in terms of the residential class. So it remains to be seen, but it's something that we're watching very closely.

What's a good number for the year kind of when you aggregate industrial and residential? Is it about flat or is that a good [indiscernible] kind of what you're thinking?

No, I think closer to the up 5/10 of 1% to 3/4 of 1%.

[indiscernible] must be expecting residential to be a little less negative as you move into the back half of the year?

Yes, we do so.

Okay. Can I -- one other thing. Nick, you mentioned having been out and visited the people of BlueStar. Can you give a little bit more of a sense of where they are in that business plan, where you're kind of targeting, are there any wins they might have had, just a 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 to focus 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's -- one, it's very focused. I mean, it's 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 can 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 was 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 are existing AEP retail customers switch over to the BlueStar systems here in the next, I think in the next week or 2 -- 2 weeks?

Yes.

So it's happening very quickly. And of 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 2 cultures going extremely well because they're fueled by the prospect of just amazing growth potential. So that's my view of it. I think it's 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 doing making deals based upon the availability of that generation and long-term deals with 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 you active in the kind of high -- in the Illinois aggregation space?

Oh, yes. They're -- matter of fact, they're operating in several states right now. Certainly, Illinois in a big, big way. But they're 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 win for us. So they're certainly making considerable progress. Now, they're starting to think about, "Okay, what areas do we want to focus on?" And we've sort of -- I mean, we've told them, "Move forward with those activities very -- 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 State, they have in New York and Maryland and other retail areas as well. But we also participate in auctions, so -- as well as our own territory. And they're also faced with the prospect that we did -- we're in the process getting approval to start up our AEP retail organization back in Texas, the lower-than-1 megawatt customers, that following is waiting for the Commission approval right now. So we're very focused and they are as well. And it really is moving forward well.

Our next question comes from the line of Stephen Byrd from Morgan Stanley.

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

Yes. 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've had thus far. And generally, around that 70% to 80% capacity factor, I think, which is sort of amazing, given what we're dealing with. I think from a coal-fired generation perspective, it's dropped off considerably. As long as you're -- we're not having sub-$3 per MBTU price, the capacity on the gas units are going to be -- continuing to be high. There's 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's 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. What we're -- and just as an additional add-on to that, we are continuing to be concerned about the reliability implications or what the EPA is doing because one thing we haven't 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're 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 minimum run-time obligations and minimum load obligations, we still achieved almost 80% capacity factor on the gas units. So that pretty well tells you we're 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's very helpful. And this builds a little on what Dan has 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 and are reaching already or are we kind of reaching a point where we're 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're 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. In either way, we'll benefit.

Our next question comes from the line of Paul Ridzon from KeyBanc.

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. It's -- we have about every shale gas play there is, from Texas, Louisiana, Arkansas and up to the Marcellus Shale and the Utica Shale. So we're benefiting from that.

And you indicated a 2-year extension on EPA compliance, but now capital of 33%?

Oh, what I'd said was that if we have the 2-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 2 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 a 1/3 less costs. So instead of $300 billion cost in the country to address the EPA issues, it would cost around $200 billion, which -- that's a substantial cost savings, particularly when you talk about the impact on the economy. And as we go through this process, we're going to have to determine, with EPA and perhaps legislation would give you a lot more flexibility and a lot more security around the solutions, and that's what we're trying to achieve.

In the technology things side, are you 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 -- if the extension is really to focus on giving time from a reliability 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 we look at your retail business, what's the net net of kind of losses versus gains?

Do we have those kind of numbers, Brian?

Yes. Paul, we can update you. We'll get Bette Jo to get that for you.

Our next question comes from the line of Michael Lapides from Goldman Sachs.

Couple of model-oriented questions and then one strategic one. On the model-oriented one, how should we be -- like is the -- is the impact of POLR that you've 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?

No. I think we expect to have -- and this just goes back to the discipline. We'll 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 wind up with additional ability to do -- 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 of things.

Got it. And last question, more -- 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're showing that you're a good team in terms of running and realizing returns out of regulated businesses. You've gone out and bought BlueStar and you're now entering a new competitive business, both on the retail and the 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 from 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's 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 has, too. We -- as we think through this process, and it goes back to the February 10 presentation that we did for everyone. It was -- it's really there to say that we are a regulated utility. That's what we do. Now, we're doing the best we can, obviously, with -- we're going to have some unregulated generation. We have -- 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 that's viable for the future. Now, the decision will be made later as to whether that makes sense for us or not. But it'll be based upon, as we've said, the February 10 meeting. If we can make it look quasi-regulated, where there's long-term contracts, there's hedging associated with the activities and the market sees that we have a business that makes sense for us in the future, then that -- we'll continue with it. But I think it's important for us to rationalize that process over the next 2 to 3 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 2 to 3 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'll be complementary. But, again, we're very focused on providing regulatory earnings, certainty for our investors. And that's something that we're very focused on.

Our next question comes from the line of Kit Konolige from BGC.

Couple of follow-ups. So looking towards the August 8 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, should be. Because one of the expectations out of the order is to define exactly what that deferral mechanism is. So we'll wind up with that. And certainly as a result of that, we need to understand the cash position as well. And then we'll 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 it is separate -- so on -- in the August 8 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, all right, but can you give us kind of an updated look forward on now, given where you know you are so far and given what you know about the ability of competitors to charge at RPM rates? What's the outlook for switching, say, 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'll 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'll understand what our reaction is because, obviously, we're 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's pretty critical that we get this train back on the tracks in a positive fashion.

That question comes from the line of Raymond -- I'm going to mess it up -- Leung from Goldman Sachs.

Raymond Leung. Nice try. Couple of questions. One, to follow on Michael's about the regulated -- unregulated business. As you guys think about it, what's sort of the right composition mix, Nick, do you think you should have between regulated and unregulated as you sort of think about that business longer-term? And then I have some more -- 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 and 14% unregulated, including the 4% of our River Operations area. So, as I said, we're a regulated utility, so 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 to where we continue to fall in the integrated regulated utility category.

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

Yes, Brian?

We've not. We anticipate margins in the high single-digits to mid double-digits -- mid-teens.

Is that on a percentage or dollar per megawatt hour?

Dollar per.

And then last thing, on terms of your financing plans. I think you indicated about $1 billion up for this year. Can you elaborate on that and maybe some any updated thoughts on how you're going to fund the nonregulated side of your 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've not talked about how we're going to fund ultimately the competitive Ohio generation, whether or not we're going to do that at the Genco level or the parent level. But we do believe we're going to have some interim financing needs until we get to that long-term solution. And we'll be looking to put those interim needs in place by the end of the year.

Thanks, everyone, for joining us on today's call. 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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