American Electric Power Company, Inc. (AEP) Q1 2013 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the First Quarter 2013 Earnings Conference Call. [Operator Instructions] And as a reminder, today's conference is being recorded. I would now like to turn the conference over to our host, Ms. Betty Jo Rozsa. Please go ahead.

Thank you, Tricia. Good morning, everyone, and welcome to the first quarter 2013 earnings webcast of American Electric Power. Our earnings release, presentation slides and related financial information are available at our website at aep.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Joining me this morning for opening remarks are Nick Akins, our President and Chief Executive Officer; and Brian Tierney, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick Akins.

Okay, thanks, Betty Jo. Overall, we had another good quarter and a solid start for the year, coming in at $0.75 a share on a GAAP basis and $0.80 per share on an operating basis, compared with $0.80 per share for both GAAP and operating last year. The difference between GAAP and operating this year is primarily due to a storm change deferral that was reversed because of a law change in Virginia. So we'll talk about that a little bit later on. Brian will, I'm sure. But the big news is that we increased our dividend by 4.3% or $0.02 to $0.49 per share this quarter, which is our 412th consecutive quarter of paying a dividend. The real story here is the confidence that our board and management team have as we set a firm foundation and strategy for continued growth. In our view, AEP is a company that is emerging from one of reacting to major issues, such as Ohio deregulation, environmental requirements and plant construction risks, to a company that is quickly moving to a place where we can truly define a path for growth. Frankly, this is pretty refreshing to the management team and our employees. We have a distinct opportunity to effectively allocate capital, control our costs through thoughtful and sustainable decision-making, reallocate and optimize spending through our repositioning initiative and make solid investments in our operating companies, grow our transmission business and transition our fleet to Generation Resources, as well as continue the formation of our competitive business through corporate separation. All of this is to achieve the financial integrity and objectives that we set forth in the February Analyst Day meeting and achieve a growth rate of 4% to 6% on a long-term basis. So we're committed to that. We've made much progress during the last quarter. But before going to those areas, let me first discuss what we've seen during the first quarter regarding the economy and customer demand. Brian is going to go into this in a lot more detail. But I just want to say that since the third quarter of last year, we see -- we continue to see weakness in the manufacturing and industrial sector of our service territory economy. I think it's true for the country and, in fact, the world. Primarily metals continues to be weak, but offset in our territory by the oil and gas activity in the Eagle Ford and the Utica Shale areas. Those are probably the saving grace of keeping our industrials where they're at. However, we're now also seeing improvement in the commercial and residential sectors, including increases in customer accounts. We continue to believe as the economy improves, our service territory is well positioned because of the energy-related activities in our service territory and we'll benefit as a result. Overall, customer load declined slightly quarter-to-quarter, but this is mitigated somewhat by the leap year difference between this year and last year. But as we said earlier in the year, we continue to believe customer load will remain essentially flat for the year. This being the case, we are making advancements in other areas as we move forward to make sure that we are addressing some of these areas to ensure that we have the financial growth that we've talked about previously. First, in transmission, we remain on plan for continued growth in earnings contribution from our transmission business of $0.14 per share this year moving to the $0.36 per share in 2015 that we have discussed earlier in the February Analyst Day. The Pioneer project received Indiana Utility Regulatory Commission approval and will be moving forward with construction. A settlement agreement in Missouri related to the public utility status for Transource/Missouri joint venture. That transfer of property and the ability to own and construct has been filed in Missouri, and we're waiting approval there. Meanwhile, at FERC, related to Transource, the ALJ approved the rates and cap structure for this project. So we await the FERC commission approval for that as well. Additionally, our Transcos continue to invest in our state footprints to enhance service reliability for our customers, and they're doing a great job in that respect. The recent FERC orders concerning Order 1000 compliance impacting such areas as the right of first refusal, cost allocation and other areas, haven't altered our strategy regarding transmission and development and have also not changed our reported investment forecast that we provided earlier. Other regulatory and legislative activities continued according to plan. Ohio has reaffirmed its commitment to the path we set previously for AEP's corporate separation and transition toward a competitive market. We recently received the final commission order regarding corporate separation, and together with final orders on the ESP, capacity and corporate separation, we are set to move forward from the Ohio perspective. At FERC, we await the orders regarding Ohio corporate separation, the Mitchell/Amos transfer, the pool termination and APCo-Wheeling merger, which we expect to have by Monday, which is the statutory deadline for the order. We did file a supplemental settlement agreement as well with the -- and settled the relevant issues with the major parties in the case. Cases were also filed in Kentucky, West Virginia and Virginia to complete the transfer of the Amos and Mitchell units to APCo and Kentucky. We expect the orders on these transfers in the June, July timeframe. These units are being transferred at net book value. They are fully controlled and will replace the capacity payments that these customers are already making through the existing pool. Even with lower gas prices, the units are a value to Kentucky and APCo customers. They are located in those states, and much of the coal supply comes from these states as well. So the Mitchell and Amos units continue to be even more valued in today's gas market for APCo and Kentucky customers. Moving on, I'd like to refer you to Page 4 of the presentation, which is probably one of my favorite dashboards. I always call it the equalizer graph. But it shows the progress we're making in the various jurisdictions. But I want to focus on a couple of them. As we -- as you might recall from the February Analyst Day presentation, I discussed primarily the regulatory lag issue in Indiana. And if you look at that graph, it had it at 7%, I think that's probably what it was last time we reported. But I do have some positive news to report. We -- the Indiana legislation that I just had discussed previously that included shortening up the regulatory lag and, as well, providing for a forward-looking test year, that actually did get through the House and the Senate, and it's at the Governor's desk. It actually went to the Governor's desk yesterday, and he has 10 days to sign. We certainly expect that to happen. So that's some very good news addressing the regulatory lag issue that we had talked about previously. And then, when you look at SWEPCO, SWEPCO has Turk operational now. So AFUDC has fallen off. And we're now putting that plan into rates. And the central issue around that at this point is the Texas case. Those hearings are complete in May. We expect an ALJ recommendation. And then in June, the PUCT order should come about. And that order will have rates retroactive back to January 29. So we should see that one pick up as well. So those are the 2 that we're very much focused on right now. So we continue to also move forward on the EPA-related mandates, such as Mercury HAPs MACT and others, as we transition our fleet with the planned retirements of over 5,500 megawatts during 2015, 2016 timeframe, and retrofits and refueling of 11,000 megawatts at a cost of around $4 billion to $5 billion over the 2012 to 2020 time period. About 1/3 of the $4 billion to $5 billion are cost expectations related to the water and coal combustion residual activities. So we're very interested in the EPA's proposed rates -- proposed rules that were just released. Most of the 8 options in the proposed water treatment rule are largely in line with expectations, particularly with the assumption that the coal combustion byproducts will be regulated as a non-hazardous waste. However, there are some extreme options that are based upon emerging technologies and require additional bottom ash retrofits. So our comments will reflect our concerns that these requirements are not warranted. Our repositioning initiatives continue, and I'm very pleased with the progress. We've engaged our workforce to redefine processes and resource requirements to achieve efficiencies and redeploy resources for growth. Lean activities have been initiated at the power plants. They continue to go through our power plants. And then, we also have reviews continue in areas such as IT and supply chain. These sustainable savings continue to keep us on track for the earnings targets we laid out for you in February. But even more important, it's to engage our employees to embrace a cultural change that will sustain us toward a path for growth and will benefit our customers, employees and shareholders. This year, we have initiated significant cultural review of our company to make sure that we do have an engaged workforce around those areas and strategic objectives that we have. So at this point, I'll turn it over to Brian to give more details of where we stand. Brian?

Thank you, Nick, and good morning, everyone. Let's starts on Slide 5, with the reconciliation of this year's first quarter operating earnings to last year's. To begin with, it's very simple, first quarter operating earnings this year were $0.80 per share and last year's were also $0.80 per share. Items adversely affecting the quarterly comparison included 2012 $0.05 effect of reversing a provision for an obligation to make certain contributions resulting from an Ohio order. That favorable item in 2012 was not repeated in 2013. Off-system sales margins net of sharing were off by $0.04 per share, due in large part to reduced capacity payments. The lower receipts from competitive retail suppliers and capacity sales in the RPM market account for about $0.05 per share and the decline in trading margin accounts for about $0.01 of the negative comparison. Offsetting these negative items by $0.02 per share are margins from physical sales of electricity, which were up 48%. Later in the presentation, I will review a slide that demonstrates the competitiveness of AEP's eastern generation fleet, even at relatively low market prices. Customer switching and the related capacity treatment in Ohio had an unfavorable net effect on the quarterly comparison of $0.03 per share. This value reflects the loss of generation-related margins on the switch load of an unfavorable $0.10 per share, partially offset by the capacity deferral provision of the ESP for a favorable $0.07 per share. As of March 31 of this year, approximately 53% of our customer load in Ohio had switched, with about 3% having provided notice of intent to switch. As of December 31 of last year, those numbers were about 51% and 3%, respectively. Allowance for funds used during construction, or AFUDC, was up $0.03 per share in 2013, primarily due to the successful startup of the Turk plant in December 2012. This resulted in the cessation of AFUDC on that facility. Operations and maintenance expense net of offsets were up slightly, adversely affecting earnings by $0.02 per share versus the 2012 period. The higher expense levels were driven primarily by additional spending associated with scheduled generating plant outages. Items positively affecting the quarter-on-quarter comparison include rate changes, which were favorable by $0.07 per share in the first quarter. This improvement in earnings through rate activity occurred through multiple jurisdictions. Finally, weather was favorable by $0.10 per share when compared to 2012, primarily due to the unfavorable conditions across all of our jurisdictions last year, with the exception of Texas where weather was comparable. Weather was a favorable $78 million versus last year's quarter, but much closer to normal this year. Remember that when we prepared our forecasted guidance for this year, we assumed normal weather. In summary, the adverse effect of several Ohio-related items, lower AFUDC due to Turk going commercial and a slight increase in O&M were essentially offset by rate changes and a return to normal -- to more normal weather. Turning to Slide 6, you'll see that the first quarter's total weather-normalized retail load was down 1.5% compared to last year. Nick mentioned the effect of the leap year, and you're all aware that this year's first quarter had 90 days compared to last year's, which had 91. On a comparable basis, total overall load would've been only negative 0.4% rather than the actual 1.5%. Much of the results for this year's comparison were driven by the industrial sector, which was down 6% compared to last year. And I'll talk more about the industrial sector on the next slide. In contrast to industrials, our residential and commercial sectors both showed growth over last year's first quarter. The residential class was up 1.3%, residential customer accounts were positive compared to last year's first quarter, and weather-normalized average usage per customer was positive 1.1%. This is the first increase in average residential customer usage since the second quarter of 2011. The commercial customer class is up 0.5%. And you may recall that 2012 was the first year of commercial sales growth since 2008. Employment growth tends to be a strong indicator for commercial sales growth, and that held true for AEP in the first quarter, and that the areas where we saw the greatest employment growth also experienced the largest increases in commercial sales. AEP Texas experienced employment growth of 2.8% and had an increase in quarterly commercial sales of 3%. AEP Ohio experienced employment growth of 1.6% and had an increase in commercial sales of 2.2%. These are the properties experiencing growth associated with shale gas development: the Eagle Ford in Texas and the Utica in Ohio. Let we take some time here to provide some economic indicators for AEP service territory, which continued to experience comparable growth to the U.S. in terms of GDP growth and employment. For the quarter, GDP growth in AEP's western footprint was 3% compared to the 2% growth in the eastern part of AEP's service territory and today's estimated 2.5% growth that was -- that has just come out for the U.S. It's worth mentioning that the effect of the sequestration and fiscal tightening from Washington having less of an effect on AEP service territory relative to the U.S. Many of the cuts so far have been related to defense spending, which is more concentrated on the coasts and less pronounced in AEP's Midwest footprint. Employment growth for AEP at 1.5% was slightly favorable when compared to the U.S. as a whole at 1.4%. The unemployment rate for AEP service territory is currently at 6.9% compared to the 7.8% or so for the U.S. This is the first time the unemployment rate has fallen below 7% in AEP service territory since the end of 2008. Turning to Slide 7, you will see that 4 of our top 5 industrial sectors experienced negative load trends for the first quarter. A significant contributor of the 6% decline in overall industrial sales, as Nick mentioned, was related to the primary metals sector, which was down nearly 17% compared to last year's first quarter. And much of that decline was associated with our largest customer. That company shut down 1/3 of its production as a result of soft market conditions and filed for bankruptcy in the first quarter of this year. If you exclude this customer, total industrial sales would have been down 3.7% for the quarter. Chemical manufacturing was down 4.4% for the quarter. It's important to note that last March, one of our largest customers in Texas, who owns a cogeneration facility, chose not to generate last year and instead, purchased all of their electricity from SWEPCO. If you exclude this customer, chemical manufacturing would be down only 2.7% for the quarter. Similarly, petroleum and coal products were down 3% for the quarter. But this was influenced by 2 refineries that conducted temporary maintenance on their facilities in the first quarter. Excluding those 2 customers, petroleum and coal product sales were actually up 10.8% for the quarter, led by a new refinery that came online last summer in Texas. The mining sector, excluding oil and gas, was down 2.9% for the quarter. Weak demand from utilities and exports have had a significant impact on coal mining operations in our service territory. And you'll note that 90% of AEP's mining base is in our Eastern regulated operations. The paper manufacturing sector was essentially flat for the quarter, with increases in Ohio sales being largely offset by decreases in our Western regulated properties. In summary, the industrial sector continues to face challenges, as the country tries to maintain its economic momentum. When we originally put Slide 8 together, we left the old title on it and later realized that it was not descriptive of what actually happened in the quarter. The old title was Coal-to-Gas Switching, and the new title that we have here, Gas-to-Coal Switching, much more accurately describes what happened during the quarter. This slide breaks out capacity factors for our East and West coal and natural gas fleets. In both regions, coal capacity factors were up for the quarter. And in both regions, natural gas capacity factors were down significantly. In gross terms, AEP generated 34% less electricity from natural gas and 9% more from coal-fired generation. These results were related to 2 factors. First, the price of natural gas increased significantly. And second, our coal-fired generation fleet is very competitive, even at gas prices below $4. Henry Hub natural gas prices increased 41% quarter-over-quarter, and AEP's delivered natural gas costs increased 35%. By contrast, AEP's cost of delivered coal only increased 7%. This is against the backdrop where AEP generation Hub peak pricing increased 15% and around-the-clock pricing increased 14%. Dark spreads widened considerably while spark spreads compressed. Turning to Slide 9, we'll see that the impact of a modest increase in prices for energy have on a very competitive AEP East generation fleet, even when Henry Hub and delivered prices for natural gas are as low as the mid-$3 range. On this slide, we have drawn the 2012 and 2013 supply stacks for AEP's Eastern generation fleet, which accounts for most of our off-system sales volumes. You'll see that in the first quarter of 2012, at an average around-the-clock price of $28.65 per megawatt hour, nearly 16,000 megawatts of capacity were in the money. By contrast, in the first quarter of 2013, at an average around-the-clock price of $32.65 per megawatt hour, nearly 20,000 megawatts of capacity were in the money. The 14% increase in around-the-clock pricing accounted for a 24% increase in, in-the-money capacity for AEP. Even at these relatively low prices for electricity and natural gas, this is a very competitive generation fleet. Let's now take a look at this year's financing activities on Slide 10. During the first quarter, we made a significant amount of progress in securing new funds at an attractive -- in an attractive interest rate environment. The company is using this capital to fund its investment program and bolster its liquidity position. Specifically, in February, we closed on the $1 billion 27-month delayed draw term loan that will provide us with interim financing as we capitalize the Genco and refinance AEP Ohio. At the same time, we also closed on the amendment of our 2 core revolving credit facilities. This included the 1-year extension of both facilities, taking the new termination dates to June of 2016 and July of 2017. The amendment also increased the capacity for the June 2016 facility by $250 million, bringing our total revolver capacity to $3.5 billion. TNC issued $200 million of senior unsecured notes and I&M issued $250 million of senior unsecured notes. In all, we obtained $1.45 billion in new debt financing and incremental -- and an incremental $250 million in credit revolver capacity. Upcoming financing activity will be highlighted by the issue -- issuance of securitization bonds at Ohio Power and Appalachian Power. These 2 financings are expected to close this summer and should bring in a combined $655 million. I'd really like to spend a little time with you now on Slide 11. This slide demonstrates the financial health of American Electric Power, and it is as strong as it has ever been. Our debt-to-total capitalization at 55% is at its lowest level in more than 10 years. Our credit metrics, FFO interest coverage and FFO to total debt, are solidly BBB and Baa2. Our qualified pension funding is now at 94%. And as we approach 100% funding, we continue to de-risk the plan, with 50% of the plan assets now invested in long-duration fixed income instruments. Over the past 3 years, we have invested $1.15 billion into the plan. This is good news for current and future retirees, as well as investors. Finally, with the increased size and tenure of our credit facilities, with the delayed draw term loan facility and with the modest uses of liquidity, the company's net available liquidity is as strong as it has ever been at $3.7 billion. I can assure you that the financial strength demonstrated on this slide has not happened by accident. The management and board of this company have been very purposeful in building the company's financial strength. Whether through careful capital allocation, O&M discipline or thoughtfully accessing the debt capital markets, we have been very focused on ensuring that the company has the liquidity and strength it needs to prosper in any variety of market and business conditions. I want you to know we will continue to do so. Let me close by saying that we remain on track to achieve 2013 annual earnings per share in the guidance range that we announced on February 15th, of $3.05 per share to $3.25 per share. We are maintaining the discipline around operations and maintenance expenses that you've come to expect from us. Lisa Barton and her team in transmission are on track to deliver $0.14 per share of earnings this year, up from $0.09 per share last year. The investment in critical transmission infrastructure should allow us to grow earnings from that segment to $0.29 per share next year. Earlier, we provided some detailed coverage of load. We're encouraged by the recent experience in our residential and commercial customer classes and are concerned by the quarterly results from industrials. Our guidance for the year factored in overall load growth of 0.5%. The industrial results for the quarter put us behind on load growth for the year but not enough to put guidance in jeopardy. Balance of year gas and power prices are higher than liquidated values for 2012. Delivered cost for coal are up but much less so than power prices. This widening of the dark spread should help off-system sales margins, but the low prices paid by competitive retail suppliers for capacity and lower RPM pricing will continue to have its negative impact. Our regulatory plans are on track relative to our assumptions and guidance. We have a positive track record of putting capital to work for the benefit of our customers and then earning a return on that investment by efficiently getting it into rates. This year should continue that record. Of our assumed rate recovery, the majority has already been secured. Finally, in terms of financial strength, I took you through some metrics that demonstrate the company is in peak financial conditions. It is this strength that gave the Board of Directors the confidence to raise the dividend payout ratio and then to quickly follow on with the increase in the dividend itself. With the dividend increase, AEP's yield is now nearly 4%. That, when combined with our stable regulated business profile and steady earnings growth, provide a total shareholder return proposition in the 8% to 10% range annually. In summary, the company is financially strong and we're well on our way to meeting our stated goals. With that, I will turn the call over to the operator for your questions.

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

So 2 questions. One, when I'm looking at the slide where you talked about gas-to-coal switching. Can you talk a little bit about the types of coal that you're burning and what the sort of a breakeven cost is between gas and coal with the types of coal you're burning, that whether it's CAP, NAP, Illinois Basin, PRB, that's allowed you to switch back?

Yes, typically, it's CAP coal, and when you look at the price breakpoint on delivered cost basis. When you're in that 3.25 to 3.50 range on natural gas, you'll start to see the switching occur. And based on natural gas prices today, obviously, we've seen it just go just basically 180-degree the other direction. But that's a good thing. And I think the real issue is that we've been able to change our contracting methodologies, particularly on the coal side and the natural gas side, to be flexible enough to adjust our generation either way. And it's worked out positively for us.

That's a lot lower break point than -- on cap coal than we've heard from other companies. Is that because of your delivery cost advantage being either mine-mouth or on the river?

Yes, that's right. We have distinct advantage from the river operations standpoint, and then also, the mine-mouth aspects of it as well. So a lot less rail delivery.

Greg, when you look at Slide 9 in our presentation and see how our supply stack lines up and you compare those prices to what natural gas prices were, our delivered natural gas was only 3.78 this year, and look at how much more of our capacity goes in the money, even at that low natural gas price. So it's a very competitive fleet that we have. And I think we demonstrated that quarter-on-quarter difference this year to last, even at pretty low natural gas prices.

And we've also been able to take the Northern APCo because of all our free units are fully controlled.

Got you. Next and last question. Page 18, you go through a line-by-line comparison of what you did in your off-system sales business. It's clear that you, obviously, you sold a lot more power and made more money. Can you take us through why the big deltas' in the other areas and what drove those?

Yes, so capacity payments were comprised of 2 items. One is the difference in the CREZ price that we're getting in Ohio. So considerably less pricing there. The other was capacity that we were getting from the RPM market. So in the first quarter of 2012, the RPM volume that we sold was 1,300 megawatts at the RPM price of $110 a megawatt day for about $16 million. And in 2013, the volume was about 640 megawatts that we cleared at a price of about $16 a megawatt day for $1.8 million. So those items comprised the capacity difference. The marketing and trading was just lower realized volumes from that. And you see that the sharing stayed about the same year-on-year, and that resulted in the difference in total off-system sales.

Yes, really, the deviations are because of the capacity payment difference.

That's right.

And our next question is from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just to follow-up on Greg's question on the coal-to-gas switching or gas-to-coal switching, I guess, we're calling it now. If you look at the curve having moved up even further, of the 3,800 megawatts of additional economic generation in the first quarter, how many more megawatts are now economic as the curve has moved that much higher?

You mean for the balance of the year? Dan Eggers - Crédit Suisse AG, Research Division: Yes.

It's considerable, Dan. It's probably another 3,000 megawatts.

Yes. And keep in mind, too, I mean, that the part that kicks up on that curve are primarily peaker units that we don't expect to run much anyway. So you're getting much deeper into the base load capability of the system now. And this -- and also keep in mind, this is the entire fleet perspective, not just the part that's going to be unregulated in the future.

And, Dan, you could even do it yourself on this slide. You could draw in the balance of the year prices for either AD Hub or AEP Gen Hub, whichever you like, and see where that crosses the line. Dan Eggers - Crédit Suisse AG, Research Division: And then when you guys talked about the coal inventory situation and you have the normalization, are you guys assuming to get the days cover using a historic burn rate? Or are you using some sort of modified lower burn rate to figure out the number of days in inventory?

That's a -- it's a full load burn rate. So it's the units that we have at full load burn for those number of days. That's the sort of historical measure that we've used.

Which we've done pretty well in managing our inventories during this process, and that goes to the flexibility issue. We're still at 43, 44 days of inventory. So we're going into the summer peak period in a pretty good fashion. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And I guess just on load growth, you gave a lot of detail. But against the plan for this year relative to a pretty slow start in the first quarter, even with your normal -- a little better-than-normal weather. What gives you guys confidence that you're going to make catch-up over the remainder of the year to get to that positive demand growth? And are you hearing comments from your industrial customers who are out of more clarification on when they're going to be back on?

I mean, I think the story that you've seen on those slides kind of nails it. The residential and commercial are up, and we're seeing the difficulty in industrial. We may not make the 5/10 of load growth that we forecasted for the year. But your earlier question highlights an offset to that, in that if off-system sales are up a bit, because prices are up even from when we came out February 15, that puts more of the fleet in the money, and that should help offset some of the load challenges that we might have through the balance of the year.

But also you have to look at the mix. You have to look at the mix of the customers, too. If you have residential and commercial improving, the margins associated with those customers are higher than the industrial customers. So it's not a one-for-one type of deal that you're looking at. And that's why I tell that now we need the industrials and manufacturing to continue to improve, and hopefully, that will occur, and a lot of times we're saying, third quarter of the year. But it's a matter of making sure it's sustainable so that the commercial and residential can continue to thrive. In the past, our residential and commercial have been really, really struggling in sales. And now we're seeing an uptick there and that's what's making the difference. And also, I think the weather was better than last year, but the weather was still normal. Dan Eggers - Crédit Suisse AG, Research Division: I mean, when you guys -- weather-normalized is always complicated when you have your big deltas from one period to another. When you look at residential, you have given the big move after having not trended well for so long. Are there underlying commentary you're seeing that gives you confidence that holds rather than just being kind of a fluctuation to what happened in weather for the period?

Yes, I think customer accounts, I think -- I always joke that maybe the 25-year-olds are finally moving out of the house. But we're seeing customer accounts go up. We're seeing construction improve. But it's that underlying industrial primary metal side, but that's all tied to the world market. So we'll watch that very closely. Brian?

We get worried about that when you have large weather effects in the period. And relative to normal, we were about $10 million positive to normal weather. So we forecasted normal for the quarter. We had normal weather, significant compared to last year, but compared to normal, it's right on top of it. So we're not concerned that weather is impacting those numbers in any significant way.

The next question is from the line of Anthony Crowdell with Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: I'm not sure how much color you want to give on this. But you've mentioned before some of the cost advantages you have with the River Operations or delivering coal via barge versus rail. I just wonder if you could talk about that or just help us for modeling purpose to kind of assume what the cost advantages would be.

Yes, I think the main aspect of it is that we -- with the River Operations, we deliver coal to our power plants at cost. And then, secondly, we also, from a mine-mouth perspective, these mines are relatively closer. So if there are any railroad movements associated with it, they can still have higher rates, but they're very short hauls. And then, overall, the position that AEP has, because of our buying strength, because of the large amount of tonnage that we purchased from the -- from all across the country, it really imputes practically the $2 per ton advantage. So when you look at that across the entire fleet, it's a pretty good advantage. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Do you -- I know some companies are talking about the flexibility in like the whole coal supply chain when gas prices really dropped and that the coal -- not only the mine owners, but the rails are very, I guess, flexible. I mean, do you see a change with gas prices now above $4 of maybe them trying to get back to previous levels, like rates of previous levels?

Are you talking about the railroads? Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Yes, or the coal mining, either one.

Coal mining. No, we don't see that. We have long-term contracts in place for coal supply from a delivery perspective. And there's plenty of coal out there. I mean, we -- in '07, we were 80 million tons of coal a year. We're at around 54 million tons this year. So there's a lot of ability to pick up production. So I think we're in good shape.

And our next question comes from the line of Stephen Byrd with Morgan Stanley.

I wondered if you could talk a little bit about, in Ohio, your plans for contracting your merchant generation, I guess, when it goes merchants. And we've had a power price uplift. But generally, the historic revenues that you had on those assets relative to the market, there's a delta between the 2. As you think about your growth prospects, how do you think about that delta and what you would assume you could achieve in getting long-term contracts for your Ohio generation, if you're kind of following my question on that delta?

Yes. Well, just keep in mind, the only ones who are going to survive out of this process after retirements will be the 9,000 megawatts of generation, all fully controlled, all well within the market. And when we look at it, even with the capital piece of it in the future, it's still looking very, very attractive. So it's a matter of how competitive your generation is, not only from a marginal cost perspective, but then, obviously, the amount of capital left in them. And I think we're going to wind up in great shape there. As far as the hedging practices associated with it, we -- that's why we're putting our wholesale shop who's been in the market for years from a long-term customer perspective. And those discussions are occurring now in preparation for the separation of generation. So that's moving along. I think, obviously, our main intent is to make sure that this generation looks as regulated as it can. We anticipate hedging about 30% of it with retail. Once we have the generation in our retail mix, where our competitive retailer can use that generation, we would be able to go to longer-term contracts and those types of things as well. So there's -- getting this generation over in the hands of our retail and wholesale shop is going to be something that's incredibly important for us but also will help us in terms of those hedging practice. So we have great relationships with munis, co-ops, long-term customers on a third-party basis, and we'll continue to advance those.

Okay. So as you look at -- that's very helpful color. As you look at the forward curve today, does that pose any headwinds to achieving that 4% to 6% as you move from the current contracts you have to market? Or is that sort of already generally dissipated as you think about your overall growth?

Yes, it's already dissipated. But the 4% to 6% is generated from what remains the regulated fees. Even in 2015, when this is unregulated, the 4% to 6% comes from that 86% that's still regulated in regulated jurisdictions, So -- and with transmission as well. So the 4% to 6% is looking pretty good.

Stephen, there's no large uptick associated with either capacity or energy price that sits in that 4% to 6% estimate.

Okay, that's very helpful. And if I could shift quickly to the dividend. You got a really, really good increase here. And as we look out, your payout ratio is happily fairly low. So it looks like you still have more flexibility. Could you just talk a bit generally about, as you look forward here, I know you just gave us a good increase, but folks are always thinking about more. The payout ratio, it looks, on the '14 basis, is still below that 60% to 70% range. Can you just talk a little about how you think about dividend over time?

That dividend increase is already old news, isn't it? What have you done formulation. So our board will continue to evaluate its dividend policy. It does it on a quarterly basis, when we look at it. And they did, and is probably the same answer I gave in February, was that they have continued to view dividend growth being in line with the earnings growth of the company. And they've looked at it in that 60% to 70% so that we can track the regulated companies. We believe that we should be viewed as a regulated company. We still track to a discount to the regulateds, which I don't understand that. But secondly, we want to move this company to a point where it's tracked at a premium to the regulated. Because of we've spent a lot of time cleaning the decks here. We're clearing up the story of AEP, and a lot of positive things are occurring. So I think, we -- obviously, it remains to be seen, but something that the board is very in-tuned with.

And our next question is from the line of Julien Dumoulin-Smith with UBS.

So first quick question, perhaps a clarification, if you will. On the industrial segment in sales, the decline in the first quarter here, you mentioned the bankruptcy. Is this a permanent reduction, at least from what you can tell? Or how do you anticipate this playing out to the back half of the year and subsequent years?

We're anticipating, Julien, that they'll continue to operate at their 2/3 of capacity through the balance of the year. We think there's -- obviously, market conditions in aluminum are not very good. There's some political will, I think, to try and keep that plant operating associated with the jobs that are there. And I think that they've continued to operate at this 2/3 level since last summer, and we anticipate that they'll do that through the balance of the year.

Some of this is driven, too, the primary metals is driven by the world market. So we're going to have to see, in particular, Europe and in China things picking up there. But here in the U.S., the manufacturing capability is there. There are expansions going on. And we have a list of future expansions that are occurring, that have been announced, that many of them are in our Western footprint. Our Eastern footprint has the manufacturing capability, we just need the economy to turn around. And certainly, the U.S. is a big part of making that happen. I hope that after we get through all the tax issues and the budget issues and, certainly, the debt issues with Congress, that the economy can start to pick up with some faith that they can invest. And when that happens, and in particular, when the President decides what he's going to do relative to the Keystone pipeline and all the other energy-related infrastructure areas, the AEP service territory is primed because of shale gas, because of coal, because of all of these resources that are indigenous in our footprint, where manufacturing will be able to latch onto that, in particular, chemicals and so forth, to advance. So I don't see it continuing to deteriorate. But the timing is, when it will return.

Great. Secondly, here, if you don't mind. Now that you're further along in the asset transfer process and have gotten at least some interview in your testimony, what are the key issues that you're identifying and how might you address those?

Well, I think, generally, if you -- from the interview and testimony and others, that there's -- they understand that the assets are very favorable. There are questions about whether we should go out for bid, which this is the case, in our opinion, that this is energy and capacity that the customers are already paying for, it's a transfer at net book. So effectively, it's a rate base replacement for a capacity payment that was occurring before. So -- and when you evaluate -- our evaluation, it's less than a new build and, on a long-term basis, even in a short-term basis today, it's very advantageous for the customers in Kentucky and APCo territories. So we have a strong message. The commission certainly is, at least in our view, in the discussions with the governors and others, that they're receptive because they understand these states. They have coal-fired generation. They're located in those states. The supply of the coal comes from these states. We just did a deal late last year that kept some Virginia and Kentucky miners at work. Those are important socioeconomic factors to consider when you're looking at these types of assets. So as the cases move on, we'll see where they go. And I think they could have discussions about the transfer process, who knows, but that to me, I think, we're in very -- we have a very strong message.

And then quick last question here. You've talked before about your desire to grow transmission. Given FERC 1000's tweaks on ROFR, does that change the game plan here? Does that expand the map for you, or is this more of a defensive posture for you as far as it goes?

I think it's in line with what our strategy has been. We've been for the development of competitive transmission. We've developed our Transcos to focus on achieving that critical mass within our service footprint of reliability-type activities. But we are positioned to be, with Transource, a strong competitive transmission provider in this country. So we continue with the joint ventures. We continue with the adjacent companies that we do business with. There's a lot of opportunity there. And we're also very careful about what we asked for incentives for. We ask for incentive structures relative to ROE based upon the way we perceive the risk of those projects. And I think the more transmission providers do that and are very solid and factual about what they ask for, I think FERC would respond. And keep in mind, the transmission piece of it, the earnings is already projects that are in place with the ROEs approved and the structures approved. So we're in good shape there, too.

Our next question is from the line of Steven Fleishman with Wolfe Trahan. Steven I. Fleishman - Wolfe Trahan & Co.: A couple of quick questions. Just first on the sales issue. It's kind of hard to exactly estimate the difference in margin between residential, commercial, industrial and turn that into an overall number. So I mean, if you just look at the first quarter, where the residential, commercial lapped industrial down a lot, could you give us a sense of how you are on track versus budget there on sales so we can kind of get a sense for the year?

Yes, let's see if we can find some numbers here.

Go to slide, which I'm looking for, 15. That will give you some sense for how we were versus last year. If you look at how we're doing, we're behind a bit, Steve. And I can get you to detailed numbers later. But as you can see, our $0.80 on top of $0.80. Whatever we lost in terms of that, we've made up for in weather and rate changes. So we can get you the detail later, but we are right on track for the year.

Margins are extremely lean on the industrial side. And so you're replacing it with, and typically, the margins for commercial customers are significantly higher than industrials and residentials or significantly higher than commercial. So it is a measure of what that this. We'll try and get you some additional information on that. Steven I. Fleishman - Wolfe Trahan & Co.: I mean, maybe to ask another way. If the trend in Q1 continued for the rest of the year where residential was better than you thought but industrial was worse, would you be on track for the year then or do you need...

I think it'd go a long way, it'd go a long way in mitigating the impact of the industrials. And keep in mind, whatever is released from industrials from an energy perspective, we're selling in the market as well. So I think there are a lot of mitigating issues there.

Steve, when you combine that with what we're seeing in off-system sales and how we're on track for the rate changes, we're right on top of where we anticipated being relative to budget. Steven I. Fleishman - Wolfe Trahan & Co.: So kind of on a gross margin basis when you accrued all that stuff, you're on track? Okay.

The great thing about the diversity of AEP. I mean, from the regional footprint, but also the customer side, we typically are 1/3, 1/3, 1/3, commercial, industrial and residential. And it's a good thing when that's happening now. What we have to watch for is the industrials were moving up. They had largely recovered from 2007 by the second quarter of last year. And then we started to see some movement down on industrial, as well -- the commercial and residential were tracking down as well. But with sustained industrial activity, the commercial and industrial started to move up. So what we need to see is the industrial and commercial -- the industrial and manufacturing base continue to improve so that we can have the sustaining quality of increased residential and commercial sales. So it's sort of cyclical, but one lags the other. And we just -- and you're right in terms of the concern that if we continue to see deterioration in industrial and manufacturing, it will have a tempering effect on the increases in the other 2 categories. So we're watching that very closely. But it is promising that customer account is moving up and the economy is starting to prosper in some areas again. Steven I. Fleishman - Wolfe Trahan & Co.: Okay. One other general question. The -- I think this is the first PJM capacity auction you'll be in, is it not an FRR entity? And I'm just curious kind of if you have any thoughts on what to expect and what you're inclusion might mean, if anything, for how much PJMs net, long or short?

Well, it's not the first one. I think we've already been involved with one. We expect this one to be pretty consistent with the last one, give or take, 10%. But it's -- I continue to be concerned about the way demand side management has an advantage over stealing the ground in terms of the capacity markets in that structure. And that needs to change because if you ever want to continue making long-term investments to ensure the stable supply of energy to our customers, we need to make sure that there is a structure in place that's compatible for all types of resources. So that's what I'm concerned about within PJM. There is no long-term pricing structure for anyone to go out and build and construct and finance new capacity. And when you have demand side management that is bidding in just for a few hours during the year but don't have the same level of commitment, that's the issue within PJM. And that's really -- it really makes the capacity markets hard to read.

And our next question comes from the line of Michael Lapides with Goldman Sachs.

First, congratulations, because over the last 2 to 3 years, Nick, Brian, and the rest of your management team have done a very, very good job of transforming AEP. I have 1 or 2 questions, though, just in terms of how you're trying to think strategically about both the nonregulated business and the regulated business. I'll start on the non-reg. And when you look at the portfolio and the size of the retail book, what you don't have is a lot of scale or diversity. Meaning, you don't have a ton of asset diversity. You have almost no regional diversification on the nonregulated side. And your retail business, while growing, is small relative to the industry. And I'm just curious, and I know the McKinsey guys running around your building at some point would probably hate to hear me use this reference, but if you have to plot your nonregulated business on the old kind of, I think, it was the Boston Consulting Group matrix of cash cow, or harvest or I think it was star for the growth businesses. How would you kind of think about that business strategically long-term and your intent for it?

Well, Michael, I've said it previously that we are a regulated company and we're focused on being a regulated company. If we can make this competitive business look quasi-regulated with the hedging associated with it, then that will certainly help us focus on what we do with that business going forward. And keep in mind, too, that the fleet that you're talking about is one of the larger unregulated fleets of the country, I mean, 9,000 megawatts, it is centrally located within the area of the PJM area. But it also is 2/3 coal, 1/3 gas, 2/3 with fully controlled units that are well within the money; 1/3 natural gas, which is going to be at -- probably at the market price. So we see -- I mean, we see this business, particularly if you look at it in its breadth, not just the matter of the generation margins themselves. On the retail side, we're focused on hedging that generation, focused on not megawatt hours but margins. And we're focused on the wholesale activity that we've been doing for years to be complementary to this. So you have to look at it as a total package. And -- but I think even if you look at the generation assets and sales, they are competitive in the market. So I don't care if I have 50,000 megawatts in a market that I'm competitive or 2,000. So it really is a matter of where these units stack up in the marketplace, and they stack up well. And then, secondly, how you're complementing that business and what your focus is. If we wind up with a competitive business that looks like something our shareholders are interested in, that doesn't provide the volatility that makes us look like a regulated utility, then that's fine. But we'll have to get there and see where it takes us.

Okay. On the regulated side, when you look across your service territories, and you've done a good job of positioning the transmission side of the business to grow, and kind of we all know that transmission has its challenges just in terms of the timeline of growth, but that's more of a national issue, not company specific. But when you look at distribution and you look at generation, how do you think about where, over the next 5 to 7 years, your greatest rate based growth opportunities lie?

Well, I think the greatest rate base opportunities are in transmission and distribution, because if we -- if you believe that you're getting into an area where we have generation, but we're also taking a broader view of what resources are, which includes transmission from an optimization standpoint, includes renewables, includes Smart Grid technology-type applications. I think we're in a pretty good position because we don't have any real large central station generation activities going on and we are advancing transmission and distribution. The infrastructure requirements associated with that are tremendous in this industry, and it gives us a distinct opportunity to continue to invest to ensure the service reliability of our customers. So we have a real opportunity here to not be, and I guess it goes to my earlier conversation, to not be off of focus of our customers working on backing in activities like a massive amount of environmental spending, a massive amount of new generation that's very, I'd say, the density of it is pretty high. So from a capital standpoint, we have the opportunity to put capital where it will make the most beneficial effect for our customers and as well as our shareholders. So we are trying to move as much as we can to transmission and the distribution side infrastructure. And also, I would add to that, from the regulated standpoint, we do have a large amount of our service territories still regulated from a generation perspective. So we'll continue to invest in those facilities as well.

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

First question, on the Ohio customer switching. Is that currently on track with how you have budgeted that? I mean, what's in the ESP order? And also related to that, I think for the year, your budget had the gross margins for Ohio utility is down, but through the first quarter, you're flat. So should we assume that Ohio is doing better than planned? Can you just address that a bit?

Yes, we're largely on track with the agreement. I think 53% of our customer load had switched, another 3% in the queue. So it's moving along at a steady pace. And we see that continuing. So I'd say that we're largely on pace and move forward.

Does that include the overall earnings contribution as well? You think that's still on budget as well?

Yes, yes.

Okay. A separate question. On -- after the SWEPCO Texas rate case is done, can you remind us what would be the next big rate case coming up for you guys?

Well, we probably -- as a result of the legislation in Indiana, that gives us a distinct opportunity to focus there on achieving better results, rate related to regulatory lags. So it gives an opportunity to do that. And I think Virginia is also an opportunity for us, as we complete the corporate separation and move forward with that kind of activity. So I'd say those are the 2 jurisdictions. And then we continue to look at other areas as well. But I'd say those are probably the 2 larger ones. And keep in mind, we are making a very large investment in our NIM associated with the Nuclear, the life cycle management process, it's $1.2 billion, $1.3 billion. And that's largely in process of being recovered. So there are some areas of spending that we'll be doing, but I'd say the stage is set.

Understood. And last question, I recall in the past, Brian or Nick, you guys have said in the context of the 4% to 6% annual EPS growth that you've been targeting, that through this transition period in Ohio, I guess, through the '12 to '15 period, more likely the lower end and higher end would make more sense. Is that still the way to be thinking about this?

No, I don't think we said that. We're anticipating the 4% to 6% off the 2013 base. So the full range of the range that we've talked about is in play, even during the transition period.

I see. So off the '13 base. And Brian, over -- is that a 5-year look forward or how should we think about that?

This -- until further notice.

And at this time, there are no other questions. Please continue.

Well, thank you for joining us for today's call. And as always, the IR team is available to answer any additional questions that you may have. And Tricia, can you give the replay information?

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