American Electric Power Co Inc AEP
Q1 2013 Earnings Call Transcript
Transcript Call Date 04/26/2013

Operator: Ladies and gentlemen, thank you for standing by. Welcome to the First Quarter 2013 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time. As a reminder, this conference is being recorded.

I would now like to turn the conference over to our host Ms. Bette Jo Rozsa. Please go ahead.

Bette Jo Rozsa - Managing Director, IR: Thank you, Trisha. Good morning everyone and welcome to the first quarter 2013 earnings webcast of the American Electric Power. Our earnings release, presentation slides, and related financial information are available on 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.

Nick Akins - President and CEO: Thanks, Bette Jo. Overall, we had another good quarter and a solid start for the year coming in at $0.75 a share on 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 for all that was reversed because of the law change in Virginia, so we will talk about that little bit later on, Brian will I am 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 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 risk to accompany this 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 cost 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 in generation resources and as well 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 are committed to that. We've made much progress during the last quarter, but before going into 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 continue to see weakness in the manufacturing and industrial sector of our service territory economy. I think that's true for the country and in fact the world.

Primary metals continues to be weak, but offset in our territory by the oil and gas activity in the Eagle Ford and 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 count. 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 all 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 have talked about previously.

First, in transmission, we remain on plan for continued growth and earnings contribution from our transmission business of $0.14 per share this year moving to the $0.36 per share in 2015 that we had discussed earlier in the February Analyst Day.

The Pioneer project received Indiana Utility Regulatory Commission approval and it will be moving forward with construction. A settlement agreement in Missouri related to the public utility status for a Transource Missouri joint venture; that transfer of property and the ability to own and construct has been filed in Missouri and we are awaiting approval there. Meanwhile, at FERC, related to Transource, the ALJ approved the rates and cap structure for this project. So we wait 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 continue 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 – and settled the relevant issues with the major parties in the case. Cases are also filed in Kentucky, West Virginia, and Virginia to complete the transfer of the Amos and Mitchell units to APCo in Kentucky. We expect 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 of 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 are making in the various jurisdictions, but I want to focus on a couple of them. As you might recall from the February Analyst Day presentation, I discussed primarily the regulatory lag issue in Indiana. 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. The Indiana legislation that I 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 it. We certainly expect that to happen. So that's some very good news addressing the regulatory lag issue that we had talked about previously.

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 in June the PUCT order should come about. That order will have rates retroactive back to January 29. So, we should see that would pick up as well. So those are the two 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 refueling of 11,000 megawatts at a cost of around $4 billion to $5 billion over the 2012 to 2020 time period. About one-third 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 eight options in the proposed water (pollution) 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 process as a 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 engaged 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?

Brian X. Tierney - EVP & CFO: Thank you, Nick, and good morning, everyone. Let's start 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 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 return 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 days basis, total overall load would have 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 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 continue 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 service territory, and today's estimated 2.5% growth 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 four of our top five 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 a third 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 two refineries that conducted temporary maintenance on their facilities in the first quarter. Excluding those two 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. 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 two 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 cost 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 two core revolving credit facilities. This included the one 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 an incremental $250 million in credit revolver capacity. Upcoming financing activity will be highlighted by the issuance of securitization bonds at Ohio Power and Appalachian Power. These two 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 three 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 purposeful in building the Company's financial strength. Whether it's from 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 15 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. Delivery 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 condition. 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 an 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.

Transcript Call Date 04/26/2013

Operator: Greg Gordon, ISI Group.

Greg Gordon - ISI Group: So two questions. One, when I'm looking at the slide where you talk 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 the breakeven cost is between gas and coal and the types of coal you're burning, that whether it's CAP, NAP, Illinois Basin, PRB, that's allowed you to switch back?

Nick Akins - President and CEO: Yeah, typically it's CAP coal, and when you look at the price breakpoint on a delivery cost basis, when you're in that 3.25 to 3.50 range on natural gas, you'll start to see the switching occur. Based on natural gas prices today, obviously, we've seen it just go – just basically 180 degrees 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.

Greg Gordon - ISI Group: 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?

Nick Akins - President and CEO: Yeah, 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.

Brian X. Tierney - EVP & CFO: 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.

Nick Akins - President and CEO: And we've also been able to take the Northern App coal because all of our units are fully controlled.

Greg Gordon - ISI Group: 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 the big deltas in the other areas and what drove those?

Brian X. Tierney - EVP & CFO: Yeah, so capacity payments were comprised of two items. One is the difference in the CRES 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.

Nick Akins - President and CEO: Really, the deviations will be because of the capacity payment difference.

Brian X. Tierney - EVP & CFO: That's right.

Operator: Dan Eggers, Credit Suisse.

Daniel Eggers - Credit Suisse: Just following-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?

Brian X. Tierney - EVP & CFO: You mean for the balance of the year?

Daniel Eggers - Credit Suisse: Yeah.

Brian X. Tierney - EVP & CFO: It's considerable, Dan. It's probably another 3,000 megawatts.

Nick Akins - President and CEO: Yeah, and keep in mind too, 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 also keep in mind, this is the entire fleet perspective, not just the part that's going to be unregulated in the future.

Brian X. Tierney - EVP & CFO: 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.

Daniel Eggers - Credit Suisse: When you guys talk about the coal inventory situation and you have the normalization, are you guys assuming to get the days cover using historic burn rate, or are you using some sort of modified lower burn rate to figure out the number of days in inventory?

Brian X. Tierney - EVP & CFO: It's a full load burn rate. So, it's the units that we have at full load burn for those number of days, and that's the sort of historical measure that we've used.

Nick Akins - President and CEO: 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.

Daniel Eggers - Credit Suisse: 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?

Brian X. Tierney - EVP & CFO: I mean, I think the story that you see 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 five-tenth 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.

Nick Akins - President and CEO: 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. That's why it's held up now. We need the industrials and manufacturing to continue to improve, and hopefully, that will occur, a lot of economists are 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 struggling in sales and now we're seeing uptick there, and that's what's making the difference. Also, I think the weather was better than last year, but the weather was still normal.

Daniel Eggers - Credit Suisse: Weather-normalized is always complicated when you have your big deltas from one period to another. When you look at residential, given the big move after having not trended well for so long, are there underlying commentary you're seeing that gives you confidence that, that holds rather than just being kind of a fluctuation to what happened in weather for the period?

Nick Akins - President and CEO: Yeah, I think customer counts – I always joke that maybe the 25-year-olds are finally moving out of the house, but we're seeing customer counts 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're watching it very closely. Brian?

Brian X. Tierney - EVP & CFO: 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.

Operator: Anthony Crowdell, Jefferies.

Anthony Crowdell - Jefferies: I'm 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 was just wondering if you could talk about that or just help us for modeling purpose to kind of assume what the cost advantages would be?

Nick Akins - President and CEO: Yeah, I think the main aspect of it is that 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 all across the country, it really imputes practically a $2 per ton advantage. So, when you look at that across the entire fleet, it's pretty good advantage.

Anthony Crowdell - Jefferies: I know some companies you're talking about, the flexibility in like the whole coal supply chain when gas prices really dropped and that, 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 at previous levels?

Nick Akins - President and CEO: Are you talking about the railroads?

Anthony Crowdell - Jefferies: Yeah or the coal mining, either one.

Nick Akins - President and CEO: Coal mining. No, we don't see that. We have long-term contracts in place for coal supply from a delivery perspective, and there is plenty of coal out there. In '07, we were 80 million tons of coal a year we're 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.

Operator: Stephen Byrd, Morgan Stanley.

Stephen Byrd - 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. We've had a power price uplift, but generally the historic revenues that you've had on those assets relative to the market, there is a delta between the two. 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 are kind of following my question on that delta?

Nick Akins - President and CEO: 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. 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, that's why we are 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 the longer-term contracts and those types of things as well. So, there is -- 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.

Stephen Byrd - Morgan Stanley: 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 anticipated as you think about your overall growth?

Nick Akins - President and CEO: Yeah, it's already anticipated, but the 4% to 6% is generated from what remains the regulated piece. Even in 2015, when this is unregulated, the 4% to 6% comes from that 86%, that's still regulated in regulated jurisdiction, so -- and with transmission as well. So, the 4% to 6% is looking pretty good.

Brian X. Tierney - EVP & CFO: Stephen, there is no large uptick associated with the unit capacity or energy prices that's in that 4% to 6% estimate.

Stephen Byrd - Morgan Stanley: 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 books are always thinking about more. The payout ratio, it looks on '14 basis, is still below that 60% to 70% range. Can you just talk a little about how you think about dividend over time?

Nick Akins - President and CEO: That dividend increase is already old news, isn't it? What have you done (indiscernible). So, our board will continue to evaluate its dividend policy. It does it on a quarterly basis, when we look at it. 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 their 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 regulated, which I don't understand that. But secondly, we want to move this Company to a point where it is tracked at a premium to the regulated, because of – we spend 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 -- obviously, it remains to be seen, but something that the board is very in-tuned with.

Operator: Julien Dumoulin-Smith, UBS.

Julien Dumoulin-Smith - 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 through the back half of the year and in subsequent years?

Brian X. Tierney - EVP & CFO: We're anticipating, Julien, that they will continue to operate at their two-thirds of capacity through the balance of the year. Obviously, market conditions in aluminum are not very good. There are 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 two-thirds level since last summer, and we anticipate that they'll do that through the balance of the year.

Nick Akins - President and CEO: Some of this is driven too, the primary metals is driven by the world market. So, we are 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 or 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. When that happens, and in particular, when the President decides what he's going to do relative to Keystone pipeline and all the other energy-related infrastructure areas. The AEP service territory is prime 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 on to 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.

Julien Dumoulin-Smith - UBS: Secondly here if you don't mind, now that you're further along in the asset transfer process and have gotten at least some intervenor testimony, what are the key issues that you're identifying and how might you address those?

Nick Akins - President and CEO: Well, I think, generally, from the intervenor testimony and others that there is – 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 who 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. And when you evaluate – our evaluation; it's less than a new build and on a long-term basis and even on a short-term basis today, it's very advantageous for the customers in Kentucky and APCo territory. So we have a strong message. The Commission certainly is, at least our view and the discussions with the governors and others that they are receptive because they understand these states. They have coal-fired generation. They are 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 look at these types of assets. So, 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.

Julien Dumoulin-Smith - UBS: Then quick last question here. You've talked before about your desire to grow Transmission. Given FERC 1000s 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?

Nick Akins - President and CEO: 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. We're also very careful about what we ask for incentives for. We asked 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. 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.

Operator: Steven Fleishman, Wolfe Trahan.

Steve Fleishman - Wolfe Trahan & Co.: 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 and commercial up, industrial down a lot, could you give us a sense of how you were on track versus budget there on sales so we can kind of get a sense for the year?

Nick Akins - President and CEO: Yes, let’s see if we can find some numbers here.

Brian X. Tierney - EVP & CFO: 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 the 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're right on track for the year.

Nick Akins - President and CEO: 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 are significantly higher than commercial. So, it is a measure of what that is. We'll try and get you some additional information on that.

Steve 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...?

Nick Akins - President and CEO: I think that it could 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.

Brian X. Tierney - EVP & CFO: 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.

Steve Fleishman - Wolfe Trahan & Co.: So kind of on a gross margin basis when you include all that stuff, you're on track?

Nick Akins - President and CEO: The great thing about the diversity of AEP; I mean, from the regional footprint, but also the customer side, we typically are a third, a third, a third, 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. 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 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 two categories. So we're watching that very closely. But it is promising that customer count is moving up and the economy is starting to prosper in some areas again.

Steve Fleishman - Wolfe Trahan & Co.: One other general question. I think this is the first PJM capacity auction you'll be in, is it not an FRR Entity? I'm just curious if you have any thoughts on what to expect and what your inclusion might mean, if anything, for how much PJM is net, long or short?

Nick Akins - President and CEO: 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 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 structured for anyone to go out and build and construct and finance new capacity. 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 it really makes the capacity markets hard to read.

Operator: Michael Lapides, Goldman Sachs.

Michael Lapides - Goldman Sachs: Congratulations, because over the last two to three years, Nick, Brian, and the rest of your management team have done a very, very good job of transforming AEP. I have one or two questions though, just in terms of how you're trying to think strategically about both the non-regulated business and the regulated business. I'll start on the non-reg. 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 non-regulated side. Your retail business, while growing, is small relative to the industry. 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 had to plot your non-regulated business on the old, kind of, I think, it was the Boston Consulting Group matrix of cash cow or harvest or I think the star for the growth businesses. How would you kind of think about that business strategically long-term and your intents for it?

Nick Akins - President and CEO: Well, Michael, I've said it previously that we are a regulated company and we are 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. Keep in mind too that the fleet that you're talking about is one of the larger unregulated fleets in the country; it'll be 9,000 megawatts. It is centrally located within the area of PJM area, but it also is two-thirds coal, one-third gas, two-thirds with fully controlled units that are well within the money; a third natural gas, which is going to be 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. But I think even if you look at the generation assets themselves, 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. And 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 the 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.

Michael Lapides - Goldman Sachs: 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 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 five to seven years your greatest lead-based growth opportunities lie?

Nick Akins - President and CEO: Well, I think the greatest rate-based opportunities are in transmission and distribution, because 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 back-end 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'll make the most beneficial effect for our customers and as well our shareholders. So, we are trying to move as much as we can to transmission and the distribution side infrastructure. Also, I would add to that, from a regulated standpoint we do have a large amount of our service territory, it is still regulated from the generation perspective. So, we will continue to invest in those facilities as well.

Operator: Ali Agha, SunTrust Robinson Humphrey.

Ali Agha - SunTrust Robinson Humphrey: First question on the Ohio customer switching. Is that currently on track with how you have budgeted that and what's in the ESP order? Also related to that, I think, for the year your budget had the gross margins for Ohio utilities down, but through the first quarter you are flat. So, should we assume that Ohio is doing better than planned? Can you just address that a bit?

Nick Akins - President and CEO: We're largely on track with the agreement. I think 53% of our customer load had switch and other 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 moving forward.

Ali Agha - SunTrust Robinson Humphrey: That includes the overall earnings contribution as well. You think that's still on budget as well?

Nick Akins - President and CEO: Yeah.

Ali Agha - SunTrust Robinson Humphrey: Separate question, 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?

Nick Akins - President and CEO: Well, as a result of the legislation in Indiana, that gives us a distinct opportunity to focus there on achieving better results related to regulatory lag. So, it gives us 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 two jurisdictions, and then we continue to look at other areas as well, but I'd say those are probably the two 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.

Ali Agha - SunTrust Robinson Humphrey: 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 through '15 period more likely the lower end and higher end would make more sense. Is there still the way to be thinking about this?

Brian X. Tierney - EVP & CFO: 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.

Ali Agha - SunTrust Robinson Humphrey: Off the '13 base and Brian over -- is that a five year look forward or how should we think about that?

Brian X. Tierney - EVP & CFO: Until further notice.

Ali Agha - SunTrust Robinson Humphrey: Until further notice.

Operator: At this time, there are no other questions. Please continue.

Bette Jo Rozsa - Managing Director, IR: Well, thank you for joining us for today's call, and as always, the IR team is available to answer your any additional questions that you may have and Trisha, can you give the replay information?

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