美國電力 (AEP) 2013 Q1 法說會逐字稿

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 Q&A session. Instructions will be given at that time. (Operator Instructions).

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

Thank you, Trisha. 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 the 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.

Thanks, Betty Jo. Overall we 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 you to a storm change deferral that was reversed because of a law change in Virginia, so we will talk about that later on. Brian will I'm sure.

But the big news is that we increased our dividend by 4.3% or $0.02 to 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.

I view AEP as 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 affectively allocate capital, control our costs through thoughtful and sustainable decision making, reallocate and optimize spending through our repositioning incentives, and make solid investments in operating companies, grow our transition business, and transition our fleet of generation resources, as well as continue the formation of the competitive business through corporate separation. All of this to achieve a financial integrity and objectives that we set forth in the February analysts day meeting and achieve a growth rate of 4% to 6% on a long-term basis. So we are committed to that.

We made much progress during the last quarter, but beforegoing to those areas, let me first discuss what we have 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 sincethe third quarter of last year we continue to see weakness in the manufacturing and industrial sector of our service territory economy.

I think that is true for the country and in fact the world. Primary metals continues to be weak, but is offset in our territory by the oil and gas activity in the Eagle Ford and the Utica shales areas. Those are probably the saving grace of keeping our industrials where they are at.

However, we are now also seeing improvement in the commercial and residential sectors, including increases in customer counts. 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 area 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 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 we 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 our 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 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 are 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 development, and also have not changed our reported investment forecast that we provided earlier.

Other regulatory and legislative activities continue according to plan. Ohio 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 the [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 settle the relevant issues with the major parties in the case.

Cases also filed in Kentucky, West Virginia and Virginia to complete the transfer of Amos and Mitchell units to APCO in Kentucky. We expect orders on these transfers in the June/July time frame. These units are being transferred at net book value. They are fully controlled, andwill replace the capacity payments that these customers are 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 coal supply comes from these states as well, so the Mitchell and Amos units continue to be even more of a value in today's gas market for APCO and Kentucky customers.

Moving on, I would like to refer you to page four of the presentation, which is probably one of my favorite dash boards. I always call it the equalizer graph. But it shows the progress we are making in the various jurisdictions, butI 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 is 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 is at the governor's desk.

It actually went to the governor's desk yesterday, and he has ten days to sign it, and we certainly expect that to happen. So that is very good news addressing the regulatory lag issues 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 are now putting that plant 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 two that were 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 time frame, and retrofits or 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 are very interested in the EPA's proposed rates -- proposed rules that were just released.

Most of the eight options in the proposed water fluent rule are largely in line with expectations, particular with the assumption the coal combustion byproducts will be regulated as a nonhazardous waste. However, there are some extreme options based upon emerging technologies and require additional bottom ash retrofits, so our comments will reflect our concerns that these requirements are not warranted.

Repositioning incentives continue, and I'm 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 our power plants. They continue to go through the power plants, and then we also have reviews continuing 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 the areas and strategic objectives that we have.

So at this point I will turn it over to Brian to give more details of where we stand. Brian?

Thank you, Nick, and good morning, everyone. Let's start on slide five with the reconciliation of this year's first quarter operating earnings to last years.

To begin with it is 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 include a 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-systems sales margin 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 $0.05 per share, and a decline in trading margin accounts for $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 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 51% and 3% respectively.

Allowance for funds used during construction, or AFUDC, was off $0.03 per share in 2013, primarily due to the successful start up 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 pershare 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 occurredthrough you multiple jurisdictions.

Finally, weather was favorable by $0.10 per share 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, weassumed normal weather.

In summary, the adverse effect of is several Ohio related items, lower AFUDC due to Turk going commercial, and a slight increase in OEM were essentially offset by rate changes and a return to more normal weather.

Turning to slide six, you will 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 are 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 will 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 America.

The residential class up 1.3%. Residential customer counts 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 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 in 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 Utica in Ohio.

Let me take some time to provide some economic indicators for AEP's service territories, which continue to experience comparable growth to the US 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 was -- that has just come out for US.

It is worth mentioning the effect of the sequestration and fiscal tightening from Washington is having less of an effect on AEP's service territory relative to the US. Many of the cuts so far related to defense spending, which is more concentrated on coasts and less pronounced in AEP's Midwest footprint.

Employment growth for AEP at 1.5% was slightly favorable when compared to the US 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 US. This is the first time the unemployment rate has fallen below 7% in AEP service territory since the end of 2008.

Turning to slide seven, you will see that four of our top five industrial sectors experienced negative load trends for the first quarter. A significant contributor to 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 sales would have been down 3.7% for the quarter.

Chemical manufacturing down 4.4% for the quarter. It is important to note that last March one of our largest customers in it Texas who owns a co-generation 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 bytwo 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 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 the eastern regulated operations.

The paper manufacturing sector was essentially flat for the quarter, with increases in Ohio sales being largely offset by decreases in the 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 eight 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 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 are 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 nature 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 a backdrop where AEP generation hub peak pricing increased 15%, and around the clock pricing increased 14%. Dark spreads widen considerably, while spark spreads come compressed.

Turing to slide nine, we'll see that the impact of a modest increase in prices for energy had on a very come 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 average around the clock price of $28.65 per megawatt-hour nearly 16,000 megawatts are 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 two core revolving credit facilities. This included the one year extension of both facilities, taking the new termination dates to June 2016 and July 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 the notes, and INM 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 issuance of securitization bonds at Ohio Power and Appalachian Power. These two financings are expected to close this summer and shouldbring in a combined $655 million.

I would 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 ten 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 derisk 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 tenor 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 through you careful capital allocation, O&M discipline, or thoughtfully access the debt capital markets, we have been 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 have come to expect from us.

Lisa Barton and here 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 last year.

Earlier we provided detail coverage of load. We are 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 costs for coal up, but much less so than power prices. This widening of the dark spread should help off-system sales margins, but the low pleases paid by competitive retail suppliers for capacity and low RPM pricing will continue to have its negative impact.

Our regulatory plans are on track relative to our assumptions in guidance. We have a positive track record of putting capital to work for the benefit of our customers and then earning return on that investment by efficiently getting it into rates. This year should continue that record. Of the 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 are well on our are way to meeting our stated goals. With that I will turn the call over to the operator for your questions.

(Operator Instructions). Our first question comes from the line of Greg Gordon with ISI Group. Please go ahead.

Thanks, good morning.

How, Greg, how are you?

Good. Good quarter. 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 are burning, and what the break even cost is between gas and coal of the types of coal you are burning that, whether it is cap nat, Illinois basin, PRB, that has allowed you to switch back?

Typically it is cap coal, and when you look at the [pros] break point on a delivery cost basis, when you were in the $3.25 to $3.50 range on natural gas, you will start to see the switching occur. And based on natural gas prices today, obviously we've seen it just go basically 180 degrees the other direction, but that is a good thing.

And I think the real issue is that we have been able to change our contracting methodologies, particularly on the coal side and the natural gas side, to be flexible enough to adjust generation either way. And it's worked out positively for us.

Greg, when you look at --

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

Yes, that's right. We have a 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 nine 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 is 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 have also been able to take the Northern App coal because of all our 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 is clear that obviously you sold a lot more power and made more are money. Can you take us through the big deltas in the other areas, and what drove those?

So capacity payments were comprised of two items. One is the difference in the CREZ price that we are 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.

Really, the deviations would be because of the capacity payment difference.

That's right.

Thank you, gentlemen.

Our next question is from the line of Dan Eggers with Credit Suisse. Please go ahead.

Good morning, guys.

Hi, Dan, how are you?

Good. Just following up on Greg's question on the coal to gas switching, or gas to coal switching I guess we are calling it now. If you look at the curve having moved up even further, of the 3,800 megawatts of additionally 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?

Yes.

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

Yes, and keep in mind too, the part that kicks up on the curve are primarily peaker units that we don't expect to run much anyway. So you are 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 is going to be unregulated in the future.

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, which ever you like, and see where that crosses the line. (Inaudible -- multiple speakers) --

And then when you guys -- sorry, Brian.

No, go ahead.

When you talk about the coal inventory situation and kind of the normalization, are you assuming -- to get the days covered, are using a historic burn rate or some sort of modified burn rate to figure out the number of days inventory?

It is a full load burn rate. So it's the units that we have at full load burn for those number of days.

And then --

So it's a historical measure that we've use.

Which we have done pretty well in managing our inventories during this process, and that goes to the flexible issue. We are still at 43 days, 44 days of inventory. So we are going into the summer peak period in a pretty good fashion.

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 normal or a little better than normal weather. What gives you guys confidence that you are going to make catch-up over the remainder of the year to get to the positive demand growth? And are you hearing comments from your industrial customers who are out of more clarification of when they are going to be back on?

I think the story that you see on those slides is kind of nails it. The residential and commercial are up, and we are seeing the difficulty in industrial. We may not make the 0.5% 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 is not a one for one type of deal that you are look at. And that is why [it's held] up.

Now, we need the in 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 amatter of making sure it is sustainable so that thee commercial and residential can continue to thrive. In the past the residential and commercial have been really struggling themselves, andnow we are seeing uptick there, and that is what is making the difference.

And also I think the weather was better than last year, but the weather was is still normal.

When you guys --

Go ahead, Dan.

When you guys -- weather normalize it is complicated when you have big deltas from one period to another. When you look at residential, given the big move after having not trying to develop for so long, are there underlying commentary you are seeing that gives you confidence that that holds rather than just being kind of a fluctuation to what happened in the period?

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

Dan, 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. It was significant compared to last year, but compared to normal it is right on top of it. So we are not concerned that weather is impacting those numbers in any significant way.

Great. Thank you, guys.

Your next question is from the line of Anthony Crowdell with Jefferies. Please go ahead.

Good morning. I'm not sure how much color you want to give on this, but you mentioned before the cost advantages you get -- you have with the river operations or delivering coal via barge versus rail. I was wondering if you could talk about that or just help is for modeling purposes to kind of assume what the cost advantages were to be?

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 now perspective, these mines are relatively close. So if there are any railroad movements associated with it, they can still have is higher are rates, but they are 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 purchase from the -- from all across the country, it really [imputes] the practically $2 per ton advantage. So when you look at that across the entire fleet, it is a pretty good advantage.

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 were 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?

You are talking about the railroads?

Or the coal mining, either one.

Or the coal mining. No, we don't see that. We have long-term contracts in place for coal supply from the delivery perspective, and there is plenty of coal out there. I mean, we -- in 2007 we were 80 million tons of coal a year. We are at around 54 million tons this year. So there is a lot of ability there to pick up production. So I think we are in good shape.

Great. Thanks for the time, guys.

Our next question comes from the line of Stephen Byrd with Morgan Stanley. Please go ahead.

Good morning.

Hey, Stephen, how are you doing?

Great. I was wondering if you could talk a little bit about in Ohio about the plans for attracting the merchant generation, I guess when it goes merchant? And 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?

Yes, just keep in mind the only ones that 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 is still looking very attractive. So it is a matter of the -- how competitive your generation is, not only from a marginal cost perspective, but you then obviously the amount of capital left in them. And I think we will wind up in great shape there.

As far as the hedging practices associated with it, we -- that is why we are putting our wholesale shop, who has 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 is moving along.

I think -- obviously our main intent is to make sure that this generation looks as regulated as it can. We anticipate hedging 30% of it with retail. Once we have the generation in our retail mix where our competitive retailer can use that generation, we will be able to go the 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 is incredibly important for us, but also will help us in terms of those hedging practices. So we have great relationships with munis, coops, long-term customers on a third party basis, and we will continue to advance those.

As you look at that -- that is very helpful color. As you look at the forward curve today, does that pose any headwind to achieving that 4% to 6% as you move from the current contracts you have to it market, or is that already generally anticipated as you think about your overall growth?

Yes, it is 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 the 86% that is still regulated -- in regulated jurisdictions. So -- and with transmission as well. So the 4% to 6% is looking pretty good.

Stephen, there is no large uptick associated with any of the capacity or energy prices that is in the 4% to 6% estimate.

That is very helpful. If could just shift quickly to the dividend, you had a really good increase here. As we look out your payout ratio is happily fairly low, so it looks like you still have more flexible. 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 2014 basis it's still below the 60% to 70% range. Could you just talk a little bit about how you think about the dividend increase over time?

That dividend is already old news, isn't it?

Sure is.

What are you done for me lately?

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 it is probably the same answer I gave in February, was that they continue to view you dividend growth being in line with earnings growth of the Company, and they look 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, we 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 we spent a lot of time cleaning the decks here.

We are clearing up the story of AEP, anda lot of positive things are occurring. So I think we -- obviously it remains to be seen, but something that the Board is very in tune with.

Great. Thank you very much.

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

Good morning, guys.

Hey, Julian.

So first quick question, perhaps a clarification if you will. On the industrial segment and sales, the decline in the first quarter here, you mentioned a 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 subsequent years?

We are anticipating, Julien, that they will continue to operate at their two-thirds of capacity through the balance of the year. We think there is -- obviously market conditions in aluminum are not very good. There is 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 the two-thirds level since last summer, and we anticipate that they will do that through the balance of the year.

Some of this is driver, too -- the primary metals is driven by the world market, so we are going to have to see, particularly Europe and in China, things picking up there. But here in the US 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 in our western footprint. Our eastern footprint has the manufacturing capability, we just need the economy to turn around, and certainly the US is a big part of making that happen.

I hope that after we get through all of 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 is going to do relative to keystone pipeline and all of 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.

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

I think generally if you -- 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 in this is a case in our opinion that this is energy and capacity that the customers were already paying for.

It is a transfer at net book. So effectively it is a rate-based replacement for a capacity payment that was occurring before. So -- and when you evaluate our evaluation, it is less than a new build, and on a long-term basis and even on a short-term basis today it is 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 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 is 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. The cases move on. We will see where they go, and I think they could have discussions about the transfer process [itself]. Who knows but that to me I think we are in very -- we have a very strong message.

And then a quick last question here. You talked before about your desire to grow Transmission. Given FERC 1000's tweaks on ROFR, does that change the game plan? Does that expand the map for you, or is this more of a defensive [positive] for you?

I think it is in line with what our strategy has been. We have been for the development of competitive transmission. We have 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 is a lot of opportunity there.

And we are also very careful about what we ask 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.

Great. Thank you for the time.

Yes. 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 are in good shape there too.

Our next question is from the line of Steven Fleishman with Wolfe Trahan. Please go ahead.

Hi, good morning, Nick. A couple of quick questions. Just first on the sales issue. It is 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 up, industrial down a lot. 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?

Let's see if we can find some numbers here.

Yes. If you 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 are doing, we are behind a bit, Steve, andI 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 are right on track for the year.

Okay.

Margins, margins are extremely lean on the industrial side.

Right, yes.

And so you are replacing it with -- and typically the margins for commercial customers are significantly higher than industrials, and residentials are significantly higher than commercials. So it is a measure of what that is. We will try and get you some additional information on that.

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 you industrial was is worse,would you be on track for the year then? Or do you need --

I think it would go a long way. It would go a long way in mitigating the impact of the industrials. And keep in mind whatever is released from the industrials from the energy perspective we are 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 are seeing in off-system sales and how we are on track for the rate changes, we are right on top of where we anticipated being relative to budget.

Kind of on a gross margin basis, when you include all of that stuff you are on track. Okay.

This is the great thing about the diversity of AEP. I mean, from the regional footprint, but also the customer side, we typically are a third, third, third, commercial, industrial and residential, and it is a good thing when that is 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 started to see some movement down on industrials. Well, the commercial and residential were tracking down as well, but with sustained industrial activity the commercial industrials started to move up.

So what we need to see is the industrial and commercial -- the industrial and manufacturing base continue to improve is so that we can have the sustaining quality of increased residential and commercial sales. So it sort of cyclical, but one lags the other and we just -- and you're right in terms of the concern. If we continue to see deterioration in industrial and manufacturing, it have a tempering effect on the increases in the other two categories.

So we are watching that very closely, but it is promising that customer is count is moving up and the economy is starting to prosper in some area again.

Okay. One other general question. I think this is the first PJM capacity auction you will 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 your inclusion might mean, if anything, for how much PJM is net long or short.

It is not the first one. I think we have already been involved with one. We he expect this one to be pretty consistent with the last one, give or take 10%. But it is -- I continue to be concerned about the way demand side management has an advantage over steel in 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 is compatible for all types of resources. So that is what I'm concerned about within PJM.

There is no long-term pricing structure for any one 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 is the issue within PJM, and that is really -- it really makes the capacity markets hard to read.

Great. Thank you.

Your next question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead.

Hi, guys.

Hey, Michael.

First of all, congratulations, because over the last two to three years, Nick, Brian and the rest of our management team have done a very, very good job of transforming AEP.

Thanks, Michael.

I have one or two questions though just in terms of how you are trying to think strategically about both the nonregulated business and regulated business. I will start on the nonreg, 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.

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 ifyou had to plot the 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 you would you kind of think about that business strategically long-term, and your intent for it?

Michael, I have stated previously 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.

And keep in mind, too, that the fleet that you are talking about is one of the larger unregulated fleets in the country. It will be 9,000 megawatts. It is centrally located within the area -- the PJM area, but it also is two-thirds coal, one-third gas. Two-thirds with fully controlled units that are well within the money, athird natural gas which is probably combing to be at the market price.

So 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 are focused on hedging that generation, focused on not megawatt-hours, but margins. And we are focused on the wholesale active that we have been doing for years to be complementary to this. 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. SoI don't care if I have 50,000 megawatts in a market that I'm competitive, or 2,000.

It so really is a matter of where these units stack up in the marketplace, and they stack up well. And then secondly, how you are complementing that business and what your focus is. If we wind up with 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 is fine. But we will have to get there and see where it takes us.

Okay. On the regulated side, when you look across our service territories -- and you have done a good job of positioning the transmission side of the business to grow, and we he all know that transmission has its challenges just in terms of the timeline of growth, but that is 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 rate base growth opportunities lie?

I think the greatest rate base opportunities are in transmission and distribution. Because if you believe that you are getting into an area where we have generation, but we are 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 are 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 -- 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 is very -- I would 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 our are shareholders. Sowe are trying to move as much as we can to transmission and the distribution side infrastructure.

Got it. Thank you, Nick. Much appreciated.

Yes. And also I would add to that from the regulated standpoint we do have a large amount of our service territory that is still regulated from a generation perspective. So we will continue to invest in those facilities as well.

Our next question is from the line of Ali Agha with SunTrust. Please go ahead.

Thank you, good morning.

Hi, Ali.

First question, on the Ohio customer switching, is that currently on track with how you budgeted that and what is in the ESP order?

And 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?

We are largely on track with the agreement. I think 53% of our customer load has switched, another 3% in the Q, so itis moving along at a steady pace. And we see that continuing. So I would say that we are largely on pace and moving forward.

And that includes the overall earnings consideration as well? You think that is still on budget as well?

Yes.

Okay. 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, as a result of a legislation in Indiana that gives us a distinct opportunity to focus there on achieving better results as oppose -- related to the 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 would say those are the two jurisdictions.

And then we continue to look at other areas as well, but I would say those are probably the two larger ones. And keep in mind we are making a very large investment in I&M associated with the nuclear, the life cycle management process that is $1.2 billion, $1.3 billion, and that is largely in process of being recovered. So there are some areas of spending that we will be doing, but I would say the stage is set.

Understood. And last question,I recall in the past, Brian, I think you guys have said, in the context of the 4% to 6% annual EPS growth that you would be targeting, that includes the transition period in Ohio -- I guess through the 2012 through 2015 period -- more likely the lower end and higher end would make more are sense. Is that still the way to be thinking about this?

No, I don't think we said that. We are 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 2013 base. And, Brian, over is that a five year look forward, or how you should we think about that?

Until further notice.

Until further notice. Thank you.

Thanks.

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

Well, 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. Trisha, can you give the replay information?

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