美國電力 (AEP) 2014 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power first quarter 2014 earnings conference call. (Operator Instructions) As a reminder, today's call is being recorded. Your hosting speaker, Bette Jo Rozsa, please go ahead.

Thank you, Kevin. Good morning, everyone, and welcome to the first quarter 2014 earnings webcast of 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 filing for a discussion of these factors. Joining me this morning for opening remarks are Nick Akins, our Chairman, 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.

Thanks, Bette Jo. Good morning, everyone, and thank you for joining us today for this first quarter 2014 earnings call. AEP had a very strong quarter driven incrementally by the coldest weather in 35 years and increased market energy prices. I say incrementally because, first, even with the polar vortex, as if it had not occurred in normal weather and market conditions would have prevailed, we would still have had a quarter that met our objectives of the plan we proposed to you in November last year at the EI.

And second, I would maintain that because of the initiatives previously implemented by the Company regarding improved capital allocation to transmission and the operating companies, focus on process improvement activities such as lean in our power plants and wires businesses, and the development of our unregulated generation business we would not have been successful in capturing the value of the [off-system] sales benefit from the extreme weather and market conditions as a result of the polar vortex.

I can give you several instances that it was apparent that the cultural initiatives that have instilled team work and ingenuity paid off to ensure our generation was available to the benefit of our shareholders and our customers. Before Brian and I get into the details of the quarter, let me go over the headlines for the quarter and for the remainder of the year. AEP earnings for the first quarter, both GAAP and operating, came in at $1.15 per share compared with $0.75 GAAP and $0.80 per share operating for first quarter 2013.

Because of the strong results, and after review of cash flow and earnings metrics for the remainder of the year, we are increasing our 2014 guidance from $3.20 to $3.40 per share to $3.35 to $3.55 per share. We are reaffirming guidance for 2015 and 2016 in the 4% to 6% earnings growth rate based upon the original guidance given in 2013. We will continue to monitor the fundamentals, in particular, load and energy markets along with the progress of our previously announced initiatives to announce any further guidance detailed during the EEI financial conference in the fall.

Additionally, as we mentioned to you in our last earnings call, if we were to get ahead from a cash and earnings perspective, we would reinvest from cash flows and retained earnings in more transmission and move projects from 2015 and 2016 into 2014 to alleviate pressures that exist in those later years. Because of the excellent operations of our plants and continued focus for our employees regarding continuous improvement we are able to do just that. Consequently, AEP will invest $200 million more in the transmission projects that was identified in the green area of my second most favorite graph, the transmission graph that you've all seen previously, and will also move $60 million to $70 million of 2015-2016 spending into this year.

This is still a lot more work to be done, because we are not counting on increased load or capacity market revenues. That's not the way we're running our business. Now I said before, our business is now an optimization business, and one in which we continually adjust to changing conditions to ensure discipline and execution that drives consistency for our shareholders and value for our customers.

Even though we now have the winds at our back somewhat because of first quarter results, our focus will not change. We will continue our capital allocation approach defined earlier, thoughtful prioritization and control of O&M expenses, continued development of our unregulated business, and the continuous improvement in cultural initiatives. The implementation of lean activities and other continuous improvement initiatives continue to produce expected results, and we are pleased with the progress our employees continue to make in this regard.

This effort will not slow down because it is now engrained in our decision making and how we do business, and this progress will not be jeopardized because we all know that one quarter does not make a year, and it certainly doesn't make three years. On the regulatory front, we have filed the PSO rate request, requesting $45 million of addtional revenue focused on infrastructure and AMI meter investments, as well as SPP-related transmission charges.

Interveners have filed testimony asking for varying levels of reductions, and hearings are set for June, and we expect an order by the end of the year. We have filed in West Virginia and FERC to allow the transfer of half of Mitchell Plant to Wheeling Power to provide needed capacity and energy to serve Wheeling customer load. Hearings are set in August in West Virginia and the FERC case commenting period ends in May, so everything is on track with the remaining initial transfer.

We have also filed in Virginia for the biannual rate review. While we are not asking for a rate increase because our ROE is within the statutory bandwidth, we are seeking some rate adjustments within customer classes and a requested ROE of 10.52%. Hearings for this case have been set for September.

I would also like to point out the progress that's been made with the capacity construct within PJM. The FERC has agreed with PJM on many of the capacity auction adjustments that AEP supported, as well, to enable the recognition of the value of steel in the ground generating assets within PJM's footprint. These changes, while not completely adequate, are moves in the right direction to not only enable a more balanced portfolio of resources, but also maintain the integrity and reliability of the grid, particularly at times of extreme stress being such as with the polar vortex.

Just as an side, I had previously reported 89% of coal units slated for retirement in mid-2015 ran during the polar vortex, that is also true for the quarter. But another interesting tidbit is that these units ran at a substantial 46% capacity factor during the quarter. So the need for this coal capacity was not just an aberration, but an integral part of the maintaining comfort for our customers during the extreme cold weather. The capacity market changes are important because this capacity construct also defines the revenues and price signals for investment, as well as the bandwidth around the volatility of energy prices.

When energy prices move as high as $1,800 a megawatt hour, this should be an indication that capacity markets are not operating properly. This is bad for investment and resources, ultimately bad for the reliability of the grid, and certainly bad for the customers in the end. We're also pleased that Congress is now getting involved with hearings in the House and Senate to shed some light on the confluence of pending and existing EPA rules, electricity and natural gas coordination, physical and cyber security issues related to the grid, and capacity market issues, all of which impact the resiliency of our country's electric supply to fuel the needs of our customers and the economy.

Now off to my favorite graph, which I typically call the equalizer graph on page -- I guess it's page 4 of the presentation -- we'll go through and step through some of the states that we're looking at here. As far as overall, it looks like we're at 9.9%, and that's close to the 10%. We expect that to improve.

We've got, from an Ohio Power perspective, I know it's showing 13.1%, but that includes some non-recurring items, particularly [seat] adjustments and transmission true-up related cost that will bring that down to that -- below that 12% allowed return threshold with the seat test. So that's going to come down.

APCo continues to improve, and certainly two jurisdictions there from the Virginia standpoint. We're in good shape. I talked about that earlier. For West Virginia, we'll plan to file a rate case this year because of the returns there in that jurisdiction.

We have a current ROE range of 10% to 10.9% in West Virginia, but we're certainly underperforming there from an ROE perspective. So we'll file a rate case there. Kentucky is still pretty much stomaching the settlement that was done relative to the Mitchell transfer, and we'll fully expect to file a rate case during 2014, at the end of 2014, that would be effective by July of 2015.

In the meantime, though, off-system sales and other benefits from the operation of Mitchell and Big Sandy will provide benefits to Kentucky. So we expect that to continue to improve. I&M has improved markedly since the last time we discussed it. It was on the order of 7% back in February of 2013. They've made considerable progress with the addition of the Cook lifecycle management projects, and, as well, as other off-system sales revenues that occurred during the cold weather.

PSO is in the midst of a rate case, as I mentioned earlier. So we expect that outcome by the end of the year. So that will be an opportunity for us, as well.

SWEPCo continues to have the issue of the part of the capacity of Turk that was slated for Arkansas and they continue to work on ways in which to deal with that situation, and other areas like transmission costs and other measures to improve the ROE there. So we expect that to come up.

AEP Texas includes a securitization, so it is always showing high at 13.7%. But also has considerable customer growth, so it should stay in there pretty steady. And then the AEP Transco Holdco, we continue to invest heavily in that area. So you'll see the return there show up lower than what actually is the authorized and the actual returns there in that part of the business.

And we intentionally will drive more investment into that area as evidenced by the $200 million I talked about earlier. But that's a good story, and we'll continue to do that. So it really shows that the benefits of being able to properly allocate capital and work on the operating company side of things to ensure that we are improving from an ROE perspective.

So we feel pretty good about where we sit from a regulated results perspective. They're all strong. And that provides the foundation for our business. So after an excellent quarter, as we look at the remainder of 2014 and into 2015 and 2016, we'll be looking at the following sensitivities in our modeling and earnings expectations.

First, the continued weather adjusted effects on load forecast in each customer category, which Brian will talk about a little later. Energy prices that appear to be increasing, but not clear given the lack of long-term liquidity in the market. Shale gas-related growth in the service territory, which Brian will cover in detail, continued progress on process improvement initiatives which continue to move forward in the Company in a very positive way.

Additional transmission capital allocation opportunities that may exist. Rate-related activities, as we mentioned earlier, and certainly the unregulated business from the cost side and the revenue side. I'm reminded of an old adage that says it is better to be lucky than good. We at AEP believe that it is much more desirable to be good and lucky.

I know you Pittsburgh Penguin fans, Chuck Zebula being one of them, may not like this, but I recently attended the most recent Columbus Blue Jackets/Pittsburgh Penguin playoff hockey game. Columbus initially had trouble controlling the puck and quickly fell behind in the first period by a 3-0 score. It looked like it was going to be a long night.

But with focus on the fundamentals, with discipline and execution, scored a goal in each period and won the game in overtime. In the old adage, good speaks of the fundamentals and lucky speaks of a free option that cannot occur if the fundamentals are not present. AEP is focusing on the fundamentals, and the rest will take care of itself. That's the story of the first quarter of 2014. Over to you, Brian.

Thank you, Nick, and good morning, everyone. On slide 5, you will see our comparison of 2014 results to 2013 by segment for the quarter. As we announced last fall at the EEI conference, we have adjusted our earnings presentation to align with our business segments following our corporate restructuring.

The segment reporting detail for the first quarter of 2014 and pro-forma for 2013, can be found in the supplemental information package posted on our website and in the 10-Q that we plan to file later today. The recently completed corporate separation provided the occasion for us to define segments that make our reporting simpler and more transparent. For the Company overall, operating earnings for the first quarter were $560 million, or $1.15 per share, up $0.35 per share compared to the $387 million, or $0.80 per share recorded last year.

Generally, the year-over-year improvement was realized across all segments and was driven by new rates that reflected our increased customer focus investment, strong generation performance that captured high prices for wholesale power, and high weather-related retail sales. With that as an overview, let me step you through the major earnings drivers by segment on slide 6. Earnings for the vertically integrated segment were $0.57 per share, up $0.16 per share compared to the first quarter of 2013.

Significant drivers include customer focus investment in our utilities that resulted in rate changes across many of our jurisdictions, adding $0.08 per share for the quarter. In addition, the effect of extreme weather temperatures improved earnings by $0.07 per share. Heating degree days were 25% higher in the East and 30% higher in the West when compared to last year.

Higher wholesale power prices and strong performance by our generation group bolstered off-system sales which benefited shareholders and customers. The higher off-system sales improved earnings for this segment by $0.11 per share, while customers across several of our jurisdictions will realize $74 million through margin sharing mechanisms. The year-over-year increase in retail and wholesale margins were partially offset by higher O&M, depreciation and other items.

The increase in O&M adversely affected the quarterly comparison by $0.03 per share due to a favorable insurance settlement recorded in 2013, and higher employee-related costs, somewhat offset by lower storm expenses. The higher depreciation expense resulted from increased investment in plant, reducing earnings by $0.02 per share. Finally, other items in total were off by $0.05 per share primarily due to higher costs from PJM that were not covered through regulatory tracking mechanisms.

The Transmission and Distribution Utilities segment results were also higher than last year by $0.02 per share, driven by positive rate changes and extreme weather in Texas. The Transmission Holdco segment continues to grow, adding $0.02 per share for the quarter, reflecting our continued significant investment in this area. From March of last year to March of this year, this segment's net plant grew by nearly $1 billion, an increase of 99%.

The Generation & Marketing segment had a strong quarter, adding $0.15 per share to our quarterly comparison. This segment benefited from the strong performance of its generation fleet and commercial organization, as well as higher wholesale power prices. I will discuss this in more details on the next slide. AEP River operations continues to rebound from the recent drought conditions, adding $0.01 per share.

Finally, corporate and other results were off a penny per share due to lower interest income at the parent. In summary, our earnings performance was strong, largely due to the effects of positive rate adjustments, strong generation and commercial performance during periods of high prices, and weather-related improvements in retail sales.

Turning to slide 7, let's take a look at AEP generation resources. This competitive generation business was the driver behind the positive quarterly results for the Generation & Marketing segment. The extreme temperatures and energy consumption during the quarter significantly impacted energy pricing. For the quarter, AEP Gen Hub day-ahead prices for around the clock power settled 100% higher than they did a year ago.

Henry Hub natural gas prices were 45% higher. In the face of these extremes, our competitive generation team and the commercial organization we have built around it, performed exceptionally well. Volumes for this fleet were up 22% and capacity factors were up 10%. The competitive generation fleet has about 2,500 megawatts of capacity that will retire by next summer.

Approximately 1,800 megawatts of that capacity operated during the first quarter. Those units experienced a capacity factor of 52%. On the right of the slide, you will see the percentage of sales by channel. The data shows that about 69% of generation resources sales had a hedge in the first quarter, and about 31% were exposed to short-term, or spot pricing.

This allowed the commercial and generation teams to capture higher margins as their output was needed to meet demand during high price periods. We view our competitive retail business as a positive margin hedge for our competitive generation. This business performed well during the first quarter.

Now if you'll turn to slide 8, we'll see our usual detail on normalized load. We are repeating the format we introduced last quarter that shows the industrial and total retail sales trends adjusted to reflect the loss of Ormet's load. On the bottom right quadrant, you can see that for the quarter weather-normalized total load was up 1.5% compared to last year. Excluding Ormet, our normalized total retail sales were up 3.2%.

On the bottom left of the slide, you can see that while our reported industrial sales growth was down 2.9% for the quarter, we continue to see steady improvement despite the loss of Ormet. Excluding Ormet from the comparison, our industrial sales were 2.2% higher for the quarter. In fact, eight of our top 10 industrial sectors showed positive growth compared to last year.

The two sectors with declining industrial sales for the quarter were primary metals, which was influenced by the shut down of Ormet, and mining, except for oil and gas, were the shale gas revolution and increasing environmental regulations adversely impacted demand for coal. Residential sales, shown in the upper left quadrant, were up 4.4% for the quarter. We did see some improvement in our residential customer accounts, but most of the increase in residential sales was due to higher average usage.

Finally, in the upper right quadrant, you can see that commercial sales increased 2.9% for the quarter. We saw customer growth in the commercial class of eight-tenths of a percent and higher growth in average usage. Commercial sales growth was the strongest in the western footprint where we also saw the strongest growth in employment. While we are happy to see increased volumes in our residential and commercial classes, we have concerns that our traditional weather normalization models do not fully capture the change in consumers behavior during extreme weather events, as was the case this winter.

Now I would like to take a few minutes to describe the most recent economic activity within AEP's service territory. On slide 9, you will see that we are introducing a few new charts to give you some perspective on how the economy within AEP's service territory compares to what you may have read about for the US. First, looking at GDP for the quarter, you can see estimated growth for AEP continues to outpace that of the US at 3% and 2.7%, respectively.

The chart on the upper right shows that GDP in our western service area continues to out perform the US and our eastern service territory. The bottom left chart displays employment growth within AEP's footprint compared to the US. For the quarter, employment growth for AEP's service area was up 1.4% compared to 1.7% for the US. Growth in employment trends tend to lead growth in retail sales, and that has proven true for AEP this quarter.

Finally, turning to the chart on the bottom right, it is clear that the job market in our western footprint is consistently stronger than the US and our eastern footprint. Even though US employment growth moderated somewhat in Q1 compared to Q4 of last year, we saw a continued improvement in employment growth in both the eastern and western parts of our service territory over the past two quarters.

The last thing I want to discuss about load growth for the quarter is on slide 10. As I mentioned on previous calls, we are seeing quite a bit of growth related to shale gas activity. AEP is fortunate to have a number of major shale regions located within our service territory. The top chart illustrates the distinction that we are seeing in industrial sales growth between major shale regions as compared to non-shale regions.

While we are seeing improving trends in both areas, the contrast is significant. For our shale counties, excluding Ormet, industrial sales were up almost 30% in the first quarter, while industrial sales in non-shale counties were down four-tenths of a percent. This is significant for AEP, because 17% of our industrial sales are located in shale-rich geographies. The bottom chart shows the industrial growth by major shale region.

As you can see, the most significant growth over the past two quarters has occurred in the Utica area in Ohio and the Permian Basin in Texas. We have already seen significant industrial sales growth around the Eagle Ford area in Texas and the Marcellus shale in West Virginia dating back to 2012. We are projecting new loads to be added in all five of the listed shale regions over the next several years.

Turning to slide 11, let's review the financial health of the Company. Our total debt to total capitalization is now at 54.2%. Our credit metrics, FFO interest coverage, and FFO to debt are solidly in the BBB and Baa1 range at 4.9 times and 19.9%, respectively. Our qualified pension funding stands at 99%, and our other post-employment benefit obligations are more than fully funded at 122%.

Our liquidity stands at about $3 billion and is supported by two revolving credit facilities with tenors that extend into the summers of 2016 and 2017. On January 31, Moody's upgraded AEP Inc.'s senior unsecured rating and the ratings of six of our operating companies. In its release announcing the upgrades, Moody's cited its more favorable view of the credit supportiveness of the US regulatory environment. Moody's also noted AEP's diversity of utilities, subsidiaries' cash flows, the Company's successfully executed corporate restructuring, and its growing rate base.

We have worked hard over the last several years to achieve the credit metrics and balance sheet strength demonstrated here. It is because of this strength that we are confident in funding the incremental transmission investment for this year that Nick mentioned earlier. Finally, let me summarize the quarter and where we go from here. The first quarter was very strong from an earnings standpoint, operationally, and by what we were able to accomplish for our customers.

In spite of extremely cold temperatures, our generation team was able to keep our units running and our transmission and distribution employees were able to deliver energy to our customers to keep people warm and to keep businesses running. We insulated our retail customers from much higher wholesale electricity prices. Due to the transition plan in Ohio, we were able to deliver our Ohio standard service offered customers savings of $132 million relative to the PJM day-ahead market pricing for the quarter.

In addition to our Ohio customers, regulated customers of our integrated utility businesses benefited from the off-system sales margins to the tune of $74 million, an increase of $57 million over last year's first quarter. At the EEI conference in November, and on the last earnings call, we talked about how we would fill the revenue gaps in 2015 and 2016 as our transition in Ohio comes to an end.

At that time, we identified three efforts; one, continuous improvement, including lean initiatives; two, cost shifting out of 2015 and 2016; and, three, funding our transmission investments above base allocations. In regards to the continuous improvement efforts, employees have now continued lean initiatives at six of our generating plants with plans to complete an additional seven during 2014.

On the distribution side of our business, we have a total of 32 work districts. Two of these districts have completed lean initiatives, five are in process now with an additional six more to be completed this year. In places where employees have engaged in lean practices, we have identified cost savings through more efficient work practices and better utilization of the contractor workforce.

Our transmission, supply chain, procurement and corporate center organizations are engaged in similar programs demonstrating that continuous improvement and employee engagement are part of our culture. In regards to cost shifting, we have identified between $60 million and $70 million in work that we will accelerate into 2014 from 2015 and 2016. The financial results of the first quarter give us confidence that accelerating this work will benefit our customers this year and our shareholders in future years.

In our Transmission Holdco segment, we had identified a base level of capital investment that was part of our budget forecast, as well as a high case for incremental capital investment. The strong first quarter results give us confidence that we can fund an incremental $140 million in Transmission Holdco business, and an additional $60 million in operating company transmission spend. We intend to fund this investment from operating cash flows and retained earnings and do not plan to issue incremental debt to do so.

This accelerated investment means that our transmission customers will realize enhanced reliability sooner and our shareholders will realize higher returns. Finally, in addition to the activities mentioned above, as Nick mentioned earlier, we are able to raise our earnings guidance for 2014 to a range of $3.35 per share to $3.55 per share. At this time, we are reaffirming our guidance for 2015 and 2016.

As is our custom, we will likely present detailed guidance for future years at the fall EEI conference. With that said, the strong first quarter of this year has enabled us to execute against our plans with confidence, and to deliver on our commitments to our customers and shareholders. I will now turn the call over to the operator for your questions.

Thank you. (Operator Instructions)

First question from the line of Dan Eggers, Credit Suisse. Please go ahead.

Good morning, guys.

Good morning, Dan.

Listen, a couple of your neighbors in Ohio have made announcements that they're looking to exit their generation assets through a sales process. Can you just give us an update on what your thought process is for your fleet and what bearing the first quarter may or may not have had on making that decision?

Yes, I think our process is unchanged. We've said earlier that we're going to be focusing on producing value out of that piece of the business, to position that business the best we can, to try to take some of the volatility out of the business, and certainly to do what we can from a cost standpoint within that business. And Chuck and his team are definitely working on all of those activities.

The first quarter doesn't change our opinion of our look at that business one way or another. And I think that as we go through the process, we still have yet to see those precursors that we talked about earlier. What happens to the capacity markets, certainly what happens to the energy markets, what we can do with the cost structure of that business, and then how do we take the volatility out of the business with, not only the capacity markets, but the hedging activities that are occurring in the background relative to that unregulated generation.

But we're still on the same time schedule, having the same discussions with our Board as we go through this process. And we'll continue that and make decisions later on in this year and the next year.

I guess, Nick, one of the ideas if you could find people who would sign longer-term contracts you would be interested in staying in those assets. With the first quarter volatility and kind of (inaudible) market conditions, are you having a change in tone in those conversations at this juncture?

Yes. It's sort of interesting. There is discussion about long-term purchase power arrangements that could occur relative to this generation. I think the polar vortex and the sense that there's -- certainly there's no -- when you look at the long-term markets, it's illiquid. There's not much out there going on.

And it sort of tends to keep those prices low in the future. But we know that the closer we get to this generation retiring, that's likely to change. And I firmly believe there is a renewed interest in what that generation looks like, and how it can preserve from a long-term PPA perspective, customers' expectations taking out that volatility and having some consistency.

Yes, we are getting some interest in that, yet to determine what that means. But if we see sustained energy prices that are higher than anticipated, and the capacity markets move up, I'm sure that degree of interest will intensify, as well. Again, our position has not changed relative to that. If we can make it look quasi-regulated, then it's a business that's worth taking a look at.

Great. Thank you. Just one last question. Can you give us an update on where coal inventories are at this point in time and the strategy around the country of full availability for the summer?

Yes. So we're fine on coal deliveries. We're at about 25 days on average on the system. We were 35 days going into the winter. And keep in mind our supplies are taken to the Mississippi and then we have the barge business to bring that coal to the plants. So we're in good shape there.

And most of our deliveries were over the Union Pacific railroad and their performance has been reasonably well done, as well. I think as we move into summer, that's when inventory levels start to improve. But in anticipation of warmer weather over the summer. But we're in great shape.

Dan, we've heard of some people doing things like burning more gas to build up their coal inventories. We went into the winter fairly healthy and we haven't had to change our dispatch or commitment at all in response to our coal levels.

Great. Thank you, guys.

Sure.

The next question is from the line of Brian Chin of Bank of America Merrill Lynch. Please go ahead.

Good morning, Brian.

Hi, good morning. On the $60 million to $70 million in cost shifting, is it fair to think about that as that's a cumulative amount of cost shifting from 2015 and 2016 into 2014?

What do you mean by cumulative?

So $60 million to $70 million in bringing forward costs from 2015 and 2016 together? So, in other words, the expense levels in 2015 and 2016 prior to this announcement we should have thought about as being $60 million to $70 million higher over the two years?

Yes. It was forecasted to be spent for us in 2015 and 2016, and we've now taken those costs and activities out of 2015 and 2016 and are now reflecting them in 2014.

And is that more of a front end loaded, as in more 2015 level of cost shifting, or is it more back end loaded as in 2016? And then also, could you give a little bit more of a business segment breakdown of that cost shifting?

It's evenly spread across both years, and it's across all of our business segments with a significant component of it coming from generation and moving outages out of those years into 2014.

Excellent. Thank you very much.

Thank you, Brian.

And the next question is from the line of Stephen Byrd, Morgan Stanley. Please go ahead.

Good morning.

Hi, Stephen. How are you doing?

Great. Thank you. I wanted to talk more about your high case growth plans in transmission. You're showing real good progress this year.

Could you maybe talk at a high level as to, as you think about what needs to happen to be able to achieve that growth over the next couple of years in terms of whether that would be approvals or planning efforts, resource, whatever it might be, just how we should think about the risk of execution, or what approvals, what milestones, you need to be able to hit to achieve that growth?

We've been very clear for probably two or three years now that -- I don't know if you can recall the slide that had the base transmission and then it had a green piece above it that was incremental transmission that were real projects that were ready to be done. But we had to find the capital to do it. And what you see in this quarter is a refocus of $200 million on that incremental green portion.

So as far as risk, there's very little risk associated with those projects. They're already identified, ready to be done. And you can expect those returns relative to those investments to occur. And as we look forward to the business, I think we've been a proponent of Order 1000 and very focused on our joint ventures, as well, and our Transource entity, ETT and others.

And they have moved forward pretty well, as well. So we continue to look for ways to continue to improve the transmission earnings profile, and that's a very distinct focus for us. But the only things we're reporting are real projects. And we sort of learned our lesson awhile back about the supposition of what may happen. We've gotten over that.

Stephen, the beauty of the chart that shows the incremental transmission spend that we can make going from the base case to the high case is that we can fund that serially as capital becomes available. So whether it's cash flows from operations, if bonus depreciation should get approved later this year, we can serially fund that incremental growth capital on a year-by-year basis.

And as we've talked about earlier, cash flows from operations enabled us to do it this year, and we'll just see how the end of this year and future years play out. But since we have that growth opportunity existing within our own business, that's an awful smart place for us to put incremental capital to work.

That's great color. Thank you. And just a follow-up on transmission, when you look at the competitive side of the business, I was just curious if you could talk at a high level as to the competitive dynamics there?

How competitive is it? How do you assess your capabilities versus others? How is that business playing out?

I think we are absolutely well positioned from a competitive standpoint. Obviously, that's why we've been a proponent of it. But when we look at the projects that we do, the project flow, the project management structure, the engineering expertise that we have and the fact that we've got joint ventures around portions of the country, and just the scope of our transmission system drives the benefits for our investors relative to transmission.

We're well positioned in terms of the breadth. And if you're plowing $1.7 billion a year in transmission projects, which that's what we're doing over the next three-year period each year, that's a pretty substantial critical mass around the growth of transmission. So we're not gold plating anything.

We're not trying to find projects just to do projects. These are all needed projects in terms of refurbishment and reoptimization of the grid with retirements in generation and so forth. So a very clear path for the business case relative to transmission as far as AEP is concerned.

That's great color. Thank you very much.

Yes.

Okay. Next question is from the line of Julien Dumoulin-Smith UBS. Please go ahead.

Hi. Good morning.

Good morning, Julien.

So quick follow-up there on the generation business. I'd be curious, is there any palatability in Ohio as you're thinking about it to perhaps see some of those longer-term contracts against the remainder of the generation business in particular?

Yes, it's sort of an interesting thing. Ohio certainly needs to take notice in my opinion of what happened during the polar vortex. And I would have to say that there is discussions going on relative to how Ohio would deal with that in the future because it's a clear indication that we really do need to think about the portfolio for Ohio customers that has a long-term component and a short-term component to it, and customers are continued to allowed to switch.

But keep in mind, we separated our generation, and it is separated. So if we were to do purchase power arrangements and that kind of thing, it would have to be something that provides value to consumers on the long term, but also value to the Company as far as hedging that generation for the long term. And I think there is a distinct opportunity for those types of discussions.

It's a positive for us, it's a positive for Ohio, and it's certainly a positive for consumers in the long run, particularly industrial customers who looking to the polar vortex and where energy markets went, and there's a high degree of concern about that. So more work to be done there.

Interesting. Is it about saving some of the more marginal coal assets kind of in a more normalized environment, or is this about just, again, security of supply? I suppose you could kind of cut it both ways?

I think it's cut both ways. When you look at jobs, taxes, certainly generation within Ohio, and the fact that Ohio really depended upon the capacity markets to provide long-term price signals, we know that's not going to happen, or at least not has happened thus far. So there is a degree of interest there that needs to occur relative to taking matters in their own hands from an Ohio perspective.

Interesting. And I would be curious, following up on all of the Utica discussion, are you seeing any nascent development on the gas project front? I would be curious just in terms of a new gas plant entry and also broadly where gas basis is headed in your neck of the woods up there?

Well, I think it's a challenge in Ohio because, certainly from a Utica standpoint, it's a great opportunity to use a resource that's indigenous within Ohio. But at the same time, you've got to have the fundamentals and the market and an improving economy to drive that investment. And right now you have at least some glimmer of hope on the economic recovery, but at the same time the market signals just aren't there. So we need to get that solidified before you see a natural gas-type development.

Great. Thank you.

Thank you. Next question is from the line of Greg Gordon, ISI Group. Please go ahead.

Good morning, Greg.

Good morning. So I understand you're taking the opportunity to accelerate some expenses into the year given the phenomenal opportunities you had in the first quarter and the earnings result.

But then also looking at the updated earnings guidance range, are you assuming as a baseline that your annual sales forecast comes in as originally articulated, or are you assuming that you see the trend line as you saw it in the first quarter?

We haven't changed the load forecast at this point in the guidance, even in the adjusted guidance range that we've now given. Because we're very clear that one quarter does not make a trend. And certainly from a polar vortex perspective, because there was a continued cold weather -- could that have skewed the weather normalization routines that we usually go through to adjust these numbers.

Whenever you get extreme heat or extreme cold for a long period of time, you would have to question that. So we're going to have to see some, during this coming quarter and the third quarter a consistency around that before we make those kinds of adjustments. And we're being deliberately conservative there.

Greg, we are forecasting -- we have factored into the forecast the higher wholesale prices for the balance of the year.

Yes. As far as energy prices, that's changed.

Okay. So you factored in higher, sort of ATC wholesale prices, but you haven't assumed any more volatility of the nature that we saw?

No.

No.

And then you're saying that, when I look at page 8, that 4.4%, 1Q 2014 residential weather normal number, you're saying you're nervous that it might not be an accurate number and, therefore, you want to see how things trend in the second and third quarter?

Yes, I'm just saying we don't know to the degree at this point to really make that adjustment. But I think it's pretty clear, though, that directionally it's in the right direction. It is increasing.

The question is the order of magnitude. And before we make that adjustment, we want to be very secure in what we're seeing.

Greg, for the first time in some time, we saw in both the residential and commercial classes significantly higher average normalized usage. And we're concerned that the normalization models don't behave as well at describing the weather effects versus the normal effects in extreme weather. So we would like to see another quarter before we start thinking about changing the balance of the year load forecast.

Great. Thanks. Obviously, great start. Congratulations.

Thank you.

Thank you, Greg.

Next question is from the line of Paul Patterson, Glenrock Associates. Please go ahead.

Good morning.

Good morning.

The sales growth forecast, the 10-year load forecast that you guys recently put out, indicates kind of, sort of lower growth over 10 years. I guess negative growth or just flattish or what have you. And I was wondering if you could sort of comment on that and whether or not you think that might change with the legislation that's being proposed, and just sort of how we should think about that?

I guess this is all Ohio. I'm sorry. If you could just sort of discuss sort of a little bit about that and what you think is going on there?

Yes. So sort of a frame of reference that was used in that. If you looked at, sort of comparing apples and oranges because one includes Ormet. Obviously, the future anticipated it does not. So if you exclude Ormet, the energy is increasing.

Okay. But the load forecast itself, when I look at it, seems like it's declining or just slightly flat really over the years. It doesn't look like there's really much change, let's say, from 2016 to 2024?

Yes, that's true. We've been anticipating for a period now that load forecasting would be relatively flat. And we haven't changed that, because we haven't seen the longevity of the fundamentals. We've seen initial indication in the fourth quarter of last year. I think we've seen a broader indication this first quarter. But I think we'll be more comfortable when we see another quarter or two and make that determination.

Okay. Does any of this have to do with the legislation that's being -- that's currently in place or might change in Ohio, or could that have an impact that we should think about? And if so, can you give us a feeling for that.

No, overall, the energy efficiency was pretty negligible to begin with in the overall scheme of things. But as far as the legislation is concerned, it's not a significant impact at all.

Okay. And then just following up on Julien's question on sales -- I'm sorry -- contracting, it sounded to me like there might be some industrial interest in this. But also I wasn't clear whether or not there's any governmental interest in this. There was some comments on the part of the Governor in Ohio about sort of second thoughts, perhaps, on a deregulation and whether it was the best move.

I was wondered if you could just sort of elaborate a little bit if there is a thought like, hey, you mentioned fuel diversity and what have you. But perhaps the thought that something new should change from a state policy perspective to sort of ensure that there's fuel diversity and all of the things that nuclear and coal provide?

Yes. And certainly the Governor Kasich can speak for himself. But there certainly is recognition by -- and it's apparent by the Governor and, as well, others, including industrials -- that we really have to think about how to address this lack of market consistency, particularly as it relates to the PJM capacity market.

But we do have legislation in place. We do have competition that's there. Our generation is separated. So you really have to think about that in the context of how you make these adjustments.

And keep in mind, we in December, AEP filed its ESP case with a PPA arrangement from a portion of our units that was in a partnership, our OVEC units, that allowed for recovery through a purchased power arrangement. And you could see some expansion of that PPA to accommodate other generation resources within the state. And that would be a way to address at least some portion of the overall requirements of Ohio customers that could be served with a long-term formula based-rate contract that could supply some of those needs.

And that's something that could done. And I think as people become more aware of where we stand relative to retirements of coal-fired generation, where we stand in terms of, if we do have an economic recovery that's occurring at the same time, Ohio has to really think about not only the investment potential for new generation, but also the maintenance of existing generation. And that's what the key component of these discussions would entail.

Do you think there would be any need for a change in regulatory or legislation, or would that entail any of that, or is this something that could be done under the current construct as you see it?

No. We see it as something that could be done under the current construct as evidenced by our PPA arrangement that we filed in our ESP filing late last year. We believe that could be done. And customers could continue to choose, although in all likelihood, the long-term PPAs would be a non-by-passable charge or something like that that would benefit Ohio in total. But at the same time, allow customers to continue to shop and choose suppliers.

Okay. Thanks a lot. I really appreciate it.

Yes.

Next question is from the line of Jonathan Arnold, Deutsche Bank. Please go ahead.

Hi, Jonathan.

Good morning.

Good morning.

Quick question on the -- I think in the annual guidance you had laid out, I think, $175 million for rate relief as the target. Can I just confirm, it's the $65 million that you had in the first quarter, is that on an apples-apples basis, is $65 million of the $175 million in the bag? Is that the right way to think about it?

I think it's more than that.

It's on an annualized basis, the $175 million. So it's for the full year of 2014. So we're -- of the $175 million that we had previously identified, we're right on track to get all of that.

So I know you're on track to get -- exceed it then?

No.

That's still the number?

Yes. We're right on it.

Okay. Thanks, Brian. And one other thing.

I was just curious as you look at the portfolio and how it performed in the first quarter, you, obviously, had some of the sales commitments, and then access to sell spot. If you had kind of imagined a world where you hadn't had the plants that you're going to be shutting, would you still have been net long and would you have been kind of more in places short, and how is the portfolio kind of evolving to address that?

Well, it's two things. One is there clearly would have been less volume, right. There was a 52% capacity factor on the 1,800 megawatts. But it's what the whole country is facing.

There would be less volume and likely higher prices. So we don't know what the net effect of that would be. Would we have had more hours at $1,800 a megawatt hour?

And keep in mind, too, that from a generation perspective, we no longer have the obligation to serve in Ohio. So it really is about an optimization business as opposed to ever increasing demands and having to serve them. So that really drives a whole different business model relative to that. And then from the overall market context, as Brian said, certainly there's implications in shortage of capacity. And I think people are realizing that.

To answer your question directly, Jonathan, is we would still be net long.

Yes, I'm thinking 1,800 megawatts to 52% capacity factor probably wouldn't have been the whole of that 31%.

That's correct.

Okay. All right. Thank you very much.

Yes.

The next question is from the line of Paul Ridzon, KeyBanc. Please go ahead.

Good morning. Can you hear me?

Yes, Paul, we can hear you.

Just want to clarify that the $200 million transmission is not an acceleration, it's actually incremental that you found because you had this capital head room?

That's right. It's incremental.

And I didn't see any discussion of Ohio shopping. Is that a big impact or have we kind of lapped out at this point?

We're in the upper 60% right now in terms of switching and we anticipated that by the end of the year we would be at about 71% switched.

Okay. And then any comments about your expectations about the upcoming auction?

Are we talking about the PJM capacity auction?

Yes, yes. Sorry. PJM.

Yes. Our expectation is that the capacity prices will go up, probably in that $80 to $100 per-megawatt-day range. But who knows, because the way this capacity construct works, weird things happen all the time. And as long as we get some of these adjustments from a FERC perspective, that certainly will be helpful.

But, again, it's one of those things that, and it goes back to the earlier discussion of how we view this business. If you can't really read that market construct in PJM, it's very difficult to really map out what the revenues are going to be from a capacity standpoint. So hopefully you'll be -- certainly, it's something that's more adequate, certainly, for the continued operation of base load generation like coal and nuclear.

Okay. Thank you.

Yes.

The next question is from the line of Steven Fleishman with Wolfe Research. Please go ahead.

Hi, good morning.

Good morning.

Hi. First a clarification. The 25-day coal piles you have now, what would that be versus like a normal or a year ago?

Oh, it's -- last year I think we were still at the 30-, 35-day range.

Yes.

I think it was 35. We moved from 45 to 35. But it's not unusual. We've had -- we've had inventory levels in the past as low as 10 days. So it's not anything that we have to do any corrective action around.

Okay. Second question is on -- I think you mentioned that the PJM uplift charges was a bit of a drag in the quarter. Were you able to pass those through at all, or do you have to kind of absorb those?

So the ones that identified -- that made up most of that $0.05 per share difference for the vertically integrated were in the jurisdictions where we couldn't pass them through. In some of our jurisdictions we are allowed to pass them through on trackers.

You couldn't pass them through in trackers. You have the opportunity to recover them.

In future periods.

In future periods.

Okay. And did you defer then the cost of those for whoever you could do that?

We were not able to defer those.

Okay. And are you going to see equal recovery like FirstEnergy is on some of these, on your retail contracts? Can you do that?

Yes. So those are -- these are different items that we're talking about. One was for the vertically integrated utilities. And then there's the issue of passing through to customers on our competitive retail side.

We've made a corporate decision that we're not going to pass those through associated with the first quarter of this year. We had a misstep and some customers started to see those charges pass through. We've gone back and since corrected that. And for this quarter, we are not passing those incremental charges through to our competitive retail customers.

Okay. One last question. We're going to get the EPA greenhouse gas rule soon for existing. I'm just, Nick, curious what you're expecting there and how you're thinking about potential implications?

Yes. If you hear what's being said, certainly Gina McCarthy has been public about, certainly they don't have any -- at least they're not focused on anything relative to reducing the reliability of the grid.

I think that's clearly within question now. And she has reinforced the point that they're not trying to take coal away. They are concerned about the reliability of the grid and won't do anything to impair that. So there's somewhat of an expectation that they may go outside the fence and focus on energy efficiency and those types of things with the states and give the states -- which they said they would give the states a lot of opportunity to be able to come up with their mechanisms to adjust to the new targets.

So it's going to be -- in my opinion, it's going to wind up being a state process that we go through, and one that at least is supposed to provide a significant amount of flexibility in how we respond. And certainly with HAPs MACT went a lot further than anyone anticipated in terms of retirements of generation.

In fact, AEP is already 21% lower than 2005 levels and the president's targets were 17% by 2020. So the industry has already come a long way and in particular AEP has. So I think as long as they give that geographic and state flexibility, we should have an opportunity to respond in a very credible fashion.

Thank you.

Operator, we have time for one more question.

Okay. And that question is from the line of Michael Lapides, Goldman Sachs. Please go ahead.

Hey, guys, congrats on a great quarter, and thank you for taking my call.

Thanks, Michael.

I just want to look at slide 4 where you show the earned ROEs by jurisdiction.

Yes.

And I want to compare it to the same slide from the first quarter of 2013's earnings call. Because if I do that, except for Ohio Power in Texas, pretty much everything else is down year-over-year, rolling 12 months. How much of those decreases do you attribute to weather versus other factors?

Yes. I don't see much of it in terms of weather. I think the ones that are down have investments that are occurring. Like there's the transfers that occurred to APCo and to Kentucky that takes awhile to stabilize after you make these because there's certain settlement deals that are done.

And then you come in for rate cases for recovery for Mitchell and Kentucky and so forth. And then, of course, Turk being just built and SWEPCo. And then for transmission they have the investment cycle that is going on there. So I think it's really more a reflection of the timing of the investment cycle.

And, certainly, we worked long and hard on putting writers in place to bring the revenue more concurrent. But on these large capital investments, we continue to work through the rate process. In Indiana, it has been very positive because certainly the I&M team has been very successful in putting legislation in place that essentially allows that recovery more quickly for things like the nuclear lifecycle management.

So I would not read that as we have a continued deterioration of ROEs. I would read it as more of where we're at in the investment cycle.

Got it. Okay. And just, when you think about 2014 and 2015, what efforts, kind of specific, whether it's specific jurisdiction or specific state, do you anticipate trying to get done that makes a structural change to reduced lag?

Hum.

Certainly, Kentucky. Getting the Mitchell assets reflected in Kentucky's base rate is a big component of that. And that's what a lot of the drag on Kentucky's ROE is, it's equity component has increased so much from the transfer of those Mitchell assets over there.

And APCo and West Virginia, and, certainly, that ROE has been low for a long period of time. And it's -- while Virginia has stabilized in a very good place, West Virginia, we still need to work on. That's why we're making the filing this year. So those initiatives are being placed to do that.

And then as far as SWEPCo is concerned, we continue to look for a home relative to the investment, the 88 megawatts of Turk station. And Arkansas should be looking at that at some point, hopefully, because they see the value of those assets. And then overall load growth and some reductions in some of the capacity of the PPA contracts that flow to SWEPCo have ended.

So there's an opportunity for the use of that additional capacity and energy within the SWEPCo portfolio. And there's initiatives in regard to that, as well. So you can bet that any of these that appear low at this point, there's a whole litany of actions being taken in the background to bring those back up to acceptable levels.

Got it. Okay. Thanks. Much appreciated.

Yes.

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

Thank you. This conference call will be available for replay starting today at approximately 11:15 Eastern time and run through May 2 Midnight. You may dial the AT&T Executive Playback Service by dialing 1-800-475-6701 with the access code 322907. International callers may dial area code 320-365-3844, access code 322907.

And that does conclude your conference. We do thank you for joining while using AT&T Executive Teleconference. You may now disconnect. Have a good day.