美國電力 (AEP) 2014 Q2 法說會逐字稿

Welcome to the American Electric Power Second-Quarter 2014 Conference Call. (Operator Instructions) As a reminder, your conference is being recorded. I would now like to turn the conference over to your host, Ms. Julie Sherwood. Please go ahead.

Thank you, Lois. Good morning, everyone, and welcome to the second quarter 2014 earnings webcast of American Electric Power.

Our earnings release, presentation slides, and related financial information are available on our website, AEP.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements.

Please refer to our SEC filings for a discussion of these factors. Joining me 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.

Okay. Thanks, Julie. Good morning, everyone, and thank you for joining us today at our second-quarter 2014 earnings call. I am once again pleased to report a very positive quarter for AEP, driven by strong regulated Company results, with a continued emphasis on the transmission business, as well our regulated utilities. Additionally, our unregulated generation, retail and river operations divisions, performed well for the quarter. The headlines for the quarter are very positive.

AEP delivered GAAP and operating earnings of $0.80 per share compared with $0.69 per share GAAP and $0.73 per share operating earnings for the second quarter 2013. Year-to-date 2014 GAAP and operating earnings have now resulted in $1.95 per share compared with $1.44 GAAP and $1.53 operating for the same period in 2013. We are reaffirming our earlier adjusted guidance range for the year of $3.35 to $3.55 per share and remain committed to our 4% to 6% growth trajectory, based on our original 2013 guidance range.

AEP is allocating another $100 million of incremental capital in 2014 to our transmission business. As you may recall, we previously allocated $200 million of incremental capital to transmission in the first quarter, so we are executing on our plan of advancing the transmission business model. Additionally, ETT has been rated BAA1 by Moody's and is now paying a dividend to its owners, so good news from the Western front.

Growth in our service territory continues for the quarter, with weather-normalized load increasing 2.3% overall for the year so far, excluding the effects of Ormet, the industrial load that went bankrupt last year. In fact, once again excluding Ormet, during the second quarter the industrial load was up a healthy 4.5% and 3.4% year-to-date, driven by the shale gas, petrochemicals, and all industrial sectors, with the exception of mining.

Commercial and residential loads continue to be up for the year, as well. Brian will cover the load growth in more detail later, but we're pleased with the energy transition that is occurring in our territory and what that means for load growth for the future.

Cost containment activities resulting from culture and LEAN processes continue on target and we remain committed to reinforcing these activities throughout our company. We'll have more to talk about on that issue later on.

The fundamentals of operational excellence, capital and OEM discipline, an open and collaborative culture that defines our ability to meet challenges, and finally, the focus on execution of our business plan in support of infrastructure, development, and the customer experience is intact at AEP and once again, exemplified by second quarter performance. But we still have much work to do as we redefine an AEP that delivers consistent quality earnings and dividend growth, while meeting the challenge of the future.

Let me add a little context to some of the areas that you might find of interest. On the regulatory front, APCo, in West Virginia, filed a base rate case on June 30 requesting a rate increase of $226 million, of which $45 million is a vegetation rider. Our earned ROE in the West Virginia jurisdiction of APCo was 5.8%, as filed with our current approved range of 10% to 10.9%, so an increase here is definitely warranted. We don't have a finalized procedural schedule for the case, but we expect it to conclude by April of next year.

Also, PSO filed a non-unanimous settlement with only AARP as the only outlier. It essentially keeps present rates in place with the addition of an AMI rider that increases revenues by over $7 million in 2014, increasing to over $27 million in 2016. We were pleased that the parties continued to recognize the value of infrastructure development to improve the customer experience.

Before discussing our initial thoughts on the EPA's Clean Power Plan, let me switch you over to the next page of the presentation material to my favorite equalizer chart. Overall, from last quarter the regulated operations ROE has moved up to 10.1% from 9.9% last quarter. Let's start moving across the page. Starting out with Ohio Power, their ROE is about 14% now, but we expect by year-end their ROE should come down to around the 12% range.

For APCo, the combined company certainly masked the disparity between Virginia and West Virginia ROEs. Virginia's in pretty good shape; its ROE is around 10.8%, which is with in the earnings band of 10.4% to 11.4%. As you know, we're working on West Virginia with the rate case, so that'll be filed and certainly, we expect to make progress there. From a Kentucky Power standpoint, Kentucky is still, as we've mentioned in previous quarters, their ROE is low due to the transfer of the Mitchell Plant.

So, while their earnings are up, the equity balance is significantly up, so it drives the ROE down. We'll file a rate case at the end of 2014 that'll reflect the full recovery of Mitchell, and expect this case to be effective in July 2015. In the meantime, there could be increases in ROE given there is a mechanism that off-system sales would enure to the benefit of Kentucky power if you reach certain thresholds, so that should come up a little bit.

I&M, with rate cases completed in early 2013 and strong plant performance adding to off-system sales, I&M is currently earning an ROE slightly higher than authorized at 10.8%. Their authorized ROE is 10.2%, so not too far out of line there. They certainly have made a lot of progress in that regard. It's noteworthy that they've filed for the additional five solar facilities, totaling 16 megawatts as well, so really a lot of positive things occurring over in the I&M jurisdictions.

PSO, as I mentioned earlier with the rate case, the reduced ROE is really actually occurring from the O&M that's been moved for generation sources during the quarter. That advancement of O&M of the $60 million, some of that went to PSO and that's what's pulling their ROE down somewhat. We expect that to improve, as well. For SWEPCo, it continues to be a lower ROE, given that we still have yet to get the disposition of the Arkansas portion of the Turk plant taken care of. There is work in progress to try to address that situation.

In the meantime, there will be several initiatives that are underway, including a Texas filing to recover transmission costs and then LEAN programs to lower costs in generation distribution. But as we go forward, we'll be certainly looking after the election in Arkansas to really push forward with the activities around the Arkansas portion of Turk.

AEP Texas has favorable ROEs, primarily because of the impact of securitization, but they're also doing well from a distribution perspective as well. AEP Transco continues to improve, you probably see a pretty sizable jump there from 9.7% last quarter up to 11.4%. As we told you last quarter, their ROE would increase, particularly in line with the true-ups adjustments that occurred that were just now booked as a result of a 2013 adjustment. Very good progress in the transmission area.

That pretty well wraps it up for the equalizer chart and certainly, we're making a lot of progress in that regard. We know what the areas are that we're working on, so you can expect continued improvement in that area.

As I said earlier, our LEAN activities are progressing very well. We're not letting up on the progress here because it's part of our cultural transformation and redefining how we do business in the future. Brian will be reviewing the details around the LEAN activities in a moment, but I did want to point out some of the examples of what we were seeing from areas such as generation distribution.

At Cardinal Plant, they bought a truck to load all of the welding materials in one place that was mobile so that they wouldn't have to go back and forth to get inventory for parts. That significantly saved time in terms of addressing tube leaks and other areas to get generation back more quickly. The South Bend storage yard, decluttering and organization of storerooms and toolkits so that work times can be improved.

The engineering group created new documents to enable faster response times for projects to our customers so that will certainly improve the customer experience. Cook Nuclear is going through LEAN activities and one of the first in the country to go through that type of activity. We're significantly -- already have a reduced targeted refueling outage duration and the costs associated with it.

There's a multitude of process reviews to eliminate redundant activities and those that don't add value. Obviously, we're very careful with that, with the nuclear side, but certainly it's something that we should do so that we can work smarter at the Cook Nuclear Station.

Just to give you an idea of the range of the things that our employees are coming up with, at Amos Plant, they reviewed the plant's barge unloading system that led to a $6 million investment to be made, but reduces coal costs by $10 million per year; very, very positive. A smaller change, but I think no less important, is in APCo Charleston area, an employee noticed that we were discarding flagging vests and we started decided to wash them instead and save $6,000 per year. I know that sounds small, but that's one employee coming up with a $6,000 per year idea and with our 20,000 employees, that's $120 million.

It's those kinds of things that'll have to work indigenously within our organization, at levels throughout the organization, to ensure we continue to get the benefits of the LEAN activities and the efficiency changes that we're making. I'm very proud of what our employees at the front line are accomplishing in their LEAN activities.

Lastly, I want to give AEP's thoughts on the EPA Clean Power Plan. From the outset, I want to reiterate AEP's commitment towards achieving a balanced portfolio of resources that provides clean, affordable, and reliable power for our customers.

While much progress has already been made toward reductions in all emission categories, including carbon dioxide, and while further progress is certainly be made, rational timing and targets are absolutely critical in achieving the substantial reductions in CO2 emissions contemplated by the EPA plan. As Administrator McCarthy has mentioned on several occasions and I want to reiterate here, is that this far-reaching plan is a proposed rule and has yet to be finalized. As we look at the proposed rule, the current plan is much too aggressive in many states and in fact, is a multi-variable equation that doesn't solve within the timeframe given.

To force a change in resource mix, system dispatch, and market conditions, along with navigating a myriad of state-related review processes covering many issues, while not impacting reliability in such a short timeframe could result basically in a convoluted mess that turns the foundation, assumption, and building blocks of the plan into pipedreams. The idea of natural gas generation to run at 70% capacity factor when neither the plants, natural gas pipeline system, or the electric system is in place to support it is not credible. Or to expect 6% efficiency gains on coal units to occur when only about 1% is viable, even if capacity factors remained high, which won't happen because we have a forced dispatch of other resources ahead of low-cost coal and that's just not credible either.

Moreover, to expect energy efficiency overall to improve 1.5% per year when EPRI itself, the Electric Power Research Institute, has determined that only 0.5% to 0.6% can be achieved annually, certainly goes beyond aspirational thinking. As a CEO, I'm all about aspirational visions, but it must be grounded in reality. These are state plans, not AEP plans or other market participant plans, so we must be able to have time to work with a multitude of different stakeholders, including the states and the EPA to determine a course and be able to execute on the myriad of different processes and approvals to make this transformation occur.

AEP is committed to working with the EPA, just as we did during the Mercury Rule comment period, which is far from over by the way, given 2015 pending retirements of coal-fired generation have yet to occur. AEP was right about the analysis of the Mercury rules and we will continue to be factual and collaborative during the upcoming comment process.

As an aside, speaking of the units retiring in 2015, 80% of them were called upon and ran during the second quarter; a quarter that was essentially no extreme weather conditions and certainly, there were outages being taken, generation has to take maintenance outages during that part of the year, but it's incredible that 80% were called upon just a year in advance of their retirement.

Briefly, in regards to the unregulated generation, if I can talk a little bit about that, we continue to review with the Board the options available to us regarding the future of that business and we continue to reinforce the value of the unregulated generation through market reforms, hedging of our generation through our retail and wholesale businesses and advanced regulatory initiatives, such as the development of purchased power arrangements.

This PPA initiative not only supports Ohio generation, but provides a valuable hedge to customers against volatile market conditions. Any decisions with regard to the unregulated generation business will be made on a timely basis to maximize shareholder value. Speaking of shareholder value, every capital decision we make is based upon our ability to move capital to infrastructure development, particularly transmission and the regulated operations.

For those of you thinking about M&A, the way we look at it, because we have about $2 billion of incremental transmission projects over the next four years looking for capital, we made a $200 million, quote-unquote, acquisition in the first quarter, a $100 million acquisition in this quarter at a good return with virtually no delay, no premium and accretive to the shareholders. That's our standard for investment.

In a nutshell, we have had another great quarter centered on the fundamentals we laid out for our investors over two years ago. You can expect us to stick with our plans to be a regulated utility, to drive effective capital and OEM discipline, and continually adjust to the challenges ahead.

Thanks, and I'll now turn it over to Brian. Brian?

Thank you, Nick, and good morning, everyone.

On slide 5, you will see our comparison of 2014 result to 2013 by segment for both the quarter and the year-to-date periods. I plan on focusing your attention this morning mostly on the second quarter results. For those of you who are interested in the year-to-date comparison, you'll find that in the appendix. I will say that the drivers we discussed at length during the first quarter earnings call remain the drivers for the year-to-date results.

For the Company overall, operating earnings for the second quarter were $390 million or $0.80 per share compared to $0.73 per share or $357 million recorded last year. These results, when combined with the first quarter, pushed first half 2014 earnings to $950 million, or $1.95 per share compared to $1.53 per share, or $744 million earned in the first half 2013. Looking at the slide, you can see that each business segment is either equal to or above results recorded in 2013.

With that as an overview, let me step you through the major earnings drivers by segment for the quarter on slide 6. Second quarter earnings for the Vertically Integrated Utility segment were $0.31 per share this year, comparable to the results of last year. Rate changes across many of our jurisdictions added $0.06 per share for the quarter. The increase in rates is a result of incremental investment made to serve our customers.

Higher wholesale power prices and the availability of our generating fleet bolstered off-system sales, which benefited both customers and shareholders, resulting in improved earnings in this segment of $0.03 per share. Normalized retail margins contributed a penny per share to the year-over-year growth. Weather for the quarter was comparable to last year. The quarterly increase in margins was offset by higher O&M expense, depreciation, and other items.

The increase in O&M adversely affected the quarterly comparison by $0.07 due to higher generation maintenance costs, an increase in transmission service expense, and higher employee-related costs, partially offset by lower storm expense this year. The higher depreciation expense resulted from increased investment in plants, reducing earnings by $0.02 per share. The Transmission and Distribution Utilities segment earned $0.18 per share for the quarter, $0.03 higher than last year.

Rate changes added $0.01 per share for the quarter and transmission revenues were higher, due to customers who have switch suppliers in Ohio, as well as the effect of increased investment. These favorable items were partially offset by higher O&M expense due to higher transmission, distribution, and employee-related costs. The Transmission holdco segment continues to grow, contributing $0.10 per share, a $0.06 improvement reflecting our continued significant investment in this area.

From June of last year to June of this year, this segment's plant grew by nearly $1 billion, a 92% increase. The Generation and Marketing segment's earnings of $0.20 per share adds $0.02 to our quarterly comparison. This segment benefited from higher wholesale power prices and lower interest expense, resulting from a very low weighted average cost of debt for generation resources. AEP River Operations contributed a penny per share to earnings, $0.03 higher than our 2013 results, due to improvements in demand for barge freight.

Finally, corporate and other results were off $0.07 per share, primarily due from the interest income benefit recorded last year from the resolution of the UK windfall tax item. In summary, our earnings performance during the quarter remained strong, largely due to a combined favorable $0.09 per share from our regulated segments. In addition, the competitive segments also contributed to the year-over-year growth in earnings.

These results, along with the strong performance in the first quarter, allowed us to advance spending into 2014 from future years, as we announced in April. This leaves us well-positioned within the guidance range of $3.35 to $3.55 per share.

Let's take a look at slide 7, where we can review normalized load trends for the quarter. As I make comments about industrial and total load on this slide, my remarks will adjust for the impact of the Ormet load. You will remember that Ormet, our largest customer at the time, ceased operations in the fourth quarter of 2013.

The convention for adjusting for Ormet is meant to give a sense of how our industrial and total load are recovering in more of a going forward basis, since Ormet is not expected to return to production. In the charts, the numbers are presented with and without the effects of Ormet. Before we dig in to the quarterly numbers, let me make some comments on year-to-date normalized load.

Every one of our operating companies experienced total normalized load increases your-to-date. The increases range from 0.6% at Appalachian and Wheeling Power to an impressive 4.6% at AEP Texas. In addition, four of our seven operating companies experienced growth in all three retail classes.

Turning to the quarterly comparisons on the bottom right of the slide, you can see that overall weather normalized load was up 1.3%. This is being driven by industrial load, which was up a remarkable 4.5%.

This marks the third consecutive quarter with positive growth in industrial sales. The Company experienced growth in seven of our top 10 industrial sectors for the quarter and nine of the top 10 for the year. The lone exception is coal mining, which was down 3.5%. The quarterly sector leaders are pipeline transportation up 30.4%, chemical manufacturing, our second largest sector, up 11.1%, and oil and gas extraction of 10.5%. We will talk more about the impacts of shale gas developments later.

On the upper right of the slide, you will see that commercial sales were up 0.4% for the quarter and have experienced positive growth for the last four quarters. We now believe that we are on track to match a positive annual comparison for the year for the first time since 2008. Four of our top five commercial sectors have experienced year-to-date sales increases; the only exception being the retail trade sector, which was down nearly 1%.

On the upper left of the slide, you will see that residential sales were down 1.5% for the quarter. While residential results varied by quarter, they are up year-to-date and are expected to be positive for the year.

Turning to slide 8, let's review recent economic data for AEP service territory. Looking at estimated GDP for the quarter, growth for AEP at 3% continues to outperform that of the US at 2.5%.

On the upper right of the slide, you can see that economic growth in our Western footprint continues to outpace the US and our Eastern service area, which trails US growth by 0.5%. In the bottom left quadrant, you will see that positive job growth in AEP service area trails that of the US as a whole by 0.4%. Similar to GDP growth, job growth in AEP's Western territories outpaces both the US and AEP's Eastern service areas.

For AEP, we have experienced strong employment gains in the natural resources of mining, leisure and hospitality, construction and manufacturing sectors. With that segue, let's turn to slide 9 to see how big of an impact the US shale gas developments is to AEP's industrial growth.

In the first quarter of 2014, we though it was notable that industrial sales in AEP shale counties grew by 30% versus non-shale counties, which had decreases of 1.7%. For the second quarter, that contrast becomes even more pronounced, as industrial sales in our shale counties increased by a dramatic 39% over last year's second quarter and our non-shale counties saw industrial sales decreases of 1.6%.

This shale county surge in industrial sales is significant for AEP because 17% of our industrial sales are in shale gas counties. The bottom chart segments industrial sales growth by major shale region.

As you can see in our Eastern footprint, industrial sales are growing fastest in the Utica and Marcellus regions. In our Western footprint, we are growing fastest in the Permian and Woodford regions, while sales are down slightly in the Eagle Ford region. Looking forward, we are anticipating significant oil and gas-related load increases in our shale footprint. We have recently updated our shale-related load forecast and the incremental capacity requirements through the end of the decade have increased by over 20%.

In Ohio, the Department of Natural Resources has just announced that, from 2012 to 2013, oil production in the state increased 62% and natural gas production increased 97%. In addition, the ODNR noted that general drilling permits issued in the state were 583 in 2013 and are expected to grow to 700 this year and to 800 in 2015.

Turning to slide 10, let's review the financial health of the Company. Our debt to total capital remains unchanged relative to last quarter at 54.2%. Our credit metrics, FFO interest coverage, and FFO to debt have improved modestly from last quarter and remain solidly in the BBB and BAA1 range at 5 times and 20.3%, respectively.

Our qualified pension is now fully funded at 100%. This is great news for our customers, employees, retirees, and investors and reflects significant investment in and derisking of the plan over the last five years.

This is noteworthy, given that our pension funding stood at 73% at the end of 2008 and was only 82% funded at the end of 2010. The weighted average duration of the assets now more closely matches that of the liabilities at about 10.2 years and at 100% funding, our targeted allocation of fixed income assets rises to 60% from its current allocation of 55%. We plan to make contributions to the plan at roughly the estimated annual service cost of about $75 million.

Finally, our liquidity stands at about $2.9 billion and is supported by our two revolving credit facilities that extend into the summers of 2016 and 2017. We have worked hard over the last several years to achieve the financial strength demonstrated on this slide and believe that we are well-positioned for the future.

Turning to slide 11, let's see if I can't wrap this thing up. The Company is off to a strong first half of 2014. For the quarter, all of our business segments were equal to or greater than last year's results and for the year-to-date, all of our business segments exceeded last year's numbers. On top of those results, we are executing on our commitments. We previously stated that we were going to accelerate transmission investment when possible, expand our LEAN and continuous improvement initiatives, and shift costs out of 2016 and into 2014 where it makes sense.

I'll spend a few moments giving an update on the progress we've made on those commitments. First, starting with the goal of accelerating transmission investment, in addition to the $200 million increase that we announced after the first quarter, our year-to-date results give us the confidence and the cash to advance another $100 million into 2014.

This increased investment will fund NERC-mandated projects, reliability projects related to generation retirements, and new customer connections. This will bring our forecasted 2014 transmission capital spend to a total of $1.9 billion. In regards to the continuous improvement efforts, employees have now completed LEAN initiatives at seven of our generating plants, with plans to complete an additional five during 2014. Our DC Cook Nuclear Plant also started deploying LEAN earlier this year. Seven of our 32 distribution districts have completed LEAN initiatives, with six starting in July and scheduled to be completed this year.

The first of five regions in transmission field operations started LEAN this month. In addition, numerous corporate, groups such as IT, supply chain, procurement and fleet, and commercial operations are applying LEAN principals and practices. In places where employees have engaged in LEAN initiatives, we have identified cost savings through more efficient work practices and better utilization of the contractor workforce.

Finally, in regards to the cost-shifting initiatives, we have accelerated approximately $60 million of expenses from 2016 into 2014. This means that our customers will get the benefit of those activities sooner than initially planned and it means that the Company can prudently manage with some of the benefits of the strong 2014 earnings have allowed. Most of these costs are being shifted into the second half of 2014 and include activities related to planned outages and other customer-focused activity. It is fair to conclude that the Company is making progress on its commitments in these areas.

Finally, we are reaffirming our 2014 operating earnings guidance range of $3.35 to $3.55 per share. We are pleased with our earnings performance for the first half of the year, mindful of a mild start to the summer, and confident in our ability to perform within the range.

With that, I will turn the call over to the operator for your questions.

(Operator Instructions) Hugh Wynne, Sanford Bernstein.

Good morning. Congratulations on a strong quarter.

Thanks.

I wanted to follow up a little bit on your comments on the new proposed regulation on CO2 and I was wondering if I could maybe draw you out a little bit on how you see the rule being implemented in the states where you have generation? I appreciate that you're submitting comments and that the rule will be changed, but are you anticipating any particular form of regulation in the major states where you have coal-fired power plants?

That's a great question and I don't know that I have a good answer at this point. I'm not sure anybody does. We're working extensively and have outreach to all of our states. Trying to understand exactly what this plan means and even our generation, we're just a part of each state that we serve and that's what I stress, these are state plans. We've got to go through the process with them of understanding the generation that's out there, the commitments made around the generation, what that means to the overall plan for the state response.

Some of our states, obviously, have taken a very aggressive view in terms of litigation and it remains to be seen how that whole process will work out. I think this plan is more far-reaching than anything that's ever occurred before. When you change dispatch order of units within states, when you change resources within states and give guidelines that are pretty significant that really minimizes the other options available, it really makes it challenging for the states.

That's something that we're trying to work through the process to fully understand. We'll get back with EPA on the facts that we see from a state-by-state perspective and have discussions about it and specific examples of areas that are of concern and we'll have to work it out. But I really can't tell you what the process is at this point. As you know, the rule provides for 2017 and then 2018 if the states decide to get together, which that'll be interesting in itself.

As one participant in part of that overall plan, it's hard to imagine how this thing's all going to come together in that time frame. Then many of the requirements really hit in 2020, so you really don't have much time, probably not enough time, to get what you need done. This thing has a long way to play out.

I think, certainly, the comments to the EPA are critical and certainly, the EPA needs to be cognizant that these states are dealing with very detailed, very complicated issues and also the companies involved. Hugh, that's a long way of saying we don't know at this point.

I appreciate your time on that. Thank you very much. Have a good day.

Michael Lapides, Goldman Sachs.

Congrats on a good quarter and also want to thank you. I know you implemented at the beginning of the year, but for the new disclosure methodology, it makes understanding AEP a little bit easier to do.

Brian's happy about that comment.

One question on the transmission side, you did this in the first quarter and now, you're doing it again in terms of updating your transmission capital spending guidance for the year. Can you give us a little more insight on where that spending is occurring, meaning either specific jurisdictions, specific Transco, or even whether it's just embedded within the VIU, T&D, or is it actually at the Transco sub? Just trying to tie together your CapEx versus your segments.

Yes. It's occurring all over the place, but primarily in Ohio, Oklahoma, and Indiana. There are RTO-mandated projects, there are other projects, reliability projects, customer connect projects, and as I recall, about 75% of the mix was in the Transcos and 25% was in the regulated operating companies. This is all block and tackle mandated spending and we have a list of projects. It's not like we're just allocating another $100 million to transmission and say go find something. We have a list of what, exactly, those projects are by individual project. I don't know, Brian, it's like 20, 25 separate projects on the page that certainly show the detail.

Does this mean that you're moving stuff that you had planned on doing in 2015, 2016, 2017 into 2014? So maybe 2014 CapEx, you're kind of accelerating the earnings power, but you're not necessarily making, I don't know, for year five earnings power higher? Or is this an increase in capital spending if you think about a three-year to five-year budget?

It is, obviously, first of all, taking care of that green section of the graph that the incremental transmission that we had for the year and then we also advanced some projects from future years into this year. But that doesn't mean that there's no additional identified projects along the way. There's a lot of other activity going on.

The green sections were only defined projects that we knew exactly what they were and where they would be done. Of course, the work continues on continued rehabilitation of the grid from a transmission perspective and additional projects, so while it's advanced from future years, that doesn't mean that there won't be incremental projects as well.

Great. Brian, this may be more of a detailed one, on the O&M change for 2014 you've talked about, can you reiterate what's the amount? You said that it's largely going to be second half of 2014. And which parts of the business is that actually impacting, meaning VIU, T&D, elsewhere?

It's going to impact all of them, Michael. It's about $60 million and it's going to impact Vertically Integrated Utilities and APGR in terms of plant outages and it's going to impact all of them in terms of -- it's going to impact Vertically Integrated Utilities and Transmission and Distribution Utilities in terms of some transmission forestry spend that we're going to do. Then there are other customer-related projects that'll be in all of the segments that we deal with where we'll be trying to pull those costs forward.

So it's costs that you will pull forward into 2014, but therefore wouldn't necessarily have recurring in 2015?

Yes. It's really, we're trying to take those 2016 costs out, because we have that challenge associated with the capacity revenue falloff in 2016. We're trying to take costs out of 2016 and pull them into 2014 and then not have those costs be recurring again in 2016. If it's plant outages, if we can get ahead on transmission tree trimming that we then get the benefits of that for our customers in 2014, but will not have the resulting spend happening in 2016 to help us fill that gap.

Got it. Thank you. Much appreciated and congratulations on a good quarter.

Dan Eggers, Credit Suisse.

Good morning.

Good morning.

Nick, going back to your comment on the Ohio generation, you said you'd address it in a timely fashion and enhance shareholder value. Can you give an update on progress you're seeing as far as long-term contracting of those assets as an alternative to keeping them? With the pullback in power prices and that sort of thing, is that having a bearing on potentially delaying when you guys would want to do something hoping for a better environment, particularly after AES pulled their project?

The way we look at it is the way we originally told you, I guess, last year or year before. We're looking for certain things and certainly, the hedging of that generation is critical, certainly from AEP retail and the wholesale side. We continue to work on the PPA issue in Ohio, focused on trying to bring some sensibility around the risk that customers are taking on in Ohio, certainly, the market areas that we've been working on with PJM and others to enhance capacity, and then with the energy markets themselves improving on average, those are all things that help us determine what the future of that business looks like.

And obviously, we're not just stopping there. We're looking at all the cost structures around that business and really treating it like any other investor would treat it.

So it's really important for us to reach those milestones to fully understand what the valuation of that business looks like in the future and then the one thing we have is time to focus on those activities and make a decision. All along the way, we're keeping our Board up to date on what market conditions look like, what the areas look like in terms of the options available to us, and that's all I'm saying, at that point, is we will decide what to do with that business when we feel like the time is right to make sure we maximize shareholder value.

That sounds like 2014 will be consumed with, or part of 2014 will be consumed with making a decision. But there's not necessarily anything getting done this year?

Yes. 2014, obviously, is a year where certain milestones have to come into place. We have several. We've already gone through a capacity auction that was improved. We still have some changes that are permeating through PJM with the demand curve and so forth. We've got other things we're doing with it, and we believe that in 2015, like I mentioned with 80% of that capacity running, it's going to retire mid-2015.

The very real impacts of the retirement to that generation is going to be reflected through the capacity and energy markets, so that will give us a real view of what that valuation looks like. Also, from a cost standpoint, Chuck Zebula is doing everything he can do to get the cost structure itself down. With the LEAN activities, the plants are running very differently than what they ran in the past. So all those things are coming together and 2014 is a year where we're going through the process, determining what the milestones are, and what the options are available.

Okay. Thank you for that. One other question on the load growth trends: obviously, there's a lot of enthusiasm in the first quarter. And trying to decipher between weather and usage was a question, and we saw residential taper off comparably in the second quarter. How are you feeling about the outlook for demand growth beyond 2014? Are you as encouraged today as you might of been, say, at the end of the first quarter?

I'd say were just as encouraged because if you look at residential, for example, quarter-by-quarter, it was pretty high change in first quarter and then it shows a slight decrease in second quarter. A lot of times residential will sort of get skewed from quarter to quarter based upon, whether it be number of holidays, whether it be areas where we're having to -- residential parties may be dealing with their loads in different fashions in different parts of the year because you could have, like last year, there was that federal furlough that was done that people stayed home, residential went up.

This year it sort of shows it goes down during this time last year. It's things like that will make the residential sort of come in and out each quarter. I tend to look more the averages of residential loads. You don't see that so much with commercial and industrial load. With commercial showing a consistently positive and in particular, the industrial continues to expand, it expands more every quarter. That's a good thing because we've always said, industrial leads commercial, commercial leads residential. I think it's a good indicator for the future.

Okay. Thank you guys.

Paul Ridzon, KeyBanc.

On Dan's question, just on the Ohio generation, is an outcome in Ohio around the PPA a gating issue for your decision?

I think, certainly, it's part of the decision process. I think the real reason why we're doing the PPA arrangement, number one, is bring some stability to the generation in Ohio. The second reason, obviously, is our customers are at risk in terms of the volatility of the market.

It's important for us to get some measure of that in place. It's just like you buy fuel or anything else, or a stock portfolio, you're in for the long term, you're in for the short-term. Long-term capacity and energy needs to be there in Ohio.

For the first time, Ohio is short and Ohio's going to be a purchaser on the market if it's not careful in reinforcing the value of this generation. So yes, it's a big part of the decision process for us, because you make very different decisions about generation unless you have long-term purchase power arrangements, whether they're formula-based rate or within the retail side that we're talking about.

So there's an opportunity there and I think there's a legitimate concern on the part of many, including the industrials, and they should be concerned. That's something I think that we're focused on answering that question during this year.

And just switching gears, the cost shift from 2016 to 2014, should we think about that as allowing you to get to the 4% or 6% or bring you comfortably within that 4% to 6% growth 2015 to 2016?

I think all the activities we talked about doing, the LEAN initiatives, the cost shifting and the incremental transmission spend are meant to have us inside that range.

Okay. Thank you.

There are a number of other factors that'll impact where we land in that range and they're the normal factors that you'd normally think about: load growth, our ability to contain costs, and wholesale energy pricing.

And also keep in mind that what we've done so far is what we've been able to identify and the prospects of what's happened so far from LEAN activities and so forth. So as far as 2016 is concerned, we still have a lot more work to do.

We obviously wouldn't have put out guidance for 2016 if we didn't feel comfortable we were within that range. Where we're at within the range, it will be a measure of how much work we can get done from this year and 2015 into 2016. Then obviously, in November, we're going to give a view of what we see happening with additional guidance that we provide then.

Thank you very much.

Stephen Byrd, Morgan Stanley.

Good morning, Stephen.

Good morning. You gave some good color in the presentation on the growth of shale gas activity. Is the kind of growth that we're seeing, is this in line with your expectations? Is it accelerating above your expectations? Can you give a little more color on the degree of activity that you're seeing?

I think, in some cases, it's above our expectations because, and I know I heard the other day, our President in AEP Texas said that we have, in the last year, put in like 25 substations in that territory, which means we're connecting a lot of load. And we're doing more in terms of transmission, the substation in a box, we call it, but the skid stations so that we can connect these customers more quickly. We're expanding that effort because we definitely want to keep up with the expansion that's occurring. So I'd say it's ahead of expectations in areas and it's probably at expectations in others.

Stephen, one of the things that we saw last year was a lot of the shale gas load that we expect it to come on earlier in the year last year did not come on until later in the year and whether that's logistics problems, permitting problems, or whatever was, it was stacked up and really didn't come in until later last year, earlier this year. As we're looking forward, our shale gas-related forecasts are actually increasing from the base that we had. As we looked to the end of the decade, we just had to increase our load forecast for those regions by 20%, given some updates that we've had on some of the developments in those areas.

Okay. And just wanted to speak about that increase in the supply, we've seen a lot of volatility in local gas prices. Do you have a point of view on the impact, either near-term or long-term, just on all this increase in shale gas and what that might mean for local gas prices versus what we might see quoted on Henry Hub?

Yes. We're seeing some pretty significant basis differentials around our combined cycle gas plants. Waterford, for instance, which takes off with Texas Eastern at Zone M2, has frequently been trading at a significant discount to Henry Hub, whereas our Lawrenceburg plant, which is on Texas gas transmission Zone 4, is frequently trading at a $0.25 premium to Henry Hub. So even in our own service territory, areas that are not that far apart from Indiana to Eastern Ohio, we're seeing some pretty significant basis differentials.

When you're in the production area and you don't have the infrastructure to take the gas out of the production area, we're awash in gas and it's depressing prices. In places where you don't have those constraints and you're pulling from the Gulf, you're trading at a traditional premium to the Henry Hub. So it's impacting local prices pretty significantly in our service area.

A little caution on that, when you look at the volatility of processing, it's a matter of perspective how much the prices are coming off. It's still higher than our coal prices and when you look at the retirements that are about to occur next year, you really wonder what it's going to do to natural gas prices going forward. Even to depend on even more with the Clean Power Plan, it will be amazing to see what the effect could be. Because I think the price is moving around in a relatively thin volume level.

So you see storage creeping up there a little bit. It wouldn't take a hot summer, we'd lose storage if there's a hot September. But when you retire generation, particularly that's running as much as that generation is running, it's going to move natural gas and I would fully expect energy prices to move up as a result.

Great. Thanks much for the color. I appreciate it.

Paul Patterson, Glenrock Associates.

Good morning.

Good morning.

Not to specifically ask about M&A, but there is, in Texas, a utility that looks like it's for sale, potentially, and you are in Texas. But, also, you made some comments in your opening statement about potential M&A and what you were looking for, and I'm just wondering about the potential deployment of leverage and whether or not you see opportunities such as Encore or what have you?

Yes. So first of all, the patent M&A 101 answer, we look at a lot of things. But certainly, when you make a decision like that, it continues to be more of a strategic move. With the amount of transmission spend that we have available to us with, like I said, with no premium and I fully expect the Texas process to be pretty robust, it remains to be seen how that process is actually going to work out and in fact, who all is involved with it.

But our course of action is what we know today and that's focused on the transmission investment that we have indigenous, that we can continue to improve earnings per share for our shareholders, and anything else beyond that would have to be something that achieves a strategic hurdle that overcomes the transmission spend. That's all hard thing to do these days.

Okay. And then I just wanted to turn back to Ohio and this PPA rider. And just sort of generically speaking, what the interaction you guys are having, generally speaking with officials in Ohio and their thoughts about fuel diversity, what the market is providing them, and their appetite or their policy perspective on potentially going for something like the PPA rider or what have you, sort of a hybrid situation, in terms of if they want to have more fuel diversity or what have or if they're willing to sort of just go pure market kind of thing? What kind of -- incrementally, what have you been getting from, as you get further in the process from the officials in Ohio?

I think there's legitimate concern. What happens, I think, probably you already have a test case out there with the ESP filing that we made last December, that has a PPA for the OVEC generation. The staff recommended against it, but they said, well, commission, if you decide to do this, this is how to do it. So basically, they punted to the Commission. It'll be a matter of the public policy in Ohio what the result winds up being.

But that'll be a clear indicator and you probably will see more of that as we go forward because there's a huge amount of generation out there that is at risk. From an Ohio perspective, it needs to be locked in, in some fashion. Now that might not be all of it but certainly, just as you do with any other portfolio, there needs to be a long-term approach and for Ohio to depend upon PJM market conditions to preserve some sense of lack of volatility for customers, that would be a huge error.

So we continue to have discussions and there are obviously others, like industrials, who were concerned about it from an economic development perspective in Ohio. There is concern about it from that perspective and we'll continue to shake the tree on that and I think that's important for us to progress. I'd see that playing out this year.

Okay. Any sense of any sort of timing? You said this year, but I'm just wondering, do you think, is it going to be just basically, should we just check out the ESP process or do you think there might be another way this might manifest itself?

I think certainly the ESP case is a clear indicator, because that may be the first thing that the Commission actually deals with, but there could be other filings that we would make as a result, as well.

Okay. Thanks a lot. I appreciate it.

Ali Agha, SunTrust.

Thank you. Good morning.

Good morning.

I wanted to clarify a couple of points. First, on the transmission side, on the slide that you all lay out for us, the base case and the high case, just to be clear, if I look at the 2016 numbers, you still have about a $0.06 differential earnings-wise between base and high. So does some of the incremental investment that you've made capture that, or when should we see that $0.06 starting to get captured visibly from our side?

Yes. It's inclusive in that and you should see that rolling through when the projects are completed.

With the very short lag that we have on transition spend, as we make incremental this year, you'll start to see that in earnings next year.

I see. Okay. Secondly, on your Ohio thinking, Nick, as you laid out various milestones, et cetera, is it still a scenario for you to look at that portfolio and think of either a tax-free spinoff, or a sale to unlock some equity value? Is that still something you're considering, or is the focus primarily on trying to make it, quote-unquote, as you'd really like as possible.

Yes. I think all those options are still open, because we have to credibly look at this business, do everything we can to fortify the value of it, and then make decisions about what the optionality is concerning that set of businesses. We're looking at that in terms of maximizing shareholder value and you have to look at all the options when you do that.

Okay. If I heard you right, the EEI is probably not the forum where you'd give us your strategic conclusion, but maybe year-end earnings for next year, would that be the time frame we should be looking at?

I certainly would be hesitant to talk about the timing of that. I doubt that will be saying anything about the disposition of our decisions on those particular assets at that point in time. November will really be a time where we focus on the guidance for the forward-looking years, so you'll see a new version of that. But in terms of the unregulated generation, we'll have to see how the processes move through in Ohio and other areas.

Okay. Last question, can you just remind us for budgeting and planning purposes, what is the weather-normalized load growth you assume for this year and normalized longer-term?

Yes, in our budget for this year, we were assuming negative 1.1% including format and excluding format, positive 0.1%. Obviously, as we've come in hotter for the first half of the year weather-normalized, we would be off those numbers today, and we generally don't reforecast what the individual components going into the guidance were once we get into the year. We had been forecasting negative 0.5% to positive 0.5% in our guidance and we will be revisiting that as we work our way towards putting together more formalized guidance at EEI.

Thanks.

Greg Gordon, ISI Group.

Looking at one of your slides, year-to-date you've put 36% of your volumes at the generation resources business into the spot market. Obviously, you've done very well because we had a lot of volatility in the first and second quarter, but prices are off quite a bit. Did you take advantage of higher prices out the forward curve in the second quarter to hedge out at better prices some of your load for next year or do you expect to run substantively open again?

Yes. They're continually hedging in the market and really those hedges have continued to be of benefit to us.

My question is, did you take advantage of higher prices out the forward curve that have since fallen precipitously to change the mix of what you might be putting into the spot market next year?

Greg, we've taken advantage of that, but a significant portion of that portfolio is going to be open to spot markets going forward, probably in that 30% to 40% range.

Okay. Thanks, guys. Take care.

Thanks.

Thank you and please go ahead with any closing remarks.

That's all. You can give the replay information, please.

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