Julie Sherwood – Director, IR Nick Akins – Chairman, President and CEO Brian Tierney – EVP and COO

Hugh Wynne – Sanford Bernstein Michael Lapides – Goldman Sachs Dan Eggers – Credit Suisse Paul Ridzon – KeyBanc Stephen Byrd – Morgan Stanley Paul Patterson – Glenrock Associates Ali Agha – SunTrust Greg Gordon – ISI Group

(Starts Abruptly). 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 as our regulated utilities. Additionally, our unregulated generation, retail and river operations divisions performed well for the quarter. So, the headlines for the quarter 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 ’13. 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 of 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 drilling 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 companies. We’ll have more to talk about on that issue later on. So, the fundamentals of operational excellence, capital and OEM discipline and 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 in AEP that delivers consistent quality earnings and dividend growth while meeting the challenges of the future. So, let me add a little context to some of the areas that you might find adventurous. 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 procedure schedule for the case but we expected to conclude by April of next year. Also PSO filed a non-unanimous settlement with AARP as the only outlier. It essentially keeps present rates in place with an addition of AMI rider that increases revenues by over $7 million in 2014 increasing to over $27 million in 2016. So we are pleased with the parties to continue 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. So, let’s start moving across the page. Starting out with 8, Ohio Power, their ROI is about 14% now but we expect by year end their ROE should come down to around the 12% range. For APCo, the combined companies certainly masked the disparity between Virginia and West Virginia ROEs. Virginia is in pretty good shape. Its ROE is around 10.8% which is within the earnings band of 10.4% to 11.4%. As you know we’re working on West Virginia with the rate case so that will be filed and certainly we expect to make progress there. From a conductive power standpoint, Kentucky is still as we mentioned in previous quarters, there already is low due to the transfer of the Mitchell Plant. So, while their earnings are up, the equity balance is significantly up. So, it draws the ROE down. We’ll follow rate case at the end of 2014 that would 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 also some sales would inure to the benefit of Kentucky Power if you reached certain threshold. So, that should come up a little bit. I&M, with rate cases completed in early 2013 and strong plant performance adding to offset some sales. I&M is currently earning in ROE slightly higher than authorized at 10.8%. Their authorized ROE is 10.2% so not too far out of line there. And they certainly have made a lot of progress in that regard. It’s noteworthy that they filed for the additional five solar facilities totaling 16 megawatts as well. So really 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 expenses during the quarter. So, that advancement of O&M is $60 million, some of them went to PSO and that’s what’s pulling their ROE down somewhat, so 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 third plant taken care of. There is work in progress to try to address that situation. In the meantime, there will be several initiatives they’re underway and including a Texas filing to recover transmission cost and then LEAN programs to lower cost and 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’ll probably see a pretty sizeable 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 ’13 adjustment so, very good progress in the transmission area. So 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 this part of our cultural transformation redefining how we do business in the future. So, Brian will be reviewing the details around the LEAN activities in moment. But I did want to point out some of the examples of what we were seeing from areas such as generation and distribution. At Cardinal Plant, they bought a truck to load all the welding materials in one place what that was mobile so that they wouldn’t have to go back and forth to get inventory for parts. And that significantly saves time in terms of addressing tube leaks and other areas to get generation back more quickly. The South Ben storage yard, de-cluttering an organization of storerooms and toolkits of it, work times can be improved. The engineering group created new documents to enable faster response at times for projects to our customers so that 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. And we’re significantly already have a reduced targeted refueling outage duration and the costs associated with it. So, there is a multitude of process reviews to eliminate redundant activities and those that don’t add value. So, 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. And 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 $6 million investment to be made but it reduces coal costs by $10 million per year, very positive. And then smaller change, but I think no less important is in APCo Charleston area, an employee notice that we were discarding flagging vests. And we started to decide to wash them instead and save $6,000 per year. And I know that sounds small but that’s one employee coming up for the $6,000 per year and with our 20,000 employees, that’s $120 million. So, if those kinds of things that we’ll have to work indigenously within our organization at levels throughout the organization to ensure that we continue to get the benefits of the LEAN activities and the efficiency changes that we’re making. So I’m very proud of what our employees at the front line are accomplishing in their LEAN activities. Lastly, I want to AEP’s thoughts on the EPA Clean Power Plant. 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 towards reductions in all emission categories, including carbon dioxide and while further progress is certainly being made, rational timing and targets are absolutely critical in achieving the substantial reductions in CO2 emissions contemplated by the EPA plant. As Administrator McCarthy has mentioned on several occasions and I want to reiterate here, is that this far reaching plant is a proposed rule and is yet to be finalized. So, as we look at the proposed rule, the current plan is much too aggressive in many states. And in fact, it’s 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 process is 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 in the pipe drains. The idea of natural gas generation to run at 70% capacity factor, we needed the plant’s 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 will – which won’t happen because we have a forced dispatch of weather 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 it only 0.5% to 0.6% can be achieved annually, certainly goes beyond aspirational thinking. As the CEO, I’m all about aspirational visions but this must be grounded reality. These are state plans, not AEP plans or other market participant plans, so we must be able to have time to work with the multitude of different stakeholders including the state, 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 fire 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 maintenances outages during that part of the year. But it’s incredible that 80% recalled 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 development of purchase power arrangements. This PPA initiative not only supports Ohio generation but provides a value 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 developments 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 “$200 million acquisition” in the first quarter, $100 acquisition this quarter at a good return with virtually no delay, no premium and accretive to shareholders. That’s our standard for investment. So, 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 their 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 results 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, was $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 the second of $0.03 per share. Normalized retail margins contributed $0.01 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 cost, an increase in transmission service expense and higher employee related cost, partially offset by lower storm expense this year. The higher depreciation expense resulted from increased investment and plant, reducing earnings by $0.02 per share. The transmission and distribution utility 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 switched 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 plan grew by nearly $1 billion, 92% increase. The generation and marketing segments 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 $0.01 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 to the interest income benefit recorded last year from the resolution of the U.K. 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 a 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 made 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 that time, ceased operations in the fourth quarter of 2013. The convention for adjusting for Ormet has 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 affects of Ormet. Before we dig into the quarterly numbers, let me make some comments on year-to-date normalized loads. Every one of our operating companies experienced total normalized load increases year-to-date. The increases range from six tenths of a percent and 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 is up 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 up 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 four tenths of a percent for the quarter and have experienced positive growth for the last four quarters. We now believe that we’re 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 U.S. at 2.5%. On the upper right of the slide, you can see that economic growth in our Western footprint continues to outpace the U.S. and our Eastern service area which trails U.S. growth by 0.5%. In the bottom left quadrant, you will see the positive job growth in AEP service area, trials that of the U.S. as a whole by four tenths of a percent. Similar to GDP growth, job growth and AEP’s Western territories, outpaces both the U.S. and AEP’s Eastern service areas. For AEP, we have experienced strong employment gains in the natural resources and 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 U.S. shale gas developments is to AEP’s industrial growth. In the first quarter of 2014, we thought that it was notable that industrial sales and 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 on industrial sales decreased of 1.6%. This shale county, surge in industrial sales are significant for AEP because 17% of our industrial sales are located in shale gas counties. The bottom chart segments, industrial sales growth by major shale regions. As you can see in our Eastern footprint industrial sales are growing fastest in the Utica, Marcellus regions and our Western footprint we are fastest in the Permian and Woodford regions, while sales are down 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 share 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 remains solidly in the BBB and BAA1 range at five 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 de-risking 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 during 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 are supported by a two revolving credit facilities that extended 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 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 cost 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 $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 their initiatives with six starting in July and scheduled to be completed this year. The first of five regions in transmission field operations started LEAN in this month. In addition, numerous corporate groups such as IT, supply-chain, procurement and fleet and commercial operations are applying LEAN principles 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 would get the benefit of those activities sooner than initially planned and that means that the company can produce – can prudently manage with some of the benefits of the strong 2014 earnings have allowed. Most of these costs are being shifted in the second half of 2014, and include activities related to plant 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). And our first question will come from the line of Hugh Wynne, Sanford Bernstein. Please go ahead. Hugh Wynne – Sanford Bernstein: Good morning.

How are you? Hugh Wynne – Sanford Bernstein: Very well. Congratulations on a strong quarter.

Thanks. Hugh Wynne – Sanford Bernstein: 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?

Yes, so, that’s a great question. And I don’t know if 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. So, we’re going through the process with them of understanding the generation is out there, the commitments made around the generation. What that means to the overall plan for the state in response. And some of our states obviously have taken a very aggressive 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. And when you change dispatch order of units within states, when you change resources within states and give guidelines that are fully significant, that really minimizes the other options available, it really makes it challenging for the states. And 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 then would be interesting in itself. And as one participant in part of that overall plan, it’s hard to imagine how these things are all going to come together in that timeframe. And 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. So, this thing has a wrong way to play out. I think certainly the comments that the EPA are critical and certainly the EPA needs to be cognizant that these states are dealing with very, very detailed, very complicated issues and also the companies involved. So, Hugh, that’s a long answer – long way of saying we don’t know at this point. Hugh Wynne – Sanford Bernstein: I appreciate your time on that. Thank you very much. Have a good day.

Yes.

Your next question is from the line of Michael Lapides from Goldman Sachs, please go ahead. Michael Lapides – Goldman Sachs: Hi guys, 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. Michael Lapides – Goldman Sachs: One question on the transmission side, you did those 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&I, 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, and there are RTO mandated projects, there are other projects, reliability projects, customer connect projects. And about – is our call about 75% of the mix was in the Transco’s and 25% was in the regulated operated companies. So, this is all block and tackle, mandate and spending and we have a list of projects and it’s not block. We’re just allocating another $100 million that the transmission say go find something. We have a list of what exactly those projects are by individual project. And I know Brian’s like 20 to 25 separate projects on the page that certainly show the detail. Michael Lapides – Goldman Sachs: Yes. Does this mean that you’re moving stuff that you had planned on doing in ’15, ’16 and ’17 into 2014? So maybe ’14 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 three to five year budget?

Yes. So, 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 meant that all those, there is no additional identified projects along the way. There is 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. And then, 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 incremental projects as well. Michael Lapides – Goldman Sachs: Okay, and last item. 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. In which parts of the business is that actually impacting, meaning VIU, T&I, elsewhere?

It’s going to impact all of them Michael. It’s about $60 million and it’s going to impact the vertical integrated utilities and APGR in terms of planned outages. And it’s going to impact all of them in terms of – it’s going to impact vertically integrated utilities and transmission distribution utilities in terms of some transmission forestry spend that we’re going to do. And then there are other customer related projects that will be in all other segments that we deal with where we’ll be trying to pull those costs forward. Michael Lapides – Goldman Sachs: So its 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 ’16 cost out because we have that challenge associated with the capacity revenue fall-off in 2016. So, we’re trying to take cost out of ’16 and pull them into ’14 and then not have those costs be recurring again in 2016. So, 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 have better resulting spend happening in 2016 to help us fill that gap. Michael Lapides – Goldman Sachs: Got it. Thank you. Much appreciated and congratulations on a good quarter.

Sure, thanks.

Your next question is from Dan Eggers from Credit Suisse. Please go ahead. Dan Eggers – Credit Suisse: Hi, good morning.

Hi Dan, good morning. Dan Eggers – Credit Suisse: Listen, I guess, just, Nick, going back to your comment on the Ohio generation, you said you’ll 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? And then 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?

Well, the way we look at it, the way we originally told you I guess last year or a year before. We’re looking for certain things. And certainly the hedging of that generation is critical. Certainly from maybe 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. And certainly the market areas that we’ve been working on with PJM and others to enhance capacity and then with the energy markets themselves and improving on average. Those are all things that help us determine what the future of that business look 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. Dan Eggers – Credit Suisse: So, that sounds like 2014 will be consumed with, or part of 2014 will be consumed with making a decision. But there’s not actually anything getting done this year?

Yes, the 2014 obviously is a year where certain milestones have to come into place. I mean, 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% that capacity running, it’s going to retire mid-’15. So, the very real impacts of the retirements 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. And also, from a call standpoint, Chuck Zebula is doing everything he can do down to get the cost structure itself down. And 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. Dan Eggers – Credit Suisse: Okay. Thank you for that. And I guess, just one other question on kind of 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 kind of beyond 2014 and are you as encouraged today as you might of been, say, at the end of the first quarter?

I’d say, we’re just as encouraged because you look at residential for example, quarter by quarter I mean, it was pretty high change in first quarter and then it shows a slight decrease in second quarter. A lot of times, residential sort of gets skewed from quarter to quarter based on whether it be holidays, whether it be areas where we’re having to residential parties maybe dealing with their loads in different fashions and 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. So this year, it sort of shows it goes down during this time last year. So, if things like that that will make the residential sort of come in and out each quarter. I tend to look more at the averages of residential load. You don’t see that so much with commercial and industrial loads. And with commercial, showing a consistently positive and then in particular the industrial continues to expand, expands more every quarter. That’s a good thing because we’ve always said industrial leads commercial, commercial leads residential. So I think it’s a good indicator for the future. Dan Eggers – Credit Suisse: Okay. Thank you, guys.

Thank you. And our next question is from the line of Paul Ridzon with KeyBanc. Please go ahead. Paul Ridzon – KeyBanc: Just kind of 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 its part of the decision process. But 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, all right, we’re asking terms of the volatility of the market. So, it’s important for us to get some measure of that in place. It’s just like you buy fuel or anything else or stock, 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 is 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 is an opportunity there. And I think there is legitimate concern on the part of many including the industrials. And they should be concerned. And that’s something I think that we’re focused on answering that question during this year. Paul Ridzon – KeyBanc: And just switching gears, the cost shift from ‘16 to ‘14, 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 of the activities that we talked about doing, the LEAN initiatives, the cost shifting and the incremental transmission spend are meant to have us inside that range. Paul Ridzon – KeyBanc: Okay. Thank you.

There are a number of other factors that will impact where we land in that range. And they are the normal factors that you normally think about. Load growth, our ability to contain cost and wholesale energy pricing. And also keep in mind that what we’ve done so far is what we’ve been able to identify in 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. I mean, we obviously wouldn’t have put our guidance for ‘16 if we didn’t feel comfortable within that range. Where we’re at within the range is, it will be a measure of how much work we can get done from this year, end of ‘15, end of ‘16. And then obviously in November, we’re going to give a view of what we see happening with additional guidance that we provide then. Paul Ridzon – KeyBanc: Thank you very much.

Yes.

Thank you. Our next question is from the line of Stephen Bryd from Morgan Stanley. Please go ahead.

Good morning, Stephen. Stephen Byrd – Morgan Stanley: 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 20, 25 – about 25 substations in that territory, which means we’re connecting a lot of load. And we’re doing 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 the areas and it’s probably at expectations than others.

Stephen, one of the things that we saw last year was lot of the shale gas load that we expected 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 it 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. And as we look to the end of the decade, we just had to increase our load forecasts for those regions by 20% given some updates that we’ve had on some of the developments in those areas. Stephen Byrd – Morgan Stanley: 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 and Zone M2, has frequently been trading at a significant discount to Henry Hub with our Lawrenceburg plant, which is on Texas gas translation zone 4 is frequently trading at $0.25 premium to Henry Hub. So, even in our own service territory, areas that are not that far apart, 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 its 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 at our service area.

Little caution on that, when you look at the volatility of processing, it’s a matter of perspective how much of the processes are coming off. It’s still hard in 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. And even it depends on even more with the Clean Power Plant, it’s – it will be amazing to see what the affect could be because I think the price is moving around in a relatively thin volume level. So you see storage creeping up a little bit, well, it wouldn’t take a hot summer, we’d lose storage if there is a hot September. But when you retire generation, particularly that’s running as much as that generation is running, it’s going to move the natural gas and I would probably expect energy processes move up as a result. Stephen Byrd – Morgan Stanley: Great. Thanks much for the color. I appreciate it.

Yes.

Thank you. Our next question is from the line of Paul Patterson from Glenrock Associates. Please go ahead. Paul Patterson – Glenrock Associates: Good morning.

Good morning.

Good morning. Paul Patterson – Glenrock Associates: Not to specifically ask about M&A, but there is, in Texas, a utility that looks like it’s for sale, potentially, and you guys 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 sort of wondering about the potential deployment of leverage and whether or not you see opportunities such as Encore or what have you?

Yes. So, I guess 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. And 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, and that’s a hard thing to do these days. Paul Patterson – Glenrock Associates: Okay. And then I just wanted to turn back to sort of 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? Just 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 is legitimate concern. What happens, I think probably the – 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 plan into the commission. And it will be a matter of the public policy in Ohio what the result winds up being. But that would be a clear indicator and you probably would see more of that as we go forward. Because there is a huge amount of generation out there that is at risk. And 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, it depends 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 you’re concerned about it, from an economic development perspective in Ohio. There is concern about from that perspective. And we’ll continue to save the tree on that. And I think that’s important for us to progress. So I’d see that playing out this year. Paul Patterson – Glenrock Associates: Okay. Any sense of any sort of timing, I mean, 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?

Well, 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. Paul Patterson – Glenrock Associates: Okay. Thanks a lot. I appreciate it.

Yes.

Our next question is from Ali Agha from SunTrust. Please go ahead. Ali Agha – SunTrust: Thank you. Good morning.

Good morning. Ali Agha – SunTrust: I wanted to clarify a couple of points. First, on the transmission side, so, on the slide that you all lay out for us, the base case and the high case. So, 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, so you should, you should it’s inclusive in that. And you should see that rolling through when the projects are completed.

With a very short lag that we have on translation spend if we make incremental this year, you’ll start to see that in earnings next year. Ali Agha – SunTrust: I see. Okay. Secondly, on your Ohio thinking, Nick, as you laid out various milestones, etcetera. Is it still a scenario for you to look at that portfolio and think of either a tax-free spin-off, 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, as “you’d really like as possible”?

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 the make decisions about what the optionality is concerning that set of businesses. And I think I mean, we’re looking at that in terms of maximizing shareholder value and you have to look at all the options when you do that. Ali Agha – SunTrust: 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?

Well, I certainly would be hesitant to talk about the timing of that. I doubt that we’ll be saying anything about the disposition of our decisions on those particular assets at that point in time. November would 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 – in terms of the end regulated generation, we’ll have to see how the processes are moved through in Ohio and other areas. Ali Agha – SunTrust: 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, so when in our budget for this year, we were assuming negative 1.1% including format and excluding format positive one tenths of a percent. 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 once we get into the year. We had been forecasting negative five tenths of a percent to positive five tenths of a percent in our guidance. And we will be revisiting that as we work our way towards putting together more formalized guidance at EEI. Ali Agha – SunTrust: Thanks Brian, thank you.

Thank you. We probably have question time for one more question operator.

Thank you. Our next question will come from Greg Gordon from ISI Group. Please go ahead. Greg Gordon – ISI Group: Thanks guys. I’ll make it quick since you’ve answered a lot of, just stopped by. I wanted to ask the – 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 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. Greg Gordon – ISI Group: And my question is, did you take advantage of higher prices out the forward curve that kind of – that have since fallen off precipitously to change the mix of what you might be putting into the spot market next year?

Greg, we’ve taken some advantage of that. But a significant portfolio of that portfolio is going to be open to spot markets going forward, probably in that 30% to 40% range. Greg Gordon – ISI Group: Okay, thanks guys. Take care.

Yes, okay.

Thank you. And please go ahead with any closing remarks.

That’s all. You can give the replay information please.

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