Mike Morris - President, Chairman and CEO Bob Powers - President, AEP Utilities Joe Hamrock - President and COO, AEP Ohio Venita McCellon-Allen - President and COO, Southwestern Electric Power Company Charles Patton - President and COO, Appalachian Power Paul Chodak - President and COO, Indiana Michigan Power Stuart Solomon - President and COO, Public Service Company of Oklahoma Nick Akins - EVP, Generation Susan Tomasky - President, AEP Transmission Brian Tierney - EVP and CFO

We thank all of you for being here. This is a pretty exciting day for us, and we would hope an exciting day for our shareholders and our customers.

I hope that I know most of you. My name is Mike Morris, the President, Chairman and Chief Executive Officer of American Electric Power Company and we decided that trying to combine an analyst day and our third quarter earnings would be a better way to get a face-to-face Q&A between us and the management team of American Electric Power so that we can get into depth about whatever issues are on your mind.

I always enjoy the quarterly earnings update and learn a great deal from the questions that you ask about the things that are paramount in your mind. But it's always faceless, because of the way that we do it.

And we haven't had a full-blown analyst day for a while, but for the things that EEI does, and we thought this would be a perfect way to do that. And as it turns out for the actual EEI meeting, Brian and Bob and Nick and Venita and the team will handle all of that as we're trying to convince the Chinese that investing in carbon capture and storage is a good thing.

And if you know anything about China, you know that they want us physically there to sign memorandums of understanding. So I will not be able to go to EEI.

Not that that's a big loss for you, I'm sure, but at any rate, we thought this would be an appropriate way to go about doing it. You know, when you do things like this, and you've already read the press release on the third quarter performance, it's clear that we had an outstanding quarter.

We feel very strong about how that will allow us to finish the year. We have a number of levers to pull if needed to, to make sure that we get within that narrowed guidance that we provided for you at the end of the second quarter.

There are many questions about that. And because it was the second quarter, we felt it was appropriate to be somewhat conservative.

Many of you said it was after those facts, wise or conservative; it was just the better time to do that. We now feel very comfortable about 2010 and we've shared that data with you.

And of course, we're also eager to share with you 2011, 2012 and beyond where we think economic recovery will have a substantial positive impact as will Susan Tomasky's Transmission play. As the years continue and permits come in hand, capital is put to work; the returns on the capital are almost automatic adjusters throughout almost all of our service territories.

So we're kind of encouraged about where we are, and where we're headed. Let me get through this, believe-what-you-want-to-believe story.

A year ago, these were the things that were on our mind coming into 2010. How are we going to work our way through the economic challenges that face us?

What we told you in 2009 was that we had forecasted some recovery in our residential, commercial, industrial space on a normalized basis. And if we didn't see that recovery, we react to it.

And of course we did exactly that. We said that we would maintain our capital discipline and throttle back from the 4 billion-odd dollars we had invested in 2006 and 2007 and the $3.5 billion in 2008 and throttle that back substantially in 2009 and 2010.

Many of you say, well, doesn't that slow down the rate machine and therefore the earnings strength of the company? And it does.

But at the same time, in the regulatory pressures that we were facing, at that time we thought it was the appropriate way to go as we, jurisdiction by jurisdiction by jurisdiction, made those filings that we thought were essential to earn our rate of return, or at least reduce the regulatory lag between the time capital's invested and the time you began as investor to see the benefit of that capital invested because our customers see it on day one, and we wanted to shorten the time between when they had the advantage of it and you had the obvious earned advantage of it as well. And we did that.

And now, as you look at 2011, 2012 and beyond, you can see that we think there's room to make additional capital investments as we go. Many of you have continued to ask, how is it that anyone can manage their way through 11 jurisdictions in seven principal operating companies?

And you'll get a good view of that today as you get a chance to dialogue with the operating company Presidents and Bob Powers who manages the utilities for us at American Electric Power, because that has happened now in a series of years where every year we go in with a stack of rate case increases that we expect to receive. And each year-over-year, we not only have been there, but somewhat above it; 2010, exactly like the many years before it.

And as you look at 2011, the need for recovery in the rate cases is very, very slim, something on the order of $240 million, $250 million, about $157, $158 of it already in place that will kick in automatically on 01/01/2011. So we feel pretty comfortable about that as well.

Issues that are outstanding that probably are outside of our control, but surely inside of an envelope where we can influence them are how states go about the business of creating jobs and how the federal government goes about the business of addressing the issue of building out a robust transmission grid to handle the renewables and things that they would like to see done at the federal level as well as addressing the issue of a global challenge of how to address the United States carbon footprint as compared to the world carbon footprint. And we have been deeply involved in all of those activities.

We were a principal participant with the NRDC in crafting the Waxman-Markey, which we thought was a reasonable Bill coming out of the House. We knew it needed substantial improvement.

And with the Environmental Defense Fund, and Senators Kerry, Lieberman and Graham before he dropped out, we were incredibly deeply involved, what become something that we were real advocates for at Kerry-Lieberman; it had things that truly appealed to us. So when we look at 2010 from the lens of 2009, when we share with you the things that concern and the performance that the team at American Electric Power has experienced, and you as investors have and will experience through the rest of the year, we feel really good about where we are.

As you know, I've talked in terms of retiring from Chief Executive Officer since I actually went to Northeast Utilities 1997. Having been born on November 11, and realizing some years ago when I spent a minute looking at it as you do when you get to be middle age 50, you start thinking about, "I want to run, I'll turn 65."

It looked like it's amazing. And 11/11/2011 I'll be there.

So, someone asked me the other day, "What are you going to work on in 2011?" And here are the issues.

Here are the issues that we will continue to work on. Many of you were at a meeting yesterday where two of the commissioners including the Chair of the PUCL shared with you some issues that are in front of them.

Obviously, those same issues are in front of us, resolution of this hearing as far as it pertains to our 2009 performance is center stage, front and center. Papers have been filed, discussions have been ongoing.

And we will see a resolution of that according to the chair of the commission before the end of the year. We told you about two or three months ago that never thought it would be resolved before the election which is now only 15 days away.

And we feel as comfortable today as we did then. We have made a very strong case for the rational of the earnings that both of our operating companies and I have seen.

And we think that that will come out without a great deal of impact on us as we go. The issue will be, "Will we get enough reading in how 2009 has handled to address 2010?"

Because we're convinced by 2011 the operating companies will be fully blended together in a merger activity which will be filed shortly. And we feel comfortable that that will go through without much of a hitch.

The filing of a electric security plan for the year is beyond 2010, 2011 will also happen in the first quarter. We think that is the appropriate time to that.

And we feel relatively comfortable about how that will unfold. We are one of the principle commentators along with many, many others on the FERC's Notice of Proposed Rulemaking on how they finally are going to take the mantle that's essential if Transmission is going to built in this country.

Two issues, one without question they are overriding opportunity to approve projects that are essential and needed without the mask of a second tier approval authority only after the States have been unable to come to resolution. We'll probably get another step in the right direction from the 2005 legislation from the FERC and that should be helpful.

But more importantly for us, and quite honestly for you as investors is the cost allocation issue, which we think the FERC will address at long last. On something that will be very similar, I would hope, to what the software's power pool has done on higher volume transmission line, higher voltage and volume.

Transmission lines being allocated on a much broader sense than the lower volume lower voltage small energy delivery lines. So we'll see how that unfolds.

The comments have been given. There are many on the commission who believe the cost allocation is an issue that they clearly have fully sway over.

And something that I think they'll find the kind of answers that we're interested in. Nick will share with you our approach to how we're going to handle the issue of environmental policies.

I think you're beginning to see particularly from our friends in Texas as only they can do, thumbing their nose at the Federal EPA and saying, "Have you even thought of the magnitude of the many steps that you take? Have you even done an analysis of the financial impact on the U.S.

economy of all of these individual rules that you are putting out?" The answer to that of course is 'no', are you kidding me, we do each one as a one off.

And each one of them has almost no impact on GDP, but collectively they do. The Environmental Protection Agency is in fact a controllable organization.

Many of you might not believe that to be the case. It is.

And no matter where the elections go in November, I think the EPA is going to have to step back for a moment. Take a break, and take a look at that issue.

We've made some very pointed testimony on the transport rule. Not that they were only concerned about it and how it affects us, that's a plus; the day that they intend to do it, to pass a final rule, mid 2011.

And demand that you deploy technology January 1, 2012, even they can't do that. Of course they couldn't get it out by 2022, but that's a side matter.

I thought that might just get a chuckle out of you, I want to make sure you're all still awake. But at any rate, the fact of the matter is we think that they'll slow down in the process and ultimately go forward, do things that make sense, allow for America continue to burn it's most prevalent fuel, unless Shell gas swamps coal eventually some day.

It could happen, might not. Coal's going to play, you've heard me say that far too many times; in the world and in the United States it will be cleaner, it will be better.

We will make those capital investments on the plant where that makes sense, and we'll recover those capital investments and show those results to you, our shareholders. Succession planning and transition, I'm not spending a nickels more with the time on that.

The Board is in deep deliberations. They have excellent internal candidates.

They are doing their governance due diligence requirement to look outside as well. By the end of the year, we will have selected someone to be President of American Electric Power.

And that someone, presuming everything works, as I would expect that it will, will be named Chief Executive Officer November the 11 of 2011. And then, most importantly, today's discussion on long-term growth and capital allocation plans and the team, Brian in particular will take you through a great deal of that with granularity.

And we're quite excited about the opportunities that we see in front of us, when we look at the company in 2011. So let's go to that Slide now.

What you saw in our press release of third quarter 2010 earnings was that the economy continues to be a bit sluggish, but improving. Our industrial sales on a weather-adjusted basis have been good.

Our commercial sales on a weather-adjusted basis had been flat, and our residential sales on a weather-adjusted basis had been up some. Having said that, the weather of course has been very good to us in all utilities and a great deal of Corporate America during the third quarter, and we're reflecting that as we go.

And that brings us to a free focused view of how to allocate capital. As I said earlier on, we'll be bumping up the capital spend in 2011 to this $2.6 billion that you see on the Slide.

That's intended to take full advantage of the opportunities that we see, some of it in generation, a lot of it in distribution, as we have tremendous capital needs throughout the entirety of the 11-state footprint. As you know, equity capital invested in the wires business is almost rarely challenged, and usually treated very fairly in the rate of return and the rate recovery process.

We'll bump that capital spend up in 2012, because we think the cash flows will come along as well. And because we have excess capital on hand today, as you know from the press releases of this morning, we will recommend to the Board of Directors this calendar year to have a 9.5% increase in the dividend that we pay to our investors.

Because we think, in these restricted times, giving you back capital by way of dividend increases is an important way for you to continue to feel comfortable about your investment in American Electric Power. This keeps us well within our 50% to 60% guidance of payout ratios, which tells you, I hope, and surely us, that there's continued room for improvement as we go.

Some of our colleagues who are in the yield range that we'll now be in are with huge payout ratios that at the long run aren't sustainable without some kind of different approach toward their capital structure, and we feel comfortable about doing that. And because the pension activity has been affected by the overall performance of the stock market, we have pre-funded much of it in 2010.

We'll do some additional cash investments in 2011. And I think that that also takes care of the financial impact of having to fund it in a much larger sense with an impact on earnings per share that ultimately would have an effect on the share price.

We think this is a reasonable way to balance our employees' concerns about the funded status of pensions, as well as our investors' concerns about seeing to it that we'll be able to manage the capital requirements and the cash flows that are essential for the company to continue to be successful. Brian will take you through some of the statistics, but there is no question that through the work holiday, Susan Tomasky, before her, Brian Tierney now is CFO, during my term as CEO of American Electric Power, I think we've done an excellent job of managing the balance sheet that was awfully unwieldy when we got here with a high risk profile on it that today is extremely conservative with an extremely low-risk profile on it, except for the beta that's required for reasonable returns on equity where we'll talk about how risky the business that we're in is.

I thought that might get a chuckle out of you. Well, but obviously it didn't.

The capital spending plan really as I've said now for '09, 2010, '11, and '12 and beyond is very much predicated on making sure that we maintain that capital discipline as we go. Everyone has said to us, you guys seem awfully low compared to your colleagues at 2% to 4% growth profile going forward.

And as you can see, in the 2011 number versus where we think 2010 will come in, we're looking at a 4% growth target. And as you see here on this Slide, 2012 to 2014, we think 4% to 6%.

And that really is a combination of a couple of things. That's a combination of the economy recovering and Transmission playing a larger role.

When you looked at a 5% or 7% range in 2014 and beyond, it again is the effect of the economy finally coming back to some normalcy, whatever that might be, plus a great deal of the transmission projects now approved, moving further down the line coming online and moving into the rate recovery and the return for capital invested. And then by 2014, we'll have a pretty clear picture of the environmental investments that we have made, want to make and the effect that they will have on the earnings strength of American Electric Power as we go forward as an integrated, combined company with a great deal of capital investment opportunity.

So we feel pretty comfortable about where we are, where we have been; we think that we have taken this ship through some reasonably choppy waters without much impact on our shareholders. The returns have been reasonable; not as good as some, but better than many, many others.

And I can't tell you how proud I am of this executive management team. And I'd now like to turn the podium over to Bob Powers, the President of AEP Utilities, and his colleagues, the Operating Company Presidents to share with you the deference that we have taken towards the Operating Company model and what we think that it will yield.

We'll then move on to Brian and others and then get to your Qs and As.

Bob Powers, President, AEP Utilities, and it's indeed my privilege to lead the seven operating companies that comprise the AEP system. We are here to talk about those operating companies this morning and some modifications we are making to our Operating Company model.

As Mike indicated, its worth repeating, the operating companies have been very busy since he's come to AEP, delivering rate proceedings the last seven or eight years. In fact, rate recovery over those seven or eight years has been well in excess of $2 billion.

And we are here to talk about some modifications, not the establishment of Operating Company model this morning. There are some differences however from 2004 and 2005 when the most recent model was implemented to now, and what are some of those changes?

First of all, we had a lot of headroom in rates back in 2004 and 2005 for a variety of reasons. Number one, the merger had locked and frozen rates across the AEP system for a number of years.

The economy was reasonably robust, so we had some modest growth in electric consumption et al, leading to more headroom in rates. We also had a situation in which at the time I was in the middle of putting scrubbers and FCRs on power plants, and I cried for more clarity out of Washington.

But looking back, we actually had quite a bit of clarity. And I knew what scrubbers and what FCRs to put on power plant.

Clearly, circumstances these days are different than that and it's a challenging circumstance that Nick will talk about in just a few minutes. And then third, in current time, we have an economy that is still sluggishly recovering.

And those circumstances lead to us standing to assess the Operating Company model and make some changes. As we look at that calculus, when we look at that circumstance, the conclusion we come to is that although public policy may be established from Washington regarding environmental compliance, and although AEP Corporate out of Columbus will certainly have input into the strategic response to those public policies, at the end of the day, we need a tremendous amount of local input and a lot of local design regarding what our response to those circumstances are going to be.

And that's where we are going about modifying the Operating Company model. We are giving the Operating Company Presidents the ability to strategically respond and financially respond to those circumstances.

So what are we doing? We are giving these people and two others the ability to drive results at the Operating Company level.

Specifically we are giving them accountability and authority to allocate capital across the business units, across G, T and D within the Operating Company itself. We are giving these individuals the authority to be accountable across those business units for O&M and capital results.

We are giving them the opportunity to dialogue with their regulators and their local legislatures to make sure that AEP strategy is in alignment with local needs and local desires. And finally, we are giving them the absolute ability to make sure they are responsive to customer needs and customer desires so that the amount of hostility from our ratepayers towards rate increases, nobody ever likes rate increases, but our customers don't need to stall to make sure that our level of service at the operating companies is adequate to satisfy our customers' desires and make them reasonably responsive to the need for rate increases.

All that should lead to more efficient deployment of capital; all that should minimize regulatory lag, and all that should lead to AEP's strategic response to public policy to be in concert with our local operating company regulators and legislatures. I think that is a pretty good deal at the end of the day for our shareholders.

What do I do personally to lead this and what gives me confidence to lead the circumstance that I have described? Well first of all I don't feel alone up here.

That's a joke also; I have got five people next to me. But I want you to know, this is not an operating company initiative that's being thrust or hoisted upon the corporation.

This is something that we have thought long and hard at an executive level, involve the Operating Company Presidents in describing what we are going to do, but I feel I have absolute support from my executive colleagues at AEP. This is a corporate initiative.

Nick Akins, Susan Tomasky, Brian and Mike, myself are all bought into this model and we are all committed to making it successful and making it work. Second of all, I gain some confidence from my own background.

I've been at the utility business now for 4 years. Prior to that, I was Executive Vice President of Generation.

And I came into AEP as a Chief Nuclear Officer. I think that framework gives me confidence; I understand the issues, I certainly understand the challenges that Nick and the Generation team face in addressing public policy issues out of Washington.

And I think that nuclear background, at least my colleagues tell me, gives me some confidence and some ability to deal with the discipline issue of how you do about achieving an objective with finite resources, but making sure that there's a focus and a discipline to achieve the results that we need. And third, I very much depend on these five people and Greg Pauley and Kentucky Power and Wade Smith in AEP Texas to help this whole thing work.

So with that, let me introduce my colleagues here and we'll get right into some Q&A to hopefully address many of questions about the operating companies and we'll get going. To my immediate left is Stuart Solomon, a native of Texas, a graduate of Southwestern University in Texas.

Also has an MBA from UT and a JB from University of Colorado. He is our President of Public Service of Oklahoma.

Sitting next to Stuart is Charles Patton, President of Appalachian Power. Charles is graduate of Bowdoin College, a Polar Bear, and also has a Masters Degree in Public Policy from the LBJ School in the University of Texas.

Charles is a veteran of Columbus Southern Company and comes with sort of long history in Operating Company implementation. He was the President of AEP Texas as well before going to APCO.

So Charles, welcome to the panel. Venita McCellon-Allen next to Charles is our President of SWEPCO.

She is a native of Longview, Texas in the heart of SWEPCO's service territory. Venita is a graduate of Texas A&M and also is a veteran of the CSW Corporation and has had many responsible executive positions in AEP before going back to SWEPCO as President.

Next to Venita is Joe Hamrock. Joe is a native of Ohio, grew up in Mingo Junction.

I'm sure you all know Mingo Junction is a suburb of Steubenville. Joe is a graduate of Youngstown State with a Degree in Electrical Engineering and has an MBA from the Sloan Program at MIT.

And Joe had his first teeth in AEP working in the AEP Ohio companies back some years ago in the early '80s. Next to Joe is Paul Chodak.

Paul is a graduate of MIT with a degree in Nuclear Engineering, PhD by the way in Nuclear Engineering. Paul has a lot of experience in Generation.

I worked with Paul a decade or so ago in Generation. Had been President of SWEPCO and is now President of Indiana Michigan Power.

So that is five of the Operating Company Presidents that represent the AEP system. So folks, I've teed up an interesting new model for the Operating Companies to talk about your discipline and your ability to allocate capital and your ability to drive results.

But I would say as a pragmatist, there is no better way to get the Operating Companies moving real well that to have a recovery in the economy. So Joe, maybe you could start off with talking about how the economy is doing in Ohio, and maybe broaden that a little bit to talk about how things are going in the East overall.

Sure, Bob, glad to. I will speak to the Midwest, which is the Ohio companies as well as Indiana Michigan, Appalachian Power, Kentucky Power.

And the economy, as is the case on the national stage is front and center, both in the political dimension and in the business community and across the states that we have served; we serve in Ohio 63 and Ohio's 88 Counties. And the story is very mixed.

What we have seen is, in terms of economic output, 2010 so far has actually been pretty good, mid single digit increases in economic output across the Midwest territories, though unemployment continues to linger at levels that we saw last year at the depth of the recession. So, so far a bit of a jobless recovery.

There are certain sectors that really started to show signs of life, and that's been encouraging across all of the territory. What that's translated to for AEP East, the Eastern Companies this year is about a one percent normalized low growth over 2009 led by the industrial sector.

Just over 4% growth in the industrial sector across the boards with some notable sectors inside the industrial class really leading the way. Primary metals in particular, we have seen about an 18 % increase over 2009 levels in the East Companies.

We have certainly seen some fallout. Some of the plants haven't come back from the recession, but those who have, have come back strong.

We have seen really strong results in that sector. Right behind that, plastics and transportation at about an 11 % growth rate in load so far this year.

And from there, other sectors, mining in particular, in Appalachian Power, Charles has certainly seen some activity in APCO with the mining industry picking back up and a lot of new load emerging there. It's not just recovery, but it's actually growth in that sector.

So we have seen now industrial lead the way. As Mike said earlier, commercial and residential still relatively flat on a normalized basis in the East, consumer confidence and the industrial confidence, that's one of the key differences.

We've spent a lot of time talking to our major costumers. And while the production levels are up and load is up, the confidence in visibility hasn't yet returned to the levels we saw a couple of years ago.

And most importantly, I think one of the key roles that each of us play is in the sphere of economic development. We spend a lot of time working with our major customers, both on retention and attraction of new investment, new jobs and for us the new load that comes along with that.

In Ohio in particular, under the new law we have got the opportunity for 10-year contracts or a multi-year contracts. And we know from experience that even in this market environment that we have in Ohio, the capital-intense, energy-intense industrials are looking for more certainty than the market provides.

So the opportunity for longer term structured deals that we can do under the new law, and certainly that the other operating companies have some opportunities to do as well has been a real opportunity for us and something that we have got a lot of activity in that area.

Thanks, Joe. Venita, you've worked in the East; you're back out West.

You're helping to keep an eye on AEP Texas. What's going on from a SWEPCO perspective and a West perspective with the economy?

Well, with SWEPCO I have the opportunity to serve three of the four Western footprint states. So I take the opportunity really distinct from PSO as well.

And we are fortunate in that we find that we go into the recession a bit lighter and come out a bit earlier. And we didn't go in quite as deep, and we are having a bit more of a balance in our industrial sector.

For SWEPCO specifically, our load is at 10% year-on-year compared to 2009, led by our industrial sector. And I think we can attribute that much to the Haynesville Shale and much of the shale play that's going on in our area.

That's a significantly important gas area, both in Stuart's PSO area in AEP Texas and also in SWEPCO. For example, SWEPCO's biggest customer is US Steel.

In the recession, it was shut down. Yet now, it is back in full production.

This is a tubular steel production and it provides tubular steel for the Haynesville share market and its back at full production full roar, and we are very excited to hear that. And we have some of the same things, residential flats, customers' kiosks flat.

commercial still rocking along, not quite as where we'd like to see it, but we are really excited about the industrial growth we're seeing. We are hoping that the others will follow along very quickly.

I appreciate that. I'm hearing that the industrials are coming back pretty strongly.

We got to keep our eye on Commercial and that seems to be the case both East and West.

Indeed.

All right. Let's talk a little bit about the new Operating Company model.

And you heard me kind of tee it up, but these folks are on the firing line and they have been through a cycle now in implementing the new Operating Company model. So Charles, I'd like to get your perspective from an APCo point of view, what's the new operating company feel like in contrast for the folks?

How is it different than it was before?

First of all, it feels real good. Well, first off, I'd be remiss if I didn't point out that even before the new Operating Company model, we did a good job.

I want to make something clear is that, it wasn't something that was terribly broken and needed to be fixed it just needed to be enhanced. And the bottom line is that historically what happened was, the operating companies, we were like minority owners.

And we were delivered a packet of goods which was planned for Generation and Transmission. On the distribution side, if you remember back in 2004, we had already received control of that part of the business.

And so that part of the business, we were able to effectively manage and make decisions and pull the appropriate levers to get the most optimization out of our recourses. But with the G&T part of the business, though with (rail) run and though there were great plans that were delivered to us, those plans were delivered to us.

Now, those plans were great and if you look in our rate cases and then you measure our performance as a company against other utilities, you'll find that our Generation performance is a leader in the nation, you'll find that our Transmission performance is a leader in the nation. So 90% of what we got was just fine; it's just that incremental amount.

There's about that 10% where the Operating Company Presidents need to be able to pull on the levers to be responsive to their customers, to the regulators and to all the stakeholders who are involved in the process. And that's the real difference.

And let me give you a specific example that happened just in the short time that we've been in this particular model. Well, in APCo Generation, there was a capital investment opportunity in Generation that we didn't spend all we had forecasted to spend.

In fact, we were about $6 million under what had been forecasted for the spend for this particular project. Now what would have happened before is the said $6 million would have went back in the Generation and it would have been used for something useful, something beneficial for the customer, but from Appalachian point of view, it may not have been the most optimal utilization of that capital.

Well, instead of that $6 million going back and possibly getting it through the previous process, Generation's there at the table, Transmission's there at the table. We sat down and we planned the Appalachian Power.

That $6 million was used to buy 28,000 automated meter reading demand meters for our larger customers. Now the benefit of that is that there's capital that's being deployed that can be recovered, but also, by investing in old AMR demand meters we are going to be able to lower our O&M on our meter reading with the deployment of those meters.

And so that is as good example as possible of how it works and how it's different from where it was.

Paul, you were put into SWEPCO as President under the old model. As we moved you to I&M back in June, you had a new model and a new opportunity.

So how do you see that playing out in Indiana Michigan?

Well, we're real excited about it. Each of the seven operating companies really are local businesses.

Our folks live in the communities that we serve. They raise their families in the communities that we serve.

And that really provides us a great opportunity to have insight into those communities. And as we look at the challenges that Nick will talk about coming our way and changing the industry, there's absolutely no shortage of opportunities for investing capital in our companies.

The challenge is to figure out where is the best place to put those investments in. And as we work on maintaining our balance sheet discipline and making sure that our capital spend is in line with our cash flows, the Transco situation that Susan is going to talk about, formation of Transcos will help with that where we're still going to have a real key issue around prioritizing capital spend.

The local operating company model will provide us the real flexibility that we need to sit down and talk to the regulators, to talk to our politicians and to listen to our customers and figure out what is it that they want. There are many opportunities around renewables, around gridSMART, around technology, how do people feel about coal, nuclear, gas, where would they like to see those investments made.

And because we'll be able to have those conversations and have the flexibility to adjust our investment strategy, we'll be able to pick those investments that the regulators really support, that the politicians really support on a local level, which will enhance our ability to get a fair return for our shareholders. I mean the bottomline is that now we have the ball, and it's our job to carry it over the line with each and every project that we do.

And I can tell you over the last three months since I'd come to I&M, I've had the opportunity to go out and travel to our service centers, travel to our plants and talk to the folks at I&M and really explain to them and talk to them bit about the ability to make decisions on a local level and also the accountability for making sure that we will put in that capital to good use to serve our customers and earning a fair return for our shareholders. And I can tell you the folks that are on the field are just very enthusiastic about this.

I'm taking no small pride in Mike's comments that Texas has given feedback to the EPA and not that I paid personal responsibility for that, because it's been certainly a team effort. But that's partly because the industry led by AEP has been in the office with regulators, in the office with the TCEQ, using that relationship to help them understand the effect these regulations are going to have on shareholders, on regulations, on the industry, on reliability.

And that helps funnel that perspective back to Washington.

Thanks, Venita. Thanks, Paul.

My friend Stuart here, it's fair to say in 2004 that financial performance of PSO was somewhat anemic. Today, you have double-digit ROEs.

So as you hear Paul, Venita, myself, Charles describe some of the differences in the new operating company model, did you use any of those over the last five, six, seven years to turn PSO around?

Absolutely. Good morning everybody.

I think as a follow-up to what all my colleagues have talked about, we put in place a number of years ago a strategic plan to try to address what our situation was, which was low single-digit ROE. And that plan wasn't done in a vacuum or wasn't done in isolation.

It was done as a part of going out talking to our regulators, talking to our customers, to customer focus groups, talking to key stakeholders like legislators, like interveners in our rate cases. And we put together a plan.

What they told us was that of all the things that they wanted us to focus on, they wanted us to focus on improving our reliability, bottomline. They wanted us to improve in our customer care.

And so we put a plan in place to do that. We called that our reliability enhancement plan.

A lot of tree trimming, as you might guess, was part of that plan. But we also had a component of that plan which was kind of unique at the time, and that was to strategically take overhead lines and convert them to underground lines where it makes sense, particularly in the urban areas.

And we put in place a funding mechanism for all that to a rider, including a rider that allowed us to take that capital investment with very little regulatory lag into earnings, so almost on a real time basis. We got more people out in the community.

We expanded our community presence in order to address one of those concerns we heard from regulators. We also worked on a number of things to improve our customer satisfaction and customer care.

All those things came together, because we talked and dialogued with our key external stakeholders. We were able to put a plan in.

We improved in a lot of operational areas, but we also were able to sow the ground, if you will, in order for us to improve our financial performance. We had a number of rate cases over that period of time, five major cases over six years, but the success in those cases that ultimately drove the double-digit returns you are talking about, Bob, was because we listened, we dialogued, we put in place that plan to address those local preferences, local needs in that local design that you were just talking about.

So, a great example I think within the distribution segment of what we're going to do on a larger basis due to the operating company model.

Thanks, Stuart. And operating company results can be turned around.

So let's get into some APCo specific questions. And, Charles, we'll put you in the hot seat.

In 2009, APCo's ROE was about 7%. You received an order in Virginia for a base rate case, and you filed in West Virginia for a base rate case.

What do you see is the prospects for turning 7% ROE into something that's in the double digits.

I feel very optimistic. First of all, we have a case currently filed in West Virginia.

And in Virginia, we will be filing next March as part of our biannual case. In addition to that, Virginia has a number of riders or trackers that we'll be eligible for also, and we're evaluating them.

And so, as we look forward and as we reach out to our commissions, as my colleagues have mentioned, and reach out to stakeholders, I am very confident that we will be able to successfully navigate through these cases and do quite well.

Venita, a couple of questions for you in SWEPCO. Between you and Paul over the last couple of years, you successfully found rate cases in Arkansas, Louisiana and Texas.

What's your assessment on the potential conflict between obligation to file those rate cases, invest that capital and ratepayer fatigue for rate increases. Where are the opportunities in SWEPCO.

Well, Paul in the team did all the heavylifting on the right case, as I inherit the good rate to come with that and the good returns. So I have to give him credit for that.

And as many of you know, those rate cases that were filed in Arkansas and Texas and annually in Louisiana thorough a formula-based rate are the first rate cases that were filed in SWEPCO in 25 years. And so we had the big obligation coming of bringing both Stall fully and Turk into the rate base by 2013 or so.

And we are very much focused on the headroom that we need to get that work done, and we're optimistic that we do have that headroom available. Now are we cavalier about it?

No, we're not, because a rate increase is a rate increase and it's difficult no matter what it is. Our rates are some of the lowest in our area.

In fact, they are the lowest in all of our areas with the exception of OG&E and Arkansas who has a case pending. And so we believe they will pass us if their cases are judicative.

And so we have the lowest rate, but customers don't care that their rates are not as low as a neighboring utility. They only care that their rate is higher than it was last month.

And so we have to be very cautious, very careful about how we position rate cases, how well we communicate, how we sow that field, something that we talk about a lot, and use that headroom wisely so that we do get Turk into the rate base, a big, big investment for SWEPCO and something that we take a big responsibility for on behalf of the shareholders in making sure that we do that with as minimum of regulatory lag as possible.

And you know, Venita, kind of reminds me thinking about it. When we look at where our rates are, we are in a similar position in both Indiana and in Michigan, and we've got to somehow help people understand the value that we bring to them.

When we went for the rate case in Texas, there were challenges; it was a pretty small rate increase on an absolute basis. But you got to help people understand that the (NFL) package that they are paying $50 a month for, that electricity actually brings more value.

And when you go out there and talk to our employees, there really are ambassadors in the in communities. For example, in Indiana Michigan Power, we've got 2500 employees that are at the Softball games.

They're standing at the outside Church on Sunday. And they have the opportunity to reach out and talk to our customers.

And as part of this operating company model, providing that identity to folks to go out there and really talk to our customers and help them explain the value of electricity is really going to help us.

Now, we have to be strategic about it. We've got to be careful not to pancake too many cases, but to be thoughtful about how we do it.

And we do believe that there's room to get Turk into the rate base, which is something we are all focused on. Even Paul Chodak at I&M is focused on that.

Yes, I know. And a quick fact to it on value proposition.

My team told me the other day that plug-in hybrid electric vehicle and off-peak rates we charge that vehicle the equivalent of $0.60 a gallon gasoline. Folks, there's lots of opportunity in the electric sector for value, and his team is going to put that opportunity to work.

You talked about pancakes, right, Venita? Talking about a big pancake, let's talk about something that impacts electrical rates and that's the Turk plant.

I think what's on everybody's mind is what seems to be the numerous legal proceedings that inevitably are associated where the project is complex is that how is all that going at SWEPCO?

Well, if you look at the big picture, I actually believe it's gone well. So our big picture goals are to gain our required regulatory approval, start construction of the plant and continue construction of the plant without interruption.

We're doing quite well, that's exactly what we've done. We've gained all the required regulatory approvals which started construction in November of 2008 and we have been busy constructing the plant.

On total construction basis, we are about 44% complete on compliant on the plant. And we're building a power plant, and it's a beautiful plant.

You are going to be very proud of it on behalf of shareholders when you see it. Now all of this noise that's coming from the interveners and the opponents is a lot of noise.

And so certainly, it's a challenge. It's something that we live with every day and we vigorously defend the reputation of the company; we defend the plant against every day.

I'll certainly be glad to answer more specific questions about that. But I will tell you, we are focused on continuing construction of the plant, and we are being successful in doing that.

Well, Venita, I don't know anyone more tenacious than you to make sure that's well shepherded and that that will get a good result. Paul, I'll turn to you for a moment though.

Did I mention by the way that Paul's PhD is in Nuclear Engineering, and we thought it would be kind of cute to put someone with a PhD in Nuclear Engineering at I&M where we have our two nuclear units. So you've been there three or four months now.

What's your perspective on the Cook rotor replacements and potentials to upgrade the Cook plant, and how do you plan to address those opportunities along with your (Bosal) fleet?

Well, Cook just absolutely continues to be a shining star in the Indiana Michigan portfolio. Their performance is nothing short of outstanding.

As we look forward, we'll be replacing the road around the Unit 1 outage in fall of 2011. And beyond that we'll be making investments in the plant to make sure that we take advantage of our 20-year license extension that we recently received for both Cook units.

So we'll make those investments. And we continue to look at the potential for an upgrade.

And as I talked about earlier, we actually have no shortage of opportunities to put to work at Indiana, Michigan, and across the operating companies. So what we'll need to do is, is really put that Cook upgrade and take that capital investment and kind of put it in the stack and see where does it fall out in terms of going to work for customers and really building a return for shareholders.

We keyed up Stuart earlier that the environmental regulations are changing frenetically out of Washington. You've got a couple of coal units in Northeastern 3&4 if I remember right?

So what do you see happening for a company the size of PSO as you contemplate scrubbers, SCR enhancements, other environmental requirements of PSO?

That's actually going to be a great opportunity for us to put this operating company model into good use. As Bob said, we have two coal units at Northeastern, about 950 megawatts total.

And for a variety of reasons, all the environmental rules that we have been talking about, we're looking at spending several 100 million dollars of environmental controls in order to comply with those various rules. But we just walking down and putting in those sorts of investments, it's incumbent on us to engage in a very good dialogue with our regulators, community leaders, our legislators and general customer base on what that decision really needs to be.

We need to partner with those folks on a decision of that magnitude for our size of a company. And so we'll be talking with them about those options, and the options really range from putting all those environmental controls on all the way to retiring the unit and replacing it with something, either another capital investment in terms of our plan or purchases or whatever we decide to do in concert with them.

But I believe that working with them, we're going to be able to put in place the right kind of decision that includes a funding mechanism for that capital investment. Again, the operating company model is designed to turn those capital dollars into earnings, and we think that it will be a good time for us to work externally and also internally.

We're going to have to be prioritizing capital in order to support that decision. So we'll be putting the model in place internally as well.

Joe, we haven't forgotten you. You run our biggest operating company for no other reason than our people are very, very interested in Ohio.

But in addition, you've got some interesting activity with ESP that needs to be revised and you got the SEET opportunity. So what do you see going on both in terms of your thoughts about the ESP and SEET?

Well, we continue to adapt in Ohio to a dynamic regulatory environment and a dynamic market environment, and we really are between the two, the way the business model works in Ohio. In terms of adapting, one of the things that we're doing, Mike referenced it earlier, is we filed yesterday with the PUCO to merge the two Ohio companies, something that's been long in the making.

I've been with the Ohio companies for a fair portion of my 25-year career. And the Ohio Power and Columbus Southern entities have been operated as one for nearly two decades now.

CSP was acquired by AEP back in 1980. And so we've come a long way in terms of capturing the synergies that go with combined operations.

We're now at that point where it makes sense to merge the entities, merge Columbus Southern into Ohio Power. That helps us position for an increasingly dynamic marketplace and the new regulatory environment that we face in Ohio as a result of Senate Bill 221 a couple of years ago.

Beyond that, as you referenced, Bob, the ESP, the SEET proceeding is right in front of us. The hearing for the Columbus Southern, Ohio Power SEET is next week.

We feel that we've put together a very solid methodology, very solid results. And the Commission has a wide latitude in terms of how to apply this new instrument.

We're confident that the Commission recognizes that the need for capital investment in this uniquely risky environment that we have in Ohio should bring with it the opportunity for the kinds of returns that we've seen with Columbus Southern Power in the past year. It's certainly not something that we expect to lock in over time, but the opportunity to earn at those levels is commensurate with the risk we face, particularly the market risk that we face in Ohio and the opportunity for customers to migrate to other providers.

In terms of the ESP, you will see from the Ohio Company's new ESP filing by the end of the year and it will reflect the dynamics that I referred to and in particular the market environment. We have in our current ESP some legacy rate designs, rates that don't necessarily reflect the way the market would structure rates.

We expect to show a much more comprehensive market-based rate design in the ESP and an opportunity to be at a much better competitive posture given the market dynamics that we'd see in the coming couple of years. While the merger itself won't affect rates for the Columbus Southern and Ohio Power Company customers, we do expect in future filings including the upcoming ESP to start to move toward a combined set of rates and programs for customers, and it will position us well for the coming environment.

Hey, Joe, let's dig a little bit more into something you alluded to in your comments, and it's customer choice in Ohio. What do you see are the opportunities and the challenges of customer choice on the Southern and maybe Ohio?

Customers have long had choice in Ohio since Senate Bill 3 passed nearly a decade ago. It actually passed more than a decade ago, but customers have had the opportunity for choice.

And up until about the midpoint of this year, we saw very little switching rates in the Ohio companies. Our rates have been low historically, and we saw market prices that were well above the tariff rates that we presented.

Of course, we all know that's changed this year. We saw low rates switching through mid-year.

That started to tick up here in the last quarter, but still very low rates. We're at about 2% of our customers migrating away through September, just less than 5% of the load having switched at this point.

And we've got projections in for next year that show some increase in that. But one of the things that our team has done is our customers nearly always reach out to our team.

Many of my colleagues have talked about the relationships that we have. And customers when presented with these options and these opportunities to switch always come to us and ask how should I evaluate this.

And we want them to do that in the most informed way possible. That includes a look forward.

Many of the opportunities that they see today are for prices that will lock them in for two-and-a-half up to three years in some cases. And the rate that we have in place expires at the end of next year.

So we encourage them to make sure they make an informed decision that they look at all of the options that they have, including the tariffs that CSP and OP provide. And so we're proactively reaching out to customers, making sure that they are making informed decisions.

We think that will help with switching that will be very rational in the near term. It will allow us to position more competitively in the longer term with those customers.

Thanks, Joe, and thanks team. We're going to wrap it up at this point, so we can get on to other parts of the agenda.

But I do want to reemphasize that there are many, many factors that influence circumstance and strategic response. But we see this battle being won locally.

And we prepared ourselves to win that battle locally. And I hope I'm meeting the Operating Company President, you get a sense of their capability, their capacity to deal with this circumstance, and their enthusiasm to deal with this circumstance.

They've been looking forward to this responsibility, and they relish the opportunity around their operating company's as a P&L. And I know they're going to do just very, very well.

From that we're going to get efficient use of our capital. We're going to minimize regulatory lag, and we're going to make sure that AEP strategy is closely aligned to what our regulators and legislatures, and our operating company's believe is important for their regions as well.

So it's going to be a good deal. With that we have the pleasant opportunity to turn the agenda over to Nick Akins, who will talk to us about the challenges coming out of Washington with the generation fleet.

Thank you, Bob. Pleasure to be here today.

I want to thank all of you for taking the time to really learn more about AEP and what we're trying to do in the future. And I think you're going to find out that we're being transformational in terms of the activities that we're dealing with.

And when you look at the EPA, I know there's a party running here in New York, I believe it was, 'The Rent Is Too Damn High' party. And I think you could easily say that we're part of the 'EPA Is Too Damn Aggressive' party, but that's not all of the things that we deal with.

And when you look at the market fundamentals, and the way they are changing our industry, and our resource mix of the future. You're going to find that AEP is very prime and ready to address all the issues, and to move forward in a very positive way.

I'm going to go through some of the environmental aspect. But first I want to touch on something that Joe Hamrock mentioned.

He did discuss some of the issues around customer migration from CSB, just know that AEP is a big company. And while it may appear schizophrenic, we do have in commercial operations in the area that I'm responsible for, we have begun in AEP retail operations.

It's been in operation for several months, and we're aggressively pursuing customers and all of the jurisdictions in Ohio. We're certified to do business in FirstEnergy, Dayton and Duke as well as AEP.

And certainly we see that as a potential for our growth engine in the future in relation to addressing customer needs through the areas that have retail choice. So we're very proud of that activity, it's also moving very well, and it's something and I think they will be able to hedge against some of the issues of customer migration.

At the same time, our systems sales, margins obviously will be impacted as well, as customers migrate, generation is released, and we're able to market that not only in the wholesale market, but also in the retail customers through AEP retail operation. So I hope you'll see that as a positive.

And that I really believe from a retail standpoint for those jurisdictions, we're going to be very measured in our approach. But at the same time, we're going to look at opportunities throughout our footprint in terms of the ability to grow that type of operations.

So we see that as a key for the future. I was previously an Operating Company President.

And you don't really know how the company actually runs and how you have to actually allocate capital until you sit in that seat. And certainly it's one that's challenging, because you're not only addressing the internal needs of the corporation, but you're addressing the community needs, the commissioner needs, and trying to reach the nexus of what is important to our customers and our company and our shareholders moving forward.

And I think, that experience really led us, and Bob mentioned, that all of us, the executives are supportive of moving to this stronger operating company model. And it's for that very reason, as I was going through the process at Southwestern Electric of deciding what generation to put in place in various parts of the company.

It was important for us to not only to have a hand on what was going on internally within the corporation, but also being able to manage commissioner and staff expectations of where we were planning to head. And I think we've mentioned very well, we're in the third project, two of those projects have been concluded.

The Madison installed facilities have done very well. And in fact, the construction is going very well from a Turk perspective.

And we have every intention in having a facility in the area where everyone can be proud of, including the people in the community near by. So as we go forward, I want to make sure that we all understand that from a resource mix perspective, we are trying to move toward a transformation in the future, and execution will be key.

And that's why from the operating company perspective, we're going to have to be able to put plans together, to put in front of the commissioners and customers by jurisdiction. Because as we go through the environmental impacts that we're going to deal with, there will be different answers based upon what jurisdiction and what commission and what customers in each jurisdiction feel like their resource mix ought to be in the future.

And we have to be flexible in that regard. So I'm going to backtrack just a little bit on the first Slide here.

I just have a background of the AEP generation capacity. And you all probably already know this, but, that we're by and large coal fired in the East.

But we do have significant natural gas capacity in our Western footprint. It's largely gone unused until recently with natural gas process going down considerably, we do have a more utilization of our gas mix in the Western footprint.

That's also a lesson for our Eastern footprint. As you look at the East, we have the ability from a market perspective, you have the REX pipeline coming through, you have the Marcellus Shale that's picking up at activity.

And you have pipeline suppliers who are wondering what the fundamentals are going to do around their pipeline capabilities in the future. AEP East is sitting right in the nexus of all that.

And I think that provides us a great opportunity to really put forward transformational opportunities for, not only our customers, but in the end our shareholders as well. So I want to point you to a couple of things on this slide, that I thought were pretty germane.

I'm going to save you the trouble of looking at the fine print, because I do want to focus on the fine print, where we say that 91% of our coal is committed. You'll see from the coal price there, and I don't know if there's a pointer here or not?

Is that a pointer? Okay.

Well you can see it. On your average delivery cost in the East, you see the coal process essentially going down.

And the estimate for '11 is $51 a ton, it's slightly lower than the previous year, and note that it's 91% committed. We actually went through the process of thinking we were 100% committed last year, and we wound up being 110% committed.

So we want to be very flexible in the future in terms of how we deal with coal supply going forward. We're going to have to contract in a different fashion as well, because as we look at our risk associated with potential retirements of small coal-fired units, and as well the market risk of natural gas in the market versus marginal coal process, we really do need to be mindful of how we commit to future coal supplies.

And we're being very judicious about what we do there. There's a very positive story in this though, and that is our commercial operations, our generation and our resource planning are working better than they ever have before.

We have one of the most robust resource planning processes here at AEP that we've ever had. And the reason is, is because of the confluence of the activities associated with weather, these small coal units are actually going to run or not.

And we've gone through a very significant operation in terms of our extended start-up program. That's a first in the industry, that's being copied by several others now, FirstEnergy, Duke and others are looking at it, TVA as well.

It really is a method by which we're optimizing the use of those small coal-fired capacity units, primarily during the seasonal operational periods. And when you look at it, that coordination is key for us, we will only have additional coal cost that drive up those markets higher than $51, we'll only do that if there is a market that supports operating those facilities.

So if our coal prices go up, it'll be because of incremental supplies. But by virtue of the margins they were receiving from the market, that'll make sense to us.

So that's the kind of analysis that's getting done every single day in terms of how we operate particularly our smaller coal fire units. Also I want to point out on the bottom last slide, you will see we have vintage of units and whether they're controlled or not controlled.

The right side, obviously is what we're looking at. The older coal fire units, right over here, those units are primarily the older coal fire units, not controlled, not likely to succeed in an EPA environment.

And certainly one that they were very focused on in terms of replacement capacity. Now the question becomes how much of that capacity you actually replace.

And that depends upon what the market does. What our economy does in terms of coming back.

But also in terms of what our options are relative to conversion to natural gas and other things. We have investigated how to deal with capacity on these particular units.

You're running the situations and this is some of our comments relative to EPA transport rule. You have black start capability, you have voltage control requirements.

You have all those types of issues that you have to look at, not to mention then depreciated plant balances to deal with from a commission perspective to ensure that we're able to retire these units and replace them on these brown field sites with much more efficient natural gas capacity. That's primarily what we would be looking at, although how much of it will depend on how well we're able to deal with gridSMART energy efficiency and the other forms of resources that we look at.

So it'll be different by different commissions. But we'll get there with those kinds of plans.

So why am I actually up here to talk about is the confluence of all the activities associated with the EPA. And what it means to our coal fleet?

And Mark was right. I mean the EPA has not evaluated the cumulative effect of all of these rules that are being propagated on the existing capacity.

And when you look at it from a country perspective, there are many things that come together to deal with the forward looking cost of coal. And when you look at the forward cost of coal, it really is defining what that threshold level is for retirements of existing capacity.

And that's something that's very serious because if we retired too much capacity, too quickly, we will not be able to survive from a system dynamics standpoint, that's particularly important. So I've sort of shown this as a funnel with several filters, but when you look at the clear air transport rule, the renewables mandates which essentially take away from base load type capacity, we have to be concerned about, well what kind of capacity do we actually replace as we go forward?

And then from a climate change legislation perspective which we manage very well from an AEP perspective, we've been at the forefront of the activities in Washington relative to the climate change. And we intend on continuing to do that.

hopefully we'll be able to get a two year delay associated with some of these EPA rules so that we can have the right parties together, including (inaudible) the regulatory commissioners, the DOE, the NERC and FERC and other independent agencies to really take a rational view of what a transition should look like. But one thing in particular that I wanted to point out to you in this slide is the fear of fundamentals and how they're changing.

This is not something that AEP all of a sudden decided, we got these EPA rules coming down when you do something about it. We started this process a year and a half ago in front of our Board when we were dealing with the climate change aspects, and the results were the same.

We know that we're long on capacity, coal capacity, we know we have older coal fire units. And we're setting in motion projects and plans that will take care of the issues associated with this type of generation.

And as we look at it, the market fundamentals themselves are changing. And when you look at natural gas with a 380 price which is about what it is today, 348 I believe.

And you look at a 6,000 heat rate unit, that's marginally competitive with coal capacity. So we have to able to make sure we enable that transition to occur.

But it has to be done in a rational fashion. And when we look at the transport rule, the coal ash rules, all those cumulative effects, it does have an impact and it'll define how far we go into the generation set of the need for replacement.

We know we have about 5,000 megawatts of sub-critical coal fire capacity that's on its way out. And this next slide sort of demonstrates that.

I wanted to mention the dark spread compression. The fundamentals obviously are showing.

And with the Shale gas activities in 2009, we expect that dark spread to continue to migrate toward being essentially neutral. So if that's the case, then even fro a marginal perspective, you won't see new coal units built, you'll see natural gas built in its place.

And that's something that I think we're very focused on. So this is what we've been sharing with our Board for probably a year and a half.

It's been refined as we go along. But the threshold that I was talking about earlier is really defined in this inner category, the partially exposed units.

We have several units that we have already said are fully exposed; and that's the 5,000 megawatts of sub-critical generation, when you define replacement for that. The cumulative effect and the time tables and targets associated with the EPA rules are going to define how far we go into this partially exposed category.

Now, nominally on AEP system, like I said the 5,000 megawatts are basically the 200 megawatt sub-critical units, older. The partially exposed, you get into the 500 megawatt nominal capacity.

And in fact, it could get to 1,300 if it's uncontrolled. And most of our 1,300 are controlled, obviously.

The only we'll be talking about is Rockport that we have to make a decision on. But nominally, the partially exposed are the 500 megawatt units.

And the cumulative impact of the EPA rules are going to define how far we can go. Obviously, when you're looking at spending $1 billion on a scrubber on SCR versus building new capacity with natural gas or whatever, we have to stop and take a look at that.

And that's what the operating company presidents will be looking at as they go to the commissions and say, "Here's what the options are." And when they define those options in front of the commission, obviously the commissions are our bosses in many respects because we need that revenue to support the shareholders investment, we're going to do what they tell us to do.

So as we go forward, we'll make sure that we are putting those plants together plenty of time in advance with the commissions so there is a firm understanding to enable that regulatory recovery. From a national standpoint, it's very serious when you look at it.

The partially exposed category and the least exposed category, you get upwards to around 40% to 50% of the fleet in this country. And if you're looking at retiring this amount of generation in the 2014 to 2016 timeframe, that's very ominous in terms of our ability to keep our system operating the way it should, and make sure the economies operate the way they should and cost impacts are mitigated.

And that's something I think that we have to have in terms of a rational plan moving forward. So what is AEP doing at this point?

Obviously, I mentioned earlier, our plan for the old smaller coal fire units we did seasonal operations, our extended start-up program, where smaller units will not operate unless there is a critical need for them to operate and in fact if we're making margins off of our ability to operate those units. We'll transition them towards retirement.

You probably already know that we did file in Ohio for retirement of our 4&5 unit. And that's just case for us to figure out exactly what the issues are going to be.

Obviously undepreciated plant balances are. We want to make sure we continue to recover those.

But also you can't credibly; this is sort of a unique situation units four and five because it was already slated for retirement. But as we go forward with these other units, we need to be able to tell the Commission what the replacement's going to be, what the plan is for developing and retiring this generation.

So the regulatory plans for recovery are going to be extremely important. We will continue to evaluate the partially exposed units.

As Mike said earlier, we are heavily invested in the activity associated from our legislative front and from a EPA front, we have made our comments. Our Commissioners have commented on what the EPA is doing.

Trying to get some realm of reasonable enough associated with the timetable and targets. If we are successful in doing that, there will obviously be a much more balanced view going forward of our partially exposed units and that is what we are intending to do.

But we are not sitting by, waiting for that kind of result to occur, because interestingly enough we are long on coal capacity in the east, we know that. And we are going about the process of making sure that we are ready for the future.

So the ways we are doing at this point is we're adding non cold fire generation. Clean coal is something that we have obviously slated for in the future.

We haven't made any investments and we are not going to make any investments in the near term in new nuclear or cold fire capacity at this point other than Turk, we will finish up Turk. But we are looking at the possibility of starting our Dresden facility.

And we are also looking at new natural gas facilities on Brownfield sites. We already have permeating.

We already have the site, water and so forth. So it is going to be very economical to convert those is some respects.

We have moved away from re-powering, refueling those types of options because it really is suboptimal given the new technologies of natural gas fired capacity with quick start capability and with the ability to serve not only from a energy perspective, from a capacity perspective as well. So we will replace with new facilities.

And then renewables, you know that we did announce a new solar farm in Ohio. So we are moving on the solar front, but we will do that to the extent that we have requirements for those renewable mandates.

And we will certainly be concerned about the ultimate costs on our customers to make sure there is a balanced view of looking at those and the entire portfolio cost and the changes there. We also are working on new technologies, and Mike mentioned earlier we are busy with the Chinese and others, the Indians, the Canadians, the Australians, around the world trying to get support for the second phase of our carbon capture and storage project.

We intend on coal being a part of the picture, the energy mix of this country moving forward. And for us, I know invariably if we are on a panel where the coal guys that are on the panel, we have a much more balanced view of that because we do have to review what our customer requirements are and those needs are.

But we want to ensure that coal remains a large piece of the fuel mix of this country, because it is an indigenous resource that supports the vitality of the economies that we serve. Future storage technology and gridSMART activities.

We have four gridSMART pilots that are continuing to operate in Texas, Oklahoma, Ohio and Indiana; those are really providing lessons learned, not only for us but the commissions that are involved with those projects to understand what can actually be done at the customer end. We are dealing with much more system efficiencies as well, from inter-gradable bar control to community energy storage, those type of activities are going to be transparent to the customer.

And it'll probably make a lot of sense to do anyway as opposed to some of the issues where customers decide within their home. So we will continue that progress and that will be a part of our portfolio mix for the future.

And as we go forward, you will see that we are much more receptive. We are not assuming like we did 20 or 30 years ago what's the next central station generation?

What's the next investment to be made in our central station generation? We are going to make wise decisions about whether this generation should even continue to operate, whether we should continue to invest in it?

And then what the replacement capability is? And support the operating company Presidents as they make their decisions with the commissions.

So again I want to thank you for the time and I will turn it over to Susan Tomasky now who is going to talk about the next growth engine for AEP, the transmission play.

Good morning everyone. Terrific to be here this morning to be able to talk about AEP's transmission strategy.

2010 has been a year in which we have been able to put some meaningful points on the board with respect to our transmission strategy. And off course it is a year, as we talked to you in the past, it's a year in which we have worked very hard to build the regulatory platform required to grow this business at the pace that we intend to grow it.

I want to talk today as I have in the past about the progress we have made of the three legs of our transmission strategy. And I also want to share with you a little bit more information than perhaps we have in the past about some specifics around how that investment is going to unfold over the coming four or five years.

And what we can see in terms of earnings contribution. As you know, we have three areas we are pursuing aggressively in order to make this transmission strategy viable in the near term, the mid term and the longer term.

Texas moves forward aggressively. It is an operating utility company with a rate base.

And we have received CCN approval for one line. I will talk a little bit more about CREZ in a minute.

The Transco strategy also moved forward as we have a settlement in front of FERC and continue to plan investment in that area. I will update you a bit on some of our joint ventures.

And I also want to assure you that this is not the end of the story, we continue to work on new deals of the time. And I am very hopeful, although we have nothing to announce today that will have two very interesting deal to be talking to about very soon.

So let's talk about ETT. ETT is an operating utility company and has a rate base of $385 million and it's expected to grow every year significantly over the next several years.

By 2013, and that is the point at which the CREZ Projects come on, we should have a rate base of that company of $1.4 billion. The progress on CREZ, of course is critical to this and that is where we are moving pretty quickly.

ETT had the only unanimous settlement on the sighting of a line, and that settlement has been approved by the Texas Commission. That is the Clear Crossing to Dermott line, and its 95 miles for $160 million of investment.

Engineering work is going forward. We have three more lines that are, also as you can see on a schedule to get the sighting and the certificate work done.

And we do plan that we will have the CREZ lines done in the timeframe that we talked about. The PUCT continues to confirm their commitment to the need for the client.

And we continue to believe that we are operating in territories where sighting is very feasible and that we are going to produce the results that we said we would with respect to CREZ. And we have also identified another $1.6 billion of investment overtime through 2017.

These are opportunities that are now in the hands of ETT, transferred from our Texas operating company. Significant new projects that will work their way through the ERCOT approval process so that we think we have a plan that ETT will be $3 billion company by the year 2017.

If you look at our Transco strategy, again this is a very important part of AEP's transmission strategies in the near to mid term. This is exciting for us because it's a 100% AEP assessment.

It draws on opportunities within our footprint and has dual benefits for AEP. It has both the benefit of providing transmission growth and also an opportunity to access capital from different sources in order to be able to relieve some capital pressure from our operating companies.

And move forward with the transmission only investment strategy under FERC regulated rate. The key to that of course, is getting the FERC rate in place, and this is been something that we worked on a good part of this year.

And I am pleased to say that we now have the settlement that's pending in front of the FERC for approval under exactly the terms that we hoped that we would get. We were seeking to mirror the settlement terms that we had in place with respect to our wholesale customers in the east and west; and that's pretty much what we have a 11.49 return in the east in the PJM customers and 11.2 in STP.

That settlement has unanimous support on the ROE issues. The only significant outlier on the policy issues the Indiana Commission who continues to raise questions at the commission about whether or not Transco is a good idea.

Everyone else is in full support, we feel very comfortable on the record that FERC will support it. And we are going to continue to be working through Paul Chodak and our team in Indiana.

And we feel very comfortable that once we get in front of the Indiana Commission with our specific proposal, that they will see the benefits for Indiana and will be able to go forward. Our spending for this year, $50 million was more modest that we have hoped for this year.

But we are going to plan to make that up in the coming couple of years. What we have done is focus our investment in Ohio where we have an application pending but where there appears to be strong receptivity to the commission.

And in fact it is effectively the same rate effect on the pasture basis as we have under the Ohio tariff now. So understandably, Ohio has got plenty else to think about right now at the commission.

But we do believe that this is just a matter of time of getting it out of the door once the FERC settlement is confirmed. And of course, in Oklahoma and Michigan, we don't actually require regulatory approval for formation of these Transcos.

So we are able to move forward with those investments without going through regulatory structuring proceeding in those states. And in fact, that's where our focus will be in terms of our investment, has been in 2010 and will be in 2011.

2011 will be a year in which we will work to get our Transco filings done in our other states, and you'll see investment planned in those other states for the Transco in 2012. I want to talk a little bit also about the progress that we're making on our joint ventures, and I want to spend in particular a little bit of time with respect to PATH where I think that there is obviously a great deal of interest and a very important part of AEP's transmission strategy.

The PATH project, to remind you, is a $2.1 billion project. AEP's investment is about $700 million of that and we have an allowed return with incentives at FERC of 14.3%.

This is obviously an extremely ambitious project and one that will require us to navigate some significant challenges in the state commissions. They key to that and our ability to do that lies in the support that we have had and continue to have pretty strongly from PJM.

PJM, although they have in recent years moved the date around, they have confirmed consistently over the course of this year that there are very significant reliability issues both from a moving forward perspective and the capacity perspective in the year 2015. They have been quite emphatic about that.

Back in June, they sent us a letter. It's public.

It's on the PJM website that says, "Please do everything possible, make the investment to meet this 2015 date." In every discussion that they have had publicly since then, they have confirmed the importance of that date.

The affidavit in the filings that they have made, as we have reactivated the regulatory proceedings in the three states, continue to be consistent with that. We have re-filed in Virginia with strong support from PJM, and we have renewed the activity in both Virginia and Maryland where we continue to go forward.

PJM has indicated that our test is final with respect to PATH. They continue to do evaluations, because it just seems like that's what PJM does.

And it will be our job to translate PJM in these state proceedings so that they do understand how critical this is. But if you look at the affidavits that have been filed by PJM recently and look to coming Board action that we think will continue to do confirm it, I feel very good about our prospects to complete this process.

It is challenging to get through these regulatory proceedings and get this deal on the ground by 2015, but it's urgently needed, and we're going to do it. The second important step forward has been with respect to the Prairie Wind project.

This is a project that has been approved as a priority project by the Southwest Power Pool. It's a project where we're already beginning the engineering, beginning the siting process in the State of Kansas, and that too is another project that will get into service within the near term.

With respect to Tallgrass, which was another piece that we have been pursuing, the future of that project does rest on future deliberations in the Southwest Power Pool with respect to the voltage at which that will be built. That could well be a long-term process.

We are continuing to support the SPP in their deliberations on that issue. We do believe that as a technical matter, the right thing to do with respect to SPP is to continue to pursue an overlay at the 765 level.

But as I've told you in the past, we intended to be ready to build the kinds of projects that will be approved and we will continue to see either through PSO or our other utilities are going to see significant opportunities either through the Transco and other joint ventures with respect to SPP. The other point I want to make with respect to future projects is that the Pioneer project, which as I'm sure many of you know has been lingering for a while, is a project proposed by Duke.

It has been identified by myself as an important part of their RGO Study. This is not obviously a decision to bill, but an important step forward in understanding, as MISO goes forward, identifying the projects that they would like to see developed for purposes of wind integration of MISO and PJM.

The challenge of course for that project is that it's on the seams between MISO and PJM and the RGOS have not done a very good job of figuring out how to do that. I'm going to talk in a minute about the efforts that FERC is making in order to make the necessity of that a little more apparent to the RGOS and hopefully even to make it a little easier for them.

The last thing that you should watch is the results of our SMART Study. We understood the need for a significant analysis to underpin the development of a system to harvest the wind from the upper Midwest.

And we talked to other utilities in the area. We all agreed to support a comprehensive study.

We did that with the full participation of the RGOS, and we now have two phases of that study public. One are the design features, and the other is the cost benefit analysis.

It does show significant benefit to moving forward. The next phase will be commercialization of specific projects around smart grid, and that's something that we are actively working on with other partners.

So I want to talk a little bit about what all this capital investment means and how you can look at it and what to expect in the coming years. Obviously, our capital investment is subject to a number of variables.

It's subject to regulatory approvals. It's subject to RGO review in some cases.

But what I hope this slide does is illustrate for you how this investment builds up, what we feel comfortable putting in our base case and what will be the things that will determine our ability to realize those higher levels of investment and the higher levels of earning. So if you look at the blue down at the bottom, that is ETT, and the ETT investment that I've described is very much in line with what's been approved through CREZ that comes online in 2013.

And the rest of that growth are the additional projects, the $1.6 billion, that as I suggested will work its way through ERCOT over a period of time. If you look then next at the green, those are the JV projects, one which we have a fairly high level of confidence.

As I said, Prairie Wind is already approved. That's a smaller part of that green.

The other is PATH, an approved project, one for which we have a rate in place. The job there is to get it through the state and get it online by 2015.

When you then get to the grey, what you see is the Transco investment. And what we've done is to reflect very specific projections for the year 2011 and 2012, which as I mentioned is $160 million, $350 million respectively.

Assuming that we can move forward with the Transco in our other jurisdictions, we continue to see the opportunity for comparable investment. The Transco investment is investment to enhance and to extend the current transmission system.

There is great need across our system for transmission investment. We have a lot of old facilities.

I know you hear that from other utilities. But what the Transco does is give us the opportunity to direct capital specifically to this investment under the FERC formula rate.

And we believe that with the Transco companies up and running, we're going to be in a position to realize that investment. And as you see, it has the potential to be quite significant as you get to the post-2013 era.

And then the High Case box, which is the box that has the dotted line around it, really are the future investments. And we have not chosen to try to put too much around that in terms of dollars with any specificity.

But these include things like the projects that will come out of the SMART Study. They include future SPP development.

They include Pioneer and other projects, very much the things we're actively involved in and things we will continue to pursue with partners around the country. And I do emphasize that there continues to be a huge amount of excitement in this space.

This is way more like baseball than basketball, which is good, people like baseball. And it is something that requires us to move in steps.

Perhaps you don't understand when we attach so much significance to these steps, but they are very significant. PATH is very well poised.

The Transco opportunity is very well poised and I do believe you're going to see some pretty significant and very interesting announcements in the near future. I'd like to conclude by spending a couple of minutes talking about where regulatory policy is going.

We have talked a lot about the importance of regulatory change to our strategy even as we've been vigorous in pushing through projects within the regulatory frameworks that we currently have. Particularly as legislation appears not to be on the horizon in the immediate future, I want to make sure that you understand the importance of some of the regulatory progress that has been made, some of the policy evolution that's going to complement what we and others in the transmission sector are trying to accomplish, because 2010 really was a year in which a number of important things moved forward.

From our perspective, I think I could probably say maybe the single most important thing that happened was the approval of the cost allocation methodology in the Southwest Power Pool. That was important because it provided the basis for approval of priority projects that includes Prairie Wind as well as a project that we will be developing through our Oklahoma Transco primarily.

So this is a very significant step forward to have addressed this. It was supported by SPP on a consensus basis and importantly pointed to by FERC not only as something they were prepared to approve, but as a model for other regions.

So we are very excited about the progress that was made with respect to SPP and also, related to that, the approval of the priority projects that will serve as the basis for future development in that area. I also want to point your attention to the work that has been done in the Midwest ISO in looking more broadly at transmission needs.

This is something that has been very important to us for a long period of time. We believe that transmission planning has been tracked by a bright line test where the solution is to solve yesterday's reliability problem and that the vision required to think about reliability, congestion relief and the integration of resources has been a very difficult thing for the RGOS to embrace.

MISO has stepped out of that mould both with respect to the RGO Study and their identification of multi-value projects, and this is a really important step forward, and I think was important in feeding FERC initiative with respect to the NOPR. So I'll close by touching on that briefly.

What FERC is attempting to do is explore the limits of its authority, and I think it's quite clear that it intends to push as far as it can to facilitate precisely the kind of transmission development that AEP has been talking about for the last couple of years. They have proposed and asked for proposals on how to mandate the RTOs to move and to address seams issues, to deal with cost allocation more broadly both within the RTOs as well as on a seams basis, to require other RTOs beyond the ones who are attempting to explore multi-value projects to have them look at those as well.

So it's a very exciting step forward from that perspective. FERC also recognized that cost allocation and planning are part of the same puzzle, and they've also begun to ask the RTOs and they asked significant questions in this NOPR about what can be done to try to identify projects that serve this broad range of policy purposes.

These are very exciting steps forward. It is obviously a tricky ground for the FERC and not everybody loves it quite as much as we do.

But I will tell you they are passionate about it, and I believe that it has changed the scope of the policy debate and created momentum that we're going to do everything possible that we can to build on. So with that, I'm going to conclude my remarks and with pleasure turn it over to Brian Tierney who is going to talk to you about third quarter results and give you a financial update.

Thank you, Susan. Before we get started, we've held your attention for nearly two hours and are very grateful for that, but would like to reward people with a humanitarian break if we can go ahead and do that.

I think that might be in order at this time. We still have plenty of time to answer questions, go over third quarter results and forecast for 2011.

If we could be back here at 5:10 sharply, that'd be great. And we'll get started again at that time.

Okay, good morning, everyone, and thank you again for being here. I appreciate the time that you've put into this and the intention.

And thank you for your quick break in getting back in place to get going again. The topics that I am going to cover today are going to be quarterly and year-to-date earnings, guidance for 2011 with some detail on capital allocation and expenditures, an overview of AEP's dividend policy and record with management's recommendation for a dividend increase, an overview of AEP's liquidity and financing and a view of AEP's long-term earnings per share growth rate.

Let's start by looking on page 24 at the third quarter 2010 performance where AEP earned $552 million for the quarter or $1.15 per share versus $443 million or $0.93 per share in 2009. We have listed for you some of the detail on the right hand side of the slide, and let me go through some of the major reconciliations.

On the positive side, rate changes accounted for $0.10 per share or $74 million. Weather accounted for $0.18 per share or $131 million.

And this reflects the fact that this was the third hottest summer in the east part of AEP system and the fourth hottest summer in the west part of AEP system in the last 30 years. Off-system sales were positive at $0.06 per share or $42 million.

On the negative side of the ledger, firm wholesale margins were down $0.03 or $21 million. O&M net of offsets accounted for negative $0.02 per share or $12 million due to employee-related expenses in the third quarter.

And other utility operations net accounted for negative $0.09 per share or $83 million and were mostly related to the loss of the Cook accidental outage insurance policy. Turning to Slide 25, we'll take a look at the September year-to-date numbers where you'll see that year-to-date AEP is on $1.272 billion or $2.65 a share versus $1.124 billion or $2.49 a share for the year-to-date period in 2009.

At this time, we're abiding 2010 full year guidance to the range of $2.95 to $3.05, which is the narrowed midpoint range of the previously announced guidance of $2.80 to $3.20 per share. Overall, the themes that we are talking about here in the year-to-date period are much the same as they were in the quarterly period with the0 major positive comparisons, including rate changes which accounted for positive $0.25 a share or $175 million, weather which accounts for positive $0.29 per share or $202 million, as 2010 is on track to be the most extreme year in terms of heating degree days and cooling degree days combined for AEP in the last 30 years.

Off-system sales is positive $0.06 per share, all from the third quarter. Year-to-date O&M net of offsets is positive $0.05per share or $38 million.

Principle negative comparisons to last year's year-to-date numbers include share count effect of $0.16 per share, reflecting $479 million average shares outstanding versus $452 million last year, reflecting the dividend reinvestment program and the equity issuance of 2009; firm wholesale margins which accounted for negative $0.08 per share or $58 million due again to the loss of the wholesale contract customers; and other utility operations net being negative $0.032 per share or $275 million and reflects the loss of the Cook accidental outage insurance, higher interest expense, higher depreciation and amortization and higher other taxes for the year-to-date period. Many of you are interested in how if we're so far ahead for weather, and it's 265 for the year-to-date period.

We're guiding to the mid-point of the range. There are couple of offsets that have been reflected and that we've talked about as we gone throughout the year.

Clearly, retail load is not recovering as we had talked about, and that continues as we had forecast, and that continues to be the case as we make our way thorough the year. We're heading into the outage component of the generation season.

So O&M will be up versus last year. There certainly won't be a repeated positive income tax effect that we reflected last year.

So those are offsets to the balance of the year that you may want to factor in as look to the balance of the year. Let's turn to slide 26.

And we'll look at some of the normalized retail load trends that we have experienced as we've gone through the year. And we'll also start giving you some guidance into what the members look like for 2011.

The third quarter of 2010 residential, normalized loads were up 1.3%, and that brings the year-to-date number to 1.2%. We're forecasting a similar rate of recovery for 2011 in the residential retail sector.

You've heard from Joe and Venita earlier in the presentation about how commercial sales have continued to struggle as we worked our way through the year. The third quarter commercial sales were down 1.6%, bringing the year-to-date for 2010 to negative 0.4%, and we're forecasting a modest recovery of 0.3% in the 2011 period.

Looking at the bottom left hand side of the chart, you'll see that the industrial class, which was the hardest hit a year ago, has steadily recovered. The third quarter comparison to last year is up 6%, bringing the year-to-date up 4.8%, and we are forecasting continued recovery it the industrial sector of 3.6%.

We would give you a little bit of a color on some of the industrial sectors, which we've done in the past, and that I think you may be interested in. The top five industrial sectors which represent 59% of our industrial sales were up 5.8% and 3.7% for the quarter and year versus 2009 respectively.

In fact, for our top 10 industrial sectors, all of them were up for the quarter and the year. Notable among these are primary metals, our largest industrial class, which is up 9.6% and 3.5% for the quarter and year respectively; and the industrial mining class, excluding oil and gas mining, our fourth largest class, which was up 7.8% and 3.1% for the quarter and year respectively.

On the bottom right hand side of the chart, you'll see overall normalized retail sales for the quarter and year being up 0.8% and 0.7% respectively. And we're forecasting overall normalized load recovery of 1.7% for 2011.

We'll do a deeper drive on Page 27 on the 2011 earnings drivers. You've heard the management team say several times that we're forecasting low growth as the economy continues to struggle of our underlying utility business to be in the 2% to 4% range.

And we are forecasting 2011 earnings in the $3 to $3.20 per share, which is squarely in the midpoint of that range. We'll start with some of the reconciliation from the midpoint of this year's range to the midpoint of next year's range, and clearly we can't forecast positive weather that we've had this year since it's been such an extreme weather year to the positive for our sales.

And if we adjust for that, it's a negative $0.20 comparison to next year or $148 million. Non-utility and parent will represent negative $0.08 per share or $40 million and reflects lower anticipated earnings from the generation of marketing sector, the absence of a gain on the sale of intercontinental exchange shares, which occurred this year and won't be repeating next year, and the absence of some favorable tax true-ups in 2010 which also were not expected to be repeated next year.

We talked a little bit about and Joe talked to some degree about this, customer switching in Ohio, and he said that slight less than 5%, particularly in the commercial sector sales where for the first time we're seeing wholesale prices dip below the ESP prices in that sector. We continue to watch how switching occurs as we go through the balance of the year and are forecasting that to pick up somewhat next year to a total of about 14% of Columbus' and Southern's total overall sales.

That impact will have a negative $0.07 per share or $53 million in 2011. We believe that additional switching in both Columbus and Southern and Ohio Power will be negligible due to the fact that wholesale prices continue to remain above the ESP prices that we have there.

Other utility costs net are forecasted to be unfavorable by $0.06 per share and reflect about $0.02 per share of share count dilution and $0.06 per share of increased depreciation and taxes, partially offset by reduced interest expense. Off-system sales, net of sharing for next year, are forecast to account for a negative $0.01 compared to this year.

That would be $286 million in 2011 on volumes of 21,600 versus $293 million expected this year on volumes on 19,400 gigawatt-hours. We're anticipating natural gas prices to be about the same next year as they are this year in the $4.40 of MMBtu range and AEP/Dayton Hub prices to be very similar to this year's in the $38 to $40 of megawatt-hour range.

We're anticipating increased volumes due to some of the customers switching that we've experienced in lower forced and planned outages for next year. Transmission operations, which reflect earnings from our Transcos and transmission joint ventures, are expected to earn $23 million in 2011 versus $10 million in 2010 for a positive $0.02 per share comparison.

On the operations and maintenance expense side, we've talked to you about the discipline and effort that we've been putting into our cost cutting initiative, and we're starting to see that investment pay off in that O&M cost net of offsets will account for positive $0.04 per share next year or $131 million. You'll see in the detailed slides in the back that O&M increase is about $100 million from about $3.4 billion to about $3.5 billion overall.

But we are recovering an incremental $129 million in trackers and other rate revenue offsets, meaning that O&M net only actually decreased by $31 million. This decrease is after other increases in operating expenses, which means that the employee base is very focused on maintaining that O&M discipline.

Load recovery, which we discussed on the prior page, will account for positive $0.14 per share or $100 million and reflects the increase in total normalized load of 1.7%. Rate relief is expected to contribute positive $0.32 per share or $235 million in 2011.

Of this amount, AEP has already secured $158 million or 67%. Remember back during the height of our environmental CapEx program, we secured as much as $659 million in annual rate relief.

Given our reduced CapEx program and reluctance of regulators to pass on huge increases at this point, we believe that this amount of rate increase is appropriate and achievable. I'm going to stop for a moment and talk about some of the pool impacts that have been discussed a fair amount in the investment community of late.

At a high level, I think many of you are familiar with AEP's East generating for the high level, it allocates the capital and energy charges along with off-system sales among the East AEP generating companies. This agreement has been in place for the last 59 years and has served the customers and the companies of AEP's East system very well during all kinds of cycles, during periods of capacity and energy surplus, deficit, during business cycles that have been up and down and during extended planned outages.

It's allowed for smoothing of cost over time to the East operating companies. While this has served the company and the customers very well for the last 59 years, we regularly look at opportunities as to whether or not it's time to modify or terminate the pool in some future period.

As we do this, we're not just looking at today's capital or capacity in energy prices, we're looking at a whole number of factors that need to be taken into account, and we do this regularly. We look at potential environmental regulation, capacity retirements, RTO design, must run requirements, and in addition energy pricing and capacity pricing.

We have to give an opinion and form an idea of what all of these factors and the cost of them mean to the various customers and operating companies as we go forward. If, at the end of this current analysis that we're engaged in, it's determined and it does make sense to terminate or modify the agreement, we'll do so in a slow measured manner taking into account the interest of our customers, the companies, and the shareholders.

We're confident that we can do this, because we've been through this process before in the early 2000s, when we cut an arrangement that modified the pool significantly, as we were approaching an idea of corporate separation into a regulated and de-regulated company. At that time there was a long-term contract back from the surplus companies to the deficit companies in a manner that met everybody's needs, the customers and the companies had the issues that they needed resolved in terms of access to capacity, energy and other such, and off system sale, and the company had it's interest met in terms of it's earnings requirements during that period.

There's been a lot of questions about Ohio Power and the fact that it receives positive capacity payments from other deficit members of the pools. But it also shares with those members of the pool, its energy, and it shares its off system sales with those other companies.

If Ohio was on it's own for whatever reason, and this wouldn't happen quickly without everyone having some transparency into that issue, it could certainly sell its capacity and energy into the market. But it would also get to keep all of its off system sales.

How would this impact on Ohio? Again, we can't just look at today's pricing and energy, and decide if it's a good or bad thing for AEP Ohio.

Perhaps it's AEP Ohio or Ohio Power had been in that situation, it would have sold its capacity and energy forward, when energy prices were high. And I can assure you it certainly managed the risk of the capacity and energy in Ohio Power differently under that scenario than we would today.

In any event, there are many issues that need to be considered. These issues will be considered with our customers, the companies, regulators and our shareholders in mind.

It will be thoughtful and methodical in how we go about doing it. It will be transparent in public.

And we're confident that as much as we did in the early 2000, we'll be able to meet solutions for all of our stakeholders as we go about looking at any modification of the pool arrangement. Let's turn to Slide 28 and talk about capital allocation.

I wish I had started counting at the beginning of today's discussion, how many times members of this management team have used the word capital allocation or capital efficiency. I hope that those of you in the audience and those of you listening on the web understand that this management team gets it.

That we are a capital intensive company in a capital intensive industry, and we're acutely focused on where we spend our next $100 million, $50 million or in the example that Charles gave $6 million, as we go about thinking about where to put our capital to work. We get it, we' re focused on it, we know that that's what we need to do to be successful as a management team for the benefit of not only our shareholders, but our employees, who expect us to maintain the facility and have a sustainable employment for them.

For our customers, who expect they have reliable and affordable service over a long-period of time. For our shareholders, who expect an adequate return; and our bond holders, who expect to lend us money at reasonable and no rates for the foreseeable future.

We know this is the job that we're focused on. And I hope that you've gotten that sense.

With that in mind in the near future, this management team has looked at where we put our capital to work in the near future. And so we are putting some portion of capital to work, as Mike said at the beginning of this discussion for capital growth.

We want to put power money back into the business to provide service to our customers, because we have an obligation and the desire to serve them, but also because we want to grow earnings for our shareholders. And that's why we're increasing the capital budget by $150 million in 2011, and we're calling for a capital budget of 2012 of $2.9 billion.

We're also returning capital to our shareholders in the form of an increased dividend, which will be recommended to our Board of Directors for the fourth quarter of this year. It has always been a component of this company's culture and history that we return current period earnings to our shareholders.

And we intend to do that through the increase in the dividend, which will bring us into line with many of our piers, and will certainly be sustainable. And then we're also putting capital to work reducing risk on our balance sheet.

This year we have planned to put a $150 million to work, reducing pension liabilities on our balance sheet. And as we looked at the year's that went through, we actually increased that amount to $500 million for the year, brining our unfunded pension liabilities much lower.

We anticipate allocating additional $150 million for pension liabilities in 2011. Our focus is making a competitive return in the marketplace and we're certainly planning on managing the company for the long term.

We get capital allocation, we know it's our job; we're acutely focused on it. Let's take a look at some of the detail of that.

Turing to Slide 29, you'll see that in 2009 the company spent about $2.5 billion in CapEx, and in 2010 we anticipate spending about $2.2 billion. Previously when we talked about spending in 2011, we had talked about $2.5 billion and we're increasing that to about $2.6 billion, with incremental spending in transmission and new generation.

Some of which you heard Susan and Nick talk about. In 2012, we're planning on spending $2.9 billion in capital, with significantly more in the Transco's particularly Ohio, Michigan and Oklahoma.

And in our transmission JVs particularly PATH and Prairie Wind, as Susan just updated you on. The Transco and JV spend in 2011 is significant with the spend in 2012 really starts to produce some earnings growth from the transmission growth side of our story.

Let's take a look at liquidity and financing for the company, as we look ahead to 2011. First let's talk about the core credit facilities that underpin our liquidity position.

Both of these today are undrawn, they are two $1.5 billion credit facilities, the first of which was to come due in 2011. And we renewed in June of this year with lots of support from our banking partners significantly over scribed favorable terms and pricing for that credit facility.

And it was a smashing success to be able to get that in place nearly a year ahead of the expiration of that facility. We're going to be looking to do the same thing again with the facility that comes due in April of 2012, as we work our way through 2011.

And anticipate the pricing terms and support from our banking partners will be just as strong as it was in the first renewal. On the financing highlight side.

Our credit metrics are expected to remain solidly in the BBB to Baa2 range, with debt to total capital in the 55% to 59% range, and FFO to debt in the mid-to-high teens. We expect to access the capital markets in 2011 for a little bit greater than $1 billion, and that comprises maturities of about $620 million.

We expect to take advantage of the current low rate environment to have some possible redemptions. And we expect to excess the debt markets for some incremental debt as well to firm the transmission and new generation projects.

We expect net debt to increase by only about $50 million as we go through the year. Our cash flows are supportive of both our capital program and the dividend program that we discussed.

Turning to page 31, let's take a look at the dividend policy and recommendation. I know many of you know that in June of this year the company celebrated paying its four hundredth consecutive dividend.

In September, we announced the payment of our four hundred and first quarterly dividend, I think that should give you some sense that our Board of Directors and the culture of the company is dedicated to paying out a consistent portion of current period earnings in the form of dividend to shareholders. Management as we discussed a couple of times in this meeting will recommend an increase in the quarterly dividend by 9.5% in the fourth quarter, clearly subject to the approval of the Board of Directors, that will increase the quarterly dividend payment from $0.42 to $0.46 a share and the annual payment will go to a $1.84 a share.

Lets look at the right hand side of the page, here we have a chart for you. In assuming the dividend increase, the compound annualized growth rate for the dividend since 2004 is 4% which mirrors the compound annualized growth rate for earnings for the same period.

Rewarding shareholders through dividend increase is consistent with the earnings growth, has been a hallmark during the Mike Morris era at American Electric Power. American Electric Power is at the bottom end of the slide.

American Electric Power's stated dividend payout ratio remains in the 50% to 60% of earnings. And in 2011 earnings of $3.10, this increased dividend will put us at 59.4% of earnings and brings our payoff ratio in the line with many of our peers and reflects AEP's commitment to reward its shareholders with current period earnings.

Lets go to Slide 32 and we we'll take a look at AEP's long term earning per share growth rate and prospects. We have been consistent in our message, that during the recovering economy our traditional utility operation will return 2% to 4% earnings per share growth and certainly the mid-point of our guidance for 2011 at 310 is squarely within that range.

As we look to the period 2012 to 2014, we believe that we can put capital to work at about twice the rate of depreciation and earn returns in the 10.5% to 11% range. This period of our story is slow, steady growth within the means of our balance sheet.

Anticipated financings need to grow during this period are financed exclusively with cash flow from operations, the dividend reinvestment program and incremental debt and current debt ratings. But the period after 2014, we believe we can grow earnings per share at an average annual growth rate between 5% and 7%.

We can do this by continuing to invest in our underlying utility, while investing incremental capital at a relatively higher blended ROE's that are Transco's and transmission JV's allow for. We will not waiver in our focus on capital allocation.

We are going to continue to focus where can we earn higher ROE's and places where ROE's are lagging. I think you got a sense from listening to the operating company Presidents that they are acutely focused on getting those ROE's improved so we can continue to invest for the benefit of our customers and our shareholders, and that will be a key component of our growth strategy going forward.

In the end the higher end of our growth rate is going to be driven by earnings from our transmission story, which we expect to significant reduce our earnings growth rate. With that, I will turn it over to Mike Morris for some wrap up comments and then we will have some questions.

If we can turn to slide 33, pretty simple, pretty straight forward, we are pretty excited about where we are. We are pretty excited about where we have been.

I think you I had enough exposure to this growth, and I think you all know that many of them have held many jobs during extended periods of time which gives me some comfort. And I hope you some comfort that this is a well seasoned team.

We have been through a lot together, with a great deal of success and we are ready for what comes our way. Setting a target of three and a quarter for 2012 is where many of you already are, some a little higher, some a little lower, I think you know from our history we don't talk about things that we don't think are accomplishable.

So we feel comfortable about the future. This is a tremendous time to be in this industry.

And American Electric Power continue to lead and effect the outside impacts that we feel as we go forward. So with that, let's get started with questions and answers.

What if you could comment in some more depth about this study that you are doing of this eastern power pool? When the PJ and capacity market was created, you all chose to self supply now it seems like you are re-visiting the possibility (inaudible) figure your comments prior to perhaps participating in the capacity market.

And I was wondering what went into the initial decision, what's changing and perhaps influencing your considerations now? Can you give us a view on the changed economics and what the potential upsides might be?

I think it is pretty straight forward. If you think about the early capacity options by being a self supplying capacity player, it worked to a great advantage to our customers.

We also had an opportunity to take a bit of the over hang of our capacity in the eastern pool, into those very high capacity prices in the early PJM auctions which year-after-year-after-year went up. Our shareholders took great benefit from that and our customers did as well.

Today, there is a bit of a reversal going on. We think that it maybe better to review the pool to see if taking apart something that was put together in 1951 for the benefit of our investors and the customers to see if there is an advantage there for our customers as well as those who invest in the company.

It's not cleat that that's the case. I know again that much of this came up in the Virginia rate proceeding where they wanted us to do a report to them in early 2011, we'll do that.

And what Virginia will see when we make that filing as the pool has served them extremely well over a lot of years. Probably avoided building 4,000 MW of power that would have served Virginia customers.

And back then when, I mean take a look at Rockport, when Rockport was build, Kentucky wanted no part of it. We ended up building it in Indiana, that's fine.

And they took a power contract or something, but today Kentucky would love to have those jobs that property tax base in their state. We're seeing the same thing throughout the pool.

So what we've committed to do in the Virginia rate case settlement proposal that we talked about was take a look at that. I hope Brian made it crystal clear that that's a long and intricate process that will go forward only if we find benefit for everybody in the equation.

And by everybody I surely mean our shareholders as well as our customers. So the map is changed, the facts have changed.

There are some things that would be benefit to all of us. We don't recover everything in the pool today.

We don't recover the cost of environmental investments, we don't recover the cost of the additives to run the existing retrofitted fleets in the fuel recovery cost filing. A lot of that would be good for our investors as well as our customers we think going forward.

So there is plusses, there is minuses. But any one who thinks this will happen and net-net will take some belly-blow from it, just understand the way we think this thing will unfold as we go forward.

(Paul)?

Just a few quick questions. The GDP growth estimates for 2010-2011 that you guys have in your sales forecast, what are they?

And how sensitive are you guys to that? Secondly, the ABCO ROE in the appendix is 9%, yet I believe for 2011, you guys are very confident to get into double digits, there's been a lot of resistance in Virginia and West Virginia not exactly needy.

Just, what's going to drive that, if you could just elaborate a little bit more on that? And then finally, do you think the Columbus Southern, Ohio Power merger, it sounds like you guys saw opportunity there.

You've been running it as a single company, it sounds like as well. So I wasn't really clear what that would bring about, and if you just get a little more flavor on that?

Does it help you with the shopping, does it make rates higher? How would the rates change there if you were to do that what sort of timeframe are we talking about?

Because, I am as old as I am, I'll go from the back first. The concept on merging the two is positive and what we think too.

We have been running under a single company. This we think is just a better way over time to blend together the rate structure so that has a constructive impact on the potential shopping.

Not enough to make it as though it would seem to dampen shopping; And that we think is important for the regulars because I am sure the commission as they share with you yesterday, they are pretty pleased with what they've created. Today's market maybe an anomaly and may not be, it may be a longer term play.

Equally important, bringing the two companies together we think gives us the opportunity to address the SEET clearly in the tail end. I think 2009, as I have told you a million times will work out just fine.

2010 will be an open issue. We'll find an answer for 2010 as the year unfolds in early '11 and we're reviewing the performance of the oil companies.

By the 2011, 2012 review of 2011 there will be a moot point, because blending the companies together give returns on equity and that will fall well within the guidelines and the guidance's. So we see a couple of plusses.

And right now, it's just we've met with the customers; we've met with everybody you can meet with. There is no push back whatsoever.

The time is right to do that. So that's the logic behind that one.

GDP growth is slightly above consensus for national averages in the west part of our system and slightly below consensus for national average in the east part of our system as is unemployment. So unemployment drives a little bit higher in the east part of our system than it does in the west.

And so, we're about moderately above GDP in the west, and moderately below in the east part of our system. It's like 2% give or take.

So in the east, it's a little less than that and in the west a little stronger than that. And we don't think that's outside of what you're seeing the general macroeconomic focus.

In Appalachian Power, Charles and I and the Appalachian Power team had an opportunity to meet with Governor McDonald and his team last week. I would argue at the executive level the pressure on Appalachian Power Virginia is off.

We are clearly in a political seasonary, you'll continue to hear one of the House of Delegates who wants to become a stronger player in the politics banging on us, but I think the Governor's team and our team are working together very closely. West Virginia rate case moving along fine, we don't see any lumps.

Remember the logic behind Charles Patton going up there. He came from Houston Lighting & Power a lot of years of success and then came over with AEP to do our lobbying in Austin and did well at that.

AEP Texas had the largest rate increase that central southwest operating companies had ever experienced in the State of Texas because before he did the rate case, he met with everybody in the world that could have a meeting and explained to them exactly what they were doing, exactly why they were doing it, and set a standard for how you do rate cases, already underway at the encouragement of the Governor of Virginia doing the same thing. We've been out to every Kiwanis Club and every Chamber that you can talk to trying to let them understand, these are rate increases, most of them driven by environment rules out of Washington, which support the coal miners in the very region where we do business.

Yes, we know you don't like rate increases, but they also have a lot to do with your jobs in these regions, and I think you'll see some pressure come off of that, although will be a bit of political fodder as we go. That should allow for the returns on equity, Appalachian Power to get better in line.

What you see at AEP consolidated for Bob's Utility Group is an overall 10%+ return on the overall consolidated equity invested in Utilities. Some days some are plus to double-digits, some days single-digits.

As Stuart said, it took him three or four years to stairstep his up; SWEPCO has stairstepped up from a number of cases that we've gone through. So any point in time that any operating company should not overwhelm you, it's I think Nick made it when he said, it's the magnitude and the scale of AEP.

I don't like customers switching in Ohio, but $0.07 hit based on what we'll do with our own retail operation and other things that we'll do in 2011 as we look at the challenges in front of us. We can tolerate those kinds of things and serve the portfolio what we have.

I think other than the system agreement issue as a structural concern, I think that other big concern in 12 more than 11 as it pertains to a 325 aspiration is how the ESP negotiations will unfold. And at a high level, investors look at where market prices (propel), they look at where your rates are, they see some of your customers switching.

It sounds like you need rates to go up in Ohio, and yet it seems to me that the pressure would be down. So how do you marginize your needs with sort of the minutia of how this process is going to go forward, that there is a mutually beneficial solution for customers.

So don't forget the major reason you see customers shipping is that the price to beat if you will is the G rate price. So there is maybe some tightening in the (G rate) that we'll see, but you can make capital investments in the Transco as Susan had already mentioned.

And you can also see some serious capital that has been invested in AEP Ohio on the Distribution side with the Smart Grid program, and others will continue to make those investments. So going in with the belief that rates go down in the ESP to avoid shopping is probably a concept that won't materialize in what we file.

And what we file will ultimately I think yield itself to a settlement over time. And so you won't see the same kinds of increases you may have seen in the last couple of years for that shopping piece on the G rate.

But you'll see some increases without question in the t and the d and other activities that go into an overall ESP filing.

Just a quick question to clarify your capital plan. You said you plan to access $1 billion in the capital market.

670 of that's debt, the other?

620 is maturities. We're going to take advantage of some additional low rates that we have available to us today to have some incremental redemptions and then we are going to issue some new debt as well.

Okay, so it's all debt.

All debt, with the exception of the dividend reinvestment program which is going to continue to contribute about $150 million here.

Right in front of you. Pauley, right next to him.

Also on the CapEx side, to be clear, when would you expect to start seeing the ramp-up from environmental-related CapEx in your portfolio? How much of any of that is in that 11, 12 number?

If not, what should we be thinking about incrementally for environmental CapEx?

Well, I think as you looked at the 5% to7% earnings cycle that we spoke to in the 2012 and beyond or the 2014 to beyond cycle, it's the basic business itself. the U.S economy recovering, associated with the capital investment ultimately yielding share price returns on the transmission play.

Plus, the environmental investments that will be made on the fleet that Nick broke down for you in a pretty granular way. So it will be that kind of a timeline before, A) You can physically get the work done, and B) You can incorporate it into some type of a rate adjustment mechanism going forward.

So that's when you'll start to see those impacts as you go forward.

So, 14 and beyond?

Right.

And some magnitude? Would you like to share with us?

It all depends how crazy our friends in Washington are. I know you know this; I know you all know this.

There is no more technically confident generation coal fleet utility in the country, no offence to my friend, my good friend David Ratcliffe, and we'll deploy all the technology we can as cost-effectively as we can. And we are going to continue to run those plants no matter what the environmental requirements become.

And as you know, under Utility law, anything that you are doing to comply with Federal Legislation is recoverable at the state level. It may take time, and that's why we think it'll be more like the 2014 period and beyond.

But it would be difficult for me to tell you. We think that's $1 billion on retrofitting or $800 million on retrofitting because I don't know what they'll do with mercury, I really don't know what they'll do with coal ash, I don't know what they'll do with the transport rule.

The way they stand today, they're illogical and they cannot sustain the way that they've been put forward in preliminary activities that we've all commented on.

Just two questions on the financials if you would please. The first one is on the cash flow from the appendix.

There's a $650 million swing in working capital in 2011 versus 2010. Can you talk about those drivers?

And the second question is higher debt balances but lower interest expenses '11 versus 2010. Just some of those drivers there?

It may be obvious but can you talk about it please?

The '09-'10 driver, a lot of that was driven by the one-time severance payments that we made of about $300 million, and there's also some incremental deferred fuel, as well it's a contributor to that. And we're obviously not anticipating severance-type payments next year as well and anticipate being about cash flow neutral for next year.

So, two things '09 to '10, the incremental pension costs of $350 million, the severance payments of about $300 million, that's '09 to '10, and then next year we're anticipating not having those clearly and being about cash flow neutral for the year.

Just on the EPA issues, can you just walk through how you guys see legislation or action changing that would preclude the EPA from (acting) and the idea that money doesn't get spent till 2014 when there's rules written and clearly in place, both today and rules written in 2005 and 2008? You had visibility to compliance, kind of how that fits together?

Senator Rockefeller's two-year slowdown on carbon was passable before they all went home. Senator Reid chose not to bring it up because he knew it was passable.

And he's made a promise to Senator Rockefeller to come up in the Lame Duck Session. That may or may not happen.

It will certainly happen early next year when the whole process gets slowed down for some period of time. But just slowing it down doesn't stop those implementations as well as other activities that are going on, clearly under the current purview of the clea Iraq.

And so again, its difficult for me to say exactly what years they'll come to play and when the capital will need to be invested and how then that'll roll through the rate play. What we try to show you in the long term post 2014 is, we think that's when those investments will have matured as far as impacts on the earnings strength of the company going forward.

As you know, we actually made some investments based on our NSR settlement. We've made some investments based on what we thought the care and camera rules were back when they were the law of the land, and obviously a law that was reversed.

So in some jurisdictions, remember where we're making these capital investments. We're making them in Applachian cold country.

Its cold jobs, it property taxes for power plants that don't get shut down. There's a lot of benefits that the economies of the states were making those investments.

And frequently, when there's headroom in the rates, and Lord knows, you heard that from the operating company folks. We'll go forward and make some of those investments, because we'll be encouraged to do that to get ahead of the cycle.

Remember, when you look at the retrofitting for SOx or NOx under the Clear Air Act as it stands today, we did a lot of that stuff at 250, 300 kW. Folks who are doing it now and still catching up are 500, 600 kW.

So, we'll be an early mover when we can, as long as the regulator understands why we're doing it and sees the benefit of what we're doing in that process.

Where do you guys see (inaudible) it's going to happen to marry together all the pay policy? It sounds like part of your goals is to repackage.

How do you see that looking?

Well, there's a move for Democrats in the House from coal country to suggest that EPA is the same thing that the state of Texas has suggested. To Venita's point, we were movers behind that activity in Texas; we're movers behind the activity in the House.

So it's a congressman from Virginia, a congressman from Ohio and a congressman from West Virginia, all on the Democratic side who will bring forward some application for our friends at the EPA to look at a consolidated study of the aggregate impact of what they're doing. And I think there'll be pretty good legs for that kind of legislation going forward.

I am sure the new Republicans, no matter how many they are, will be eager to have that kind of an activity. Again, understand what we're trying to do; we're trying to put rationality in this.

We've are not, just say no to utility, although we may have been in the past. That's not where we are in the future.

Where we are in the future is, let's make the air better, let's make the capital investments better, let's keep (king) coal and play. And most importantly, let's keep these massive capital investments that we've made on behalf of our customers viable for the near term, mid term and long term.

And we just think that'll happen.

Brian, when you talked about these different periods of time and the different growth rates in 2012 to 2014, I think I heard you list a number of sources of capital, but I don't think you talked about external equity in that 2012 to 2014 period. Did I hear that right, and should we be thinking of sort of beyond 2014?

2014 and beyond is the earliest you might be, based off these plants be back in the market.

Certainly through the 2014 period we have no plans to issue any equity. Certainly consistent with the CapEx and growth rates that we described.

You know, I think when you start to look out towards the latter part of the decade, if this Transmission business takes off, other opportunities for us to either access the equity market, do a partial spin of that business which is how we have organized it as a Transmission holding company, or access other forms of capital to bring it in to drive that growth, that would be a story that we'd come out, we'd talk to you about, you'd hear about, and you'd understand why we would be accessing that incremental equity, what our plans with it were and how it fit into the growth story of the company. But certainly in the period 2012, 2011 to 2014 we have no plans to issue equity and believe that the CapEx and growth that we have described can be funded with incremental debt and with the dividend re-investment program that we have.

As you know, it is a pretty strong dividend re-investment program. It yields $150 plus million a year.

A lot of smart shareholders see the benefit of just rolling over and staying in the stack.

If I may, just on another subject. You are talking about the $0.07 of margin erosion in Ohio in 2011.

I'm guessing some of that is the full year impact of what you saw mainly in the second half of what you are seeing in the second half of 2010. How much is embedded in the 2010, based on the same kind of measure?

I think it would be silly for us to tell you how much load we think we are going to lose, so we won't do that. But rest assured, we have built the impact of what we think the market prices are, our competitive position in Ohio, particularly the Columbus Southern and any impacts that that will have when we talk about being in the range that we gave you for 2011 on the earnings profile of $3 a share to $3.20 a share.

We've baked all of that in. And as you might imagine we have been aggressive about the potential impact.

And I think that tells you directionally about as much as we would like to share on that. I don't want to energize any of my competitors.

Yes Mike, an industry wide question. We are in a period of really high leverage at kind of the state financial level, even in federal government; below-trend GDP, high unemployment at a time when rate pressures, albeit with shale gas, fuel costs may be down a bit.

But renewable costs are up, causing rate pressure. Environmental costs will likely cause some rate pressure.

Can you point us to a period of time historically where that same circle of events happened, how it played out for the broad sector and what's likely different this time around?

Think of Jimmy Carter and think of the earlier Reagan years, as President Reagan corrected some of the incredible malaise that the country went through with 20%-plus inflation, 20%-plus cost of capital. And we saw a huge impact on the macroeconomics of this country then without the export machine working.

So when you ask me what's the difference from the then to now, a couple of things. I was sharing this morning with some folks over breakfast.

You look back today and you now know that the economic impact is an event that began really in 2007, not really recognizable then, because it was small. In 2008, it became pretty serious.

The minute the Lehmann thing tumbled, everything unraveled in a hurry. We never saw the 2008 impact until last half of the 12 month in 2008 because of the export machine.

So coming out of this one, we think that that growth in Asia is going to allow many of our large industrials to the points that Paul made, the points that Venita made, the points that Charles made. Think about the shale gas play moving across the country.

What you're seeing at U.S. Steel tubular for shale play in the Greater Southwest, you'll see repeated throughout our service territory.

We are in the midst of shale country everywhere that we are. So I think there'll be some different things going on as the economy recovers and most of it having to do with the potential for export.

If you look at August exports, September exports, but for plains, which as you know are very, very volatile, it's been up again. So the world continues to grow and U.S.

will continue to satisfy that growth. So jobs will come back over time.

We're all sitting on massive amounts of capital. What we don't know is what it costs to hire somebody.

And I would argue and I would hope that as we get more balance in the United States Senate, which is essential for this country's wellbeing, and I wouldn't want 60 Republicans anymore than I like 60 Democrats. I think you'd be much better to understand what the Senate was created to do, which was to slow down ideas that looked great when you first think about them, but when you pass a 1,200 page health care bill with 67, 87 regulations yet to come, with seven or eight new agencies yet to be created, and will learn about it as we go, how could it be sillier than that.

So I think that balance will help all of this as we go forward. In corporate America, from my exposure to business roundtable association, manufacturers and others, it's eager to go forward and grow.

Bob made the mention of $0.60 equivalent gallon to put some electric vehicles on the road. You've read a big story today about (inaudible) cost going on it, that's technology.

So I think this will be a different recovery. Slow, but when it comes it will be strong, it will be sustainable, and it will have a lot to do with the export engine that we call the american industrial complex.

I want to talk on one other issue. It's a very important issue.

It's come up, and Ally and I had a chance to talk about it in the hallway before we came in here. And that's there is some concern that the deferred fuel contracts are getting a little outlandish.

We agree with that. Then there is some concern that over time there will be an inability to recover those.

We surely don't agree with that. I think Allen answered that question yesterday.

I got asked more than one. And I think you've put it to rest, but just think about the politics of this.

So you bought all this coal from Ohio and it was expensive and a lot of Ohioans got the benefit of all of that. And now you're trying to recover the cost of all that benefit from the same Ohioans that had the potential benefit of it by the economy going forward in Ohio.

I mean the politics are out of balance when you think about that. The chance of that happening is remote.

Now, what I learned years ago in law school was that it's never, never in any answer. But the chance of that is hugely remote.

So I'd like to at least put a point on that. Steve?

A question on Ohio on the coal plants. So I guess Duke had said that they might sell their plants.

And I'm just curious kind of how would have any interest in any more of those plants, and how many of those plants are ones that might need to be shut down are on that high risk group of plants. And how are the companies, given the co-ownership figuring out, making decisions on these plants?

Well, those are questions that I can't answer other than the one about our interest level is very low. As you heard Nick say, our next best option is finishing the Dresden station, and we're taking a hard look at that four our 2011 cycle.

That's a combined cycle plant. If you think about $4 gas and 6,000 heat rate, that's going to be a pretty nice plant that will run well.

We see our gas plants in the Eastern footprint being called on a lot more than coal. So I'll let Jim explain to you the value proposition that he thinks that he has.

But there's a lot of smart money buying generation facilities in this country today. So I'm sure if he puts it up for auction, there'll be some who'll come in to buy it.

We'll take a look at them, just to see if there's anything we're missing in any region of the state that we think may make sense, but it would take quite a deal to energize us to get involved in that activity.

You may have partially answered this question from some of your prior comments, but can you give us a feel of the politics in Ohio. For a state that the gubernatorial election doesn't seem to have utilities is the frontline issue.

There is a very overt type divisiveness from the companies in the state as far as where the support is. I think your previous comment may be alluded to that.

Some of the issues under the surface that we should be aware of, but we're messing?

It appears as though a very decent fellow who got dealt a very interesting deck of cards did his best to manage his way through Ohio. There is the potential that Ohioans who are very conservative who have been voting now for about 15 or 16 days may well put Governor Strickland back in the saddle just simply saying he is a really decent fellow who did as much as he could rectify Ohio.

But he is hitting a storm of you and your colleagues lost 400,000 jobs during the last four years. I don't think we can tolerate any more of that.

So there is high potential that John Kasich who is a very charismatic, very energetic individual may well win that race. Our team has been as bipartisan as you can be in those events.

I think John Kasich would be a great governor if that's the way it turns out. And for us, it will work out well no matter how what happens.

Utilities aren't top of the list. There are other issues that are very much top of the list issues for people in Ohio, most importantly jobs.

Who is a better economic developer than the utility? So you may have seen a couple of weeks ago, we announced a contract to take the commitment for our solar requirements if and only if the solar manufacturing facility is built in Ohio, bringing in 600 jobs.

That goes back to the point that was raised back who gets a lot of upward pressure, things like renewables. We're only going to do that inside of an envelop that makes sense.

Again, if you look at the gigawatt-hours that AEP Ohio sells, buying a few gigawatt-hours of solar is not going to move the needle a great deal. We feel comfortable with the way the politics will unfold.

It looks quite likely that we'll have Senator Voinovich, a very staunch Republican, replaced by Portman, a very staunch Republican. Sherrod Brown is a very dear friend of Susan's and mine and other members of our management team.

I think we're in great shape politically in Ohio. I am not concerned about it at all.

You can imagine if in fact we go forward with the Dresden plant, it will be 700 or 800 jobs early on, people swamping around at that station in Ohio. There'll be a lot of happy politicians to see more people working.

So utilities and executive officers need to find a way to get along, and they will find a way to get along. That's one of the things that's essential for how we do our business.

A quick question on the guidance. The 2012 number, does that include the same level of shopping as the '11 number?

And then also, have you baked in any SEET impact in either of the two years?

So again, that's more granularity than we're really prepared to share. I can assure you that we think shopping will go on.

When we look at the 2014 and beyond, the cost of the energy in the marketplace, we expect it will begin to drift up, not continue to drift down. If you're a shale producer and you've already spent your money, you're happy to put fuel in the market at what it brings today.

But there is a time when you pause and you say, "Hey look at these $4 rates, I'm just not coming." When you start getting north of $4, our coal plants kick back in.

That pushes the market price throughout the whole area up some as shale gas prices increase that reduces the shopping potential. If you blend those two companies together and over time you blend their rate structures together, that puts downward pressure on the cost at the Columbus Southern commercial marketplace, and I think you'll see some positive effects of that.

As far as heat is concerned, we see it as a zero earnings impact issue. And eventually, again blending the companies together, SEET is a yesterday challenge rather than a today challenge.

I'd like to thank the team for being as prepared as they were. Chuck, you, and the IR group deserve a great deal of credit.

Third quarter has been outstanding. We think it makes for a very strong 2010.

We're comfortable about our 2011 forecast, 2012 and beyond. We couldn't be more bullish about the potential upside for investing in American Electric Power.

And you'll make your own decisions in that regard. Thanks for being here with us.