American Electric Power Company Inc (NYSE:AEP)
February 10, 2012 8:00 am ET
Nicholas K. Akins - Chief Executive Officer, President and Director
Brian X. Tierney - Chief Financial Officer and Executive Vice President
Unknown Executive -
Lisa Barton - Executive Vice President of AEP Transmission
Robert P. Powers - Chief Operating Officer and Executive Vice President
Joseph Hamrock - President of Columbus Southern Power Company, President of Ohio Power Company, Chief Operating Officer of Columbus Southern Power Company and Chief Operating Officer of Ohio Power Company
Mark C. McCullough - Executive Vice President of Generation
Andrew Levi - Caris & Company, Inc., Research Division
Nicholas K. Akins
Good morning, everyone. Thank you, all, for taking the time to visit with us today at AEP. We're very much focused on a few things, I think, you're going to find enlightening in the presentation today. Brian and I will certainly be talking about in detail the issues we see with the company, going forward. And certainly, we're working on several important aspects that you obviously need to be made aware of.
First of all, I want to talk about generally what you're going to hear today. We have significant commitment to growth. Execution is going to be something that you hear about, and as well, the transmission business is very much becoming a part of our portfolio mix for the future in terms of growth.
And I want to leave you with a notion: AEP is much more than coal and AEP is much more than Ohio. And I think we really have to consider some of the positives of the rest of our system as well when we go through this, so you're going to see a more balanced approach to that discussion. Since we've talked about the discount in our share price being focused on EPA and Ohio, it's very much the other way around, too. We need to think about that from an execution and clarity perspective.
So you're going to hear throughout this entire presentation what we are talking to our entire management team and all of our employees. The last year, I had discussions with many of you and heard resoundingly the issues that AEP needs to work on to enhance shareholder value. There are issues around clarity, execution, line of sight and discipline, you're going to hear that over and over in this presentation. And we're very much taking a fine-toothed comb in going over our entire business to focus on those particular areas. So let me see if this thing works here.
First of all, I'd like to say -- I think you can read that yourself, I'm not going to read it to you. But we're obviously going to observe the Safe Harbor provisions that we have there.
Okay, so here's what you're going to hear today. The earnings range that we're talking about for 2012 will be in the range of $3.05 to $3.25 per share, with a midpoint of $3.15. Earnings growth will be in the range of 4% to 6%, supported by the rate base growth of the regulated companies. We're going to show you that the regulated side of our business, even after corporate separation, is going to be pretty dramatically still regulated, and we want to have that discussion as well. The company's asset profile is going to continue, like I said, to be 86% regulated, which is very different from the 25% we heard before. We're just definitely going to be regulated as we go forward.
The dividend is supported by the regulated operations, you're going to see that clearly as well. What we've worked on for the past few years, what Brian and his team have definitely worked on, is making this company much stronger from a financial profile perspective. The credit metrics, the ongoing fundamentals of this business are getting better every day.
Corporate separation filings at FERC have been made today, about 6 different filings, which I'll go into a little bit detail later, but it all, it is all about that execution. And since we got corporate separation from Ohio approved, that was the precursor for us to make these additional filings. So they have been made today and the game is on.
The transition period, execution is key. You're going to see step-by-step processes that we have to go through over the next 2 years to have corporate separation completed by the first quarter of '13. We want to make sure that we're able to move forward in a very, very positive way not only with Ohio but with the other 3 members of the eastern pool, so you'll hear more about that as well.
The competitive generation profile, I really am excited by that business because we will be able to put together, I believe, a very good ongoing business operation not just about unregulated generation but about wholesale operations, retail operations, hedging activities associated with the available generation we're going to have available. It's really, I believe, it's going to be a positive thing.
So when we go through this, and I know we've typically talked about a combination of the metrics in terms of financials for the company, we're going to split it up in terms of the regulated piece of the business and the competitive piece of the business. I typically don't call it unregulated, it's more competitive because the hedging practices and so forth, I'm still making the argument that it is primarily FERC-based regulated and those types of things that remain regulated in some fashion. So we're going to go through that as well.
Just a little bit of history. AEP changed its path particularly when Mike Morris joined the company. We refocused on the regulated business. And in terms of that refocus, it's certainly has reached that point of discipline of the operating companies to focus on not only their return on equity but also making sure that we are able to do the things, make the investments that the commissions and customers and those various states would want us to make. And they've done an incredible job, as you're going to find out. But as you look at the years associated there, you will see that we've actually performed very well compared to the utility index and the S&P 500. When you look at that over the 1-year, 3-year, 6-year and 8-year period, AEP has been very credible in terms of providing consistent dividends, dividend growth and earnings growth during that period of time. We also have put in a strong balance sheet and put in that solid foundation by moving to the operating company model that provides the focus and execution for us to deliver in the future.
So the operating company model that I mentioned earlier, I think you're going to see further refinement in that model, going forward. Our operating companies have focused on certainly the distribution operations and also the capital allocation that's occurring in that area. They're going to really be focused on capital allocation at the operating company level because it's important to make sure that we are doing the right things by each of the jurisdictions that we serve, and many of them want different things. They may want a different resource portfolio; they may want different things in terms of investment between generation, distribution and transmission. So those modifications are going to be key. The pool operations that we're talking about, particularly in relation to the eastern pool, that is going be very positive for that line of sight with the regulators in the eastern footprint. They will be able to make their decisions about the resource portfolio of the future that makes sense for them. And I think that's something, a step we needed to make anyway so that we could adequately value each line of those businesses.
The financial controls in place to manage the balance have been put, manage the balance sheet and growth opportunities have been put in place. We have a strong financial platform and we're focused on capital discipline, as you'll see when we go through the capital plan a little bit later on.
So this is all about clarity and we have gone through the process of systematically addressing those issues that may have defined risk in our share value. As we've gone through the process, you know we've been upfront on the mercury MACT issue, on the environmental issues as well, to really get across the notion that we have to have some measure, some reasonable, rational measure to actually address the issues of system security, reliability, those types of things as we go forward in this transition. We embrace that transition. What we need to make sure of is there's a rational transition that makes sense.
So we have, we expect the MATS rule to be published in mid-February, probably effective in mid-April. And filings with the RTOs have been made. We have filed with PJM, we'll soon file with Southwest Power Pool. Those filings demonstrate the plans that the RTOs need to look at in terms of retirements of generation to ensure that we maintain system reliability and get our hall pass for that 1-year or 2-year extension. So those things are critical. We're probably one of the first out with our plans. Our plans have been consistent during this entire period and we have been very aggressive about ensuring that there is RTO review of these plans. And then, we'll take them to the EPA and have those discussions as well.
We also settled the Arkansas litigation associated with the Turk plant. That was an overhang for us in terms of our ability to move forward with that construction project. We're well over 80% complete now with the project. It's great that Venita McCellon-Allen, the President of SWEPCO, can actually focus on other things besides the legal ramifications of what she's doing with the Turk station, and that's important for us. We now can really focus on the construction, get it completed and get the cases done in the various jurisdictions of SWEPCO to ensure that we get recovery of that facility.
Securitization opportunities have occurred, as you well know, in Texas. We also are working on securitization in Ohio, particularly, of deferred fuel there. And there's a bill that's been filed in West Virginia associated with securitization of that fuel balance as well. So we're getting clarification around securitizing those deferred fuel balances to provide a further reinforcement of our balance sheet.
The PUC approval, I know you've heard a lot about Ohio and we'll get into that a little bit later on, but I think one of the critical things you have to look at is this: Getting the corporate separation filing was the most important step for us because you can argue about the economics of all the other things that we're dealing with around discounting capacity and all those types of things, but this was a critical step for us. To get the corporate separation approved via -- it's a net book value transfer that would occur, and it's important for us to do that because it's a precursor of every other step that we're taking. And as we put together the businesses associated with our competitive operations, it's important for us to have that done. Ohio is complete, we are filing with FERC and moving with that process and the negotiations and discussions with the various other jurisdictions involved.
Okay. So as we execute through 2012 to '14, we are going to optimize the operating company ROEs and invest in the regulated utility platform. And the regulated utility platform is robust for us particularly when you talk about the environmental spend, the Transco spend, those types of activities and the ordinary block-and-tackle reinforcement of the grid. So those are activities that are key for us. The issue for us is to make sure that we advance the notion of getting us concurrent recovery as we can, and you will see a little bit later on that we've made some progress in that regard as well.
Repositioning the generation resource portfolio is key for us because we have to start thinking about resources in a broader sense. And as we look toward making sure that we not only deal with the issues associated with HAPs MACT and EPA and all the other rules that are coming down the pipe but also what the market is doing. And as you know, we just brought on Dresden generation by 550 megawatts in natural gas capacity. We'll continue to move in that direction as we retire these subcritical 200-megawatt units. So as we go through that process, it will be a repositioning of that business, going forward.
We'll also refocus the transmission business, which we've already started. I know I've had discussions with you all before about this, but we are repositioning that business to focus on near-term, easier top projects. And I say easier because the long-term lead-time projects that was large interstate transmission that traverse several states are slower-moving projects, and it became abundantly clear that we weren't moving quickly enough in relation to our transmission earnings potential. So you'll see in a little bit later on a discussion about that.
The robust competitive business that we're going to talk about, and again, I think of it in a broader sense. We'll separate the AEP Ohio and generation, replace the system tool, and then we'll transition to Ohio to market, as a result. So the current stipulation has us moving the market by 2015, with the discounted generation during the period of time that opens up for '12, '13 and '14. Still, a discussion about what that is and what it means, but we hope to get clarification of that here pretty soon particularly after they delayed implementation of their January order.
Okay. So this is really an important slide because it shows you, and I've heard a lot about, "Your company is moving to a hybrid utility, 25% unregulated and 75% regulated." That's not the case. We have actually taken the balance sheet of 2011 and looked at it from a post-corporate-separation perspective in 2013 and we anticipate the regulated course of the business to be 86%. And of the 14%, 4% is River Operations. And then from a 10% perspective, I'm going to get into the hedging practices associated with that, so I still have arguments about that piece of the business as well.
We are a regulated utility. We're comfortable being a regulated utility, but we are pursuing these 2 paths in parallel, and then as we move forward with the competitive companies, we'll make a determination as to whether that is appropriate for our business or not. And I think we'll certainly be looking at that process in the next couple of years.
Okay, so let's drill down on the regulated business. Here, We're going to continue that operating company focus, and it really is about strengthening those relationships and also making sure that our ROEs are improved by concurrent recovery and adjusting to those things that we know that the commissions are focused on. It's different by different areas. I've heard several times the notion that AEP is complicated, you're in 11 jurisdictions, hard to understand, but it really isn't that hard to understand because, if you really focus on each one of those companies and in an individual sense, many of the issues are the same. It's just the request and the discussion are different based upon the geographic footprint involved and the notions that the various commissions have and what customers want. So we really want to focus on that, strengthen that line of sight so they can see the decisions that are made based or upon what is needed for those particular jurisdictions.
So the east pool replacement obviously is the big key to that to help clarify the east. They will operate more like the western pool where capacity is made available. But the capacity is owned by the various jurisdictions. And then, they'll have a clear line of sight on the recovery related to those assets and then also be an energy pool, a 3-member energy pool actually, after the corporate separation.
The other issue we're working on is developing Transcos in the various jurisdictions, both jurisdictional Transcos that we enhance the ROE but also allows us to make more financially able investments, as we go forward. And I think the Transcos have actually worked very well for us. We see that as a positive, going forward, as well. We still have filings in some of the jurisdictions, and in many of the jurisdictions we already have those approvals. And obviously, focusing on the prudency and the reliability, financial discipline and capital efficiency. Those are major areas, and our operating company presidents are going be very focused on that, as they are today. But what they are doing is capital allocation and the planning and strategy around how to move their ROEs up in a very credible fashion.
So on the right side, I want to show you the strides that have been made so far. When you look at 2008, we only had about 20% of these improved recovery mechanisms, like writers, formula-based rates, those types of thing. Well, today, that's up to 48% so that enables us to really focus on those activities that the commission wants. And usually, you can get a writer for specific areas that the commission would like to see addressed. And that, those strides are huge in terms of minimizing the amount of volatility we see in the ROEs of the various jurisdictions. So we'll continue to work on that as well.
So this is probably one of my favorite slides. We've had a lot of discussion about this slide internally. This is really a key of showing diversity is a strength for AEP. Many people have said, as I've said previously, that we're complicated, but this is really a strength because various things occur in various jurisdictions in their own different timelines, and when you add them all up together, it winds up being pretty decent. And I think, I sort of characterize this slide like an equalizer, going back to my music background. But if you think of an equalizer with the different frequencies going up and down but it still winds up being good music in the end. And that's really what we're after here. And when you look at the areas of the, of ones that have less than their authorized ROE, those are the areas we're really focusing on to improve. And as we all know, Ohio Power is likely to come down some during the year. APCo, we expect the be over 9% for 2012, so it's going to come up as well. And then, a I&M has a couple of cases that are filed in Michigan. There's a case there that is still on file and then there's a settlement that, in one of the jurisdictions, as well. So and the settlement actually is in Michigan, and then in Indiana, the case is on file.
So it is important for us to be able to minimize the variations. And when you look back at that previous slide of the areas around the rate mechanisms being improved, that sort of defines the minimum threshold, and then we can minimize the moving back and forth of the curves in the various jurisdictions. So look for this as we go forward. And Texas is showing high because of securitization, and PSO had some very favorable weather during the year. So there's not just diversity within the commissions and how you deal with it, there's diversity in terms of weather and many other aspects of the business that we have in those various jurisdictions.
So on this slide, I want to show you just the solid investments that are being made. When you look at 2012 on a regulated capital spending perspective, this slide shows a distinction of the large block-and-tackle fundamental system reliability spend, most of that will show up in the yellow portion, and usually, you'll get recovery of those types of expenses. And when you look at reliability spend, when you look at even environmental spend, on the environmental front, the green portion, we've never had this allowance for environmental that was acquired from a regulatory standpoint. So you put all those together, along with the nuclear side, you see life cycle management, there is legislation that supports the recovery with quip of nuclear life cycle management as well as new generation and environmental and those stage, so it's very positive. When you look at this entire graph, it winds up being a very solid spend-and-recover plan.
Add the Transcos to that and you see the growth side of things, and Transcos have their own mechanism for recovery as well. So this, in total, when you look at the $2.9 billion, and keep in mind, this is separated from the competitive spend, so our total capital budget is going to be $3.1 billion, $2.9 billion of it is in this regulated piece of the business. But the depreciation on the regulated side is about $1.1 billion a year so anything in excess of that will provide growth for the company, going forward.
So in the fleet repositioning, we're estimating now that it'll be around $5 billion to $6 billion for the EPA-related investments associated with generation. That has been adjusted a little bit because we did get a , one positive outcome out of the EPA rules and that was around a particular matter. One of the things that we had talked about previously was this notion that we were having to move from 99.6% efficiency to 99.8% efficiency and it was a cost of $600 million to $700 million. Well, the EPA did resolve that issue by only going to filterable in particular as opposed to condensable and filterable. So that helped us, it took about $600 million out of the capital plan. So that's been very positive for us.
When you look at the 2,600 megawatts of retiring old, less-efficient regulated plants, that 2,600, it doesn't include Ohio portion because we're not counting that as the regulated piece, so that 6,000 megawatts we talked about earlier, I just wanted to rationalize that. We've Big Sandy out because Big Sandy will continue and then the remaining portion will be Ohio. And then, you have the 2,600 megawatts retired generation.
So for the new capacity, we're adding Dresden, as I mentioned earlier, and Turk obviously is going to get completed, but we still have concerns about the timing associated with the EPA requirements. They tried to address it, I think, at least moderately, so in terms of allowing the additional year associated with the extensions for generation, more of a -- it's not a blanket extension but at least it involves the states so it should be more credible in terms of getting the additional year. The year beyond that is probably more of an issue for us. We have to go through, essentially, administrative order type procedure and there's a lot of questions whether that leaves the generators open for any litigation. So we really have to get that resolved.
We're going to test that process. We're going to see that, if we file our plans with the RTOs, get the results of not only the RTO evaluation -- and I believe it's a 6-month period, they're going through the, going through that analysis. And then, we'll know, in combination with everyone else with their filed plans with the RTOs, what the impact is from a reliability standpoint. We'll immediately take that to the EPA and focus on how does this fit within the framework that you've provided.
We will continue working on legislation associated with the EPA rules. We support the Manchin-Coats bill and we'll continue to support it. The union support that bill, as well. And I think it's better for us because it provides more flexibility and more of a broad approval for the extensions for reliability so we'll continue to work on that in parallel, as well. But we would like to see the process within the EPA worked out to where we could advance and make the plans. We can't wait until the day that we're actually violating the rules. To think about making investments, we have to do it well ahead of time and that's why these rules and plans need to go in very quickly.
So when you look at the balance of the CapEx, it's pretty balanced by the operating companies. We really have filed for pre-approvals for Big Sandy, Rockport and Flint Creek, so those approvals are going in for those reliability additions as well. We want to have as much interaction as we possibly can with the various commissions so that there's full understanding of the options available. Whether it's natural gas or coal or nothing, we need to know that. And there's been credible discussions already with the commissions before we file these particular plans. And then, the dialogue can begin and we can assure cost recovery associated with these investments.
Another of my favorite subjects is transmission. AEP has been very focused on transmission development, as you know. I really believe transmission needs to be seen as a resource for the future. And too many times, transmission is only seen as an extension cord to renewables, it's more than that. It's about grid optimization. It's about providing efficiencies of the entire system that we operate. And when you look at projects like that, there are so many that can be done. And when we looked at the potential for, and we look at other transmission systems, we decided, Well, the transmission system we'd really like to own and invest in is our own because we have the largest transmission system in this country. And we also have probably the largest need in terms of rehabilitation of existing transmission and also a development of transmission from our 765 kV system, so we really see that as a very positive for our business, going forward.
Unlike previous presentations where we were dealing with long-term-type projects, it was very difficult to project out the earnings potential of transmission. Everyone wondered, "Well, okay, when, it's great to talk about the project, but when are the earnings going to happen?" And our transmission organization has been refocused on developing those short-term projects and real projects through the Transco development and specific joint ventures associated with smaller, less-lead-time, more -- less-risky projects, going forward. And I think this graph that we're showing you, the earnings associated with transmission and the projects that we show in terms of capital, are all real. They're there, we're executing on them and you can expect the earnings associated with those transmission projects to be delivered.
So I show in this graph it sort of tapers off in '14 and '15. It only tapers off because that's the projects that, at this point, are real. We fully expect transmission to continue to increase at this, at a pretty rapid rate, but we want to make sure that we only show you the projects we actually know of. And then there's other joint-venture projects that are in discussions, as you might suspect, because AEP is a great partner, people recognize AEP is a great partner. Those products will constantly be added on as they become more real to us, so you can expect more movement in the transmission space and we'll be aggressive at that.
Okay, so from a capital recovery perspective, when you look at the plant, property and equipment, the capital deployed thus far, $32 billion, we use that as the base, this shows you the incremental capital that's being invested by year, and it's on a cumulative basis. So if you look at '15, $8.4 billion, you take $8.4 billion over $32 billion and you come out cumulative about 6%. So the earnings capability associated with this added asset investment reduce the upper end of that guidance range. Obviously, our ability to achieve that is going to be based, in large part, on making sure we're making the right investments, but then secondly, ensuring that we minimize the regulatory lag. So we will be very focused on that. And that really does support the earnings capability and the dividend quality of the company, going forward.
Something else I want you to see in that is the delineation of the various incremental capital investments we're making in the different business units. You'll see that transmission is picking up quite considerably, and then we continue make investments obviously in the operating companies themselves. But this really shows you that we're refocusing that investment to ensure that we are optimizing at those areas where we can get more concurrent recovery, where we can get the ROE expectation that's required. So this is a very positive slide, I hope you see it that way. But the real key here is: Investment leads to earning. And we want to make sure that we're investing in the right things and getting quality recovery, as a result, in a timely fashion.
Let's move on to the competitive side of things. So as I mentioned earlier, we filed all 6 cases today relative to the corporate separation. Those cases, we hope to get completed, we've asked for completion of that by first quarter of '13. Those cases are 203 and 205 cases: 203 to effect corporate separation, 205 case is associated with the rates and the regulatory jurisdictions involved with that. So of those cases, you can see the list of them: corporate separation by Ohio, transfer of the Amos units and Mitchell facilities to APCo and Kentucky.
One of the areas we're looking at and having discussions with those various commissions are the ability to move the actual unit participations over to those companies. We are presently paying capacity payments to the Ohio companies, and once corporate separation occurs, we'll take that portion and move it over into rates of the APCo and Kentucky utilities. So we want to make sure that we're able to do that, a lot of quality discussions going on at this point. I believe that they are very focused on owning their own resources. And we believe that transaction will be one that's neutral for the company and then also one that's being positive for the various operating companies to take on this capacity.
For the approval of the Standard Service Offer contract between AEP, that really will define there will be a linkage during the transition period for the companies to satisfy the Ohio load that hasn't switched.
And then, the approval of the 3-company-member pool; the bridge agreements for, to provide for the FRR obligations and the hedging transactions that would be transferred to the members of the 3 operating members; and also, the approval of the APCo merger with Wheeling, or Wheeling into APCo, more appropriately said.
This next chart is Chuck's favorite and it really does show, in a very, very good fashion, the timeline for the activities that are going to occur. Like I said, it's a great opportunity to, for these 3 companies to take on this capacity. when you look at the transition from first quarter 2013 to 2015, we will have agreements in place, as I said, for the transfer of Mitchell/Amos. The bridge agreement is the one that we would deal with, with the FRR and hedging and trading book that would be allocated out to the operating companies, as well. That's here in that temporary phase.
And then, the excess energy after the SSO will be available to the competitive market. We will have transactions with the Standard Service Offer customers that are, that have not switched. We'll supply their needs from a capacity and energy standpoint. And then also, we'll continue to recover fuel during that transition period.
As we move to market post May 2015, then you might have just a single 3-member pool. A lot like it operates in the Western, our Western operations where capacity is dedicated to the operating companies. There are opportunities for capacity to be exchanged on a contractual basis but also primarily in the energy pool so that pool would remain in place with the other parties involved in the regulated utilities. All the capacity and energy is going to be available to the market, and I'll talk a little bit later about how we see that shaping out. And then, the Standard Service Offer for the remaining customers in Ohio will be subject to the auction that would occur, so basically, they would be going to market at that point.
So it really does provide us a plan to execute on. I think you'll see step by step as we're making progress here. That'll take the risk out and also move us toward a more definitive period of understanding what the earnings capability of the company and of that particular business is going to be in the future.
So moving onto the Generation Resources themselves in the competitive footprint. As we've talked to you about it before, we wind up with about 14,000 megawatts of generation. We're going to retire about 2,000 megawatts, that's the green area. The yellow is the transferred portions of Amos and Mitchell to the other 3-member pool, and that leaves us with about almost 9,000 megawatts of generation that's in the competitive market. This is where we've talked about before. We are going about the process of putting that business together with our wholesale trading, with our wholesale activities associated with third-party contracts, FERC-based contracts, and we're really focused on hedging that as we go forward. And I'll talk a little bit later about the retail effort associated with that, and we see that as the hedging activity, as well.
But the capacity mix actually turns out to be pretty decent. We will only wind up with fully controlled units, coal units, that are well within the economic market. And if you look at the coal conversion price today, it'd be about $23 per megawatt hour. Well, if you were to address that, if you take the retired units which are the higher-cost coal units, that number would come down and it'd still be fitting pretty well in the competitive market. So we wind up with a really good fleet of generation on the coal side. And then also, we're bringing gas-fired generation on as we speak with Dresden and others, so we wind up with over 1/3 from a natural gas standpoint. We're also that 16% new -- I mean, excuse me, the 19% steamed, that would be Muskingum River 5 where we would refuel that unit to natural gas.
So it really turns out to be a very, very competitive mix, going forward, and one that we really can attach other parts of the business to and make it very, very positive, going forward.
This slide really shows you the difference in nature of the competitive spend associated with that. It's very different to have to invest in units that have an obligation to serve as opposed to optimization against the market. That optimization against the market is going to enable us to really take advantage of minimizing the capital spend and making sure it's efficient against the market that we see. So already, you've seen the reduction that I've talked about earlier associated with the EPA rules in a particular matter adjustment that they made. That's by and large most of this. And then we also will be operating in terms of a foreign [ph], it comes from a 5 and 6 a little differently from an operational perspective to meet the EPA requirements.
But the big, big takeaway from this, if you look over on the right side: You're spending about $15 per kW on the ongoing CapEx. That's lower than the regulated side, but it is that way because you are able to optimize against the market, as opposed to deal with that obligation and serve where everything has to be ready to meet the demand. So we'll -- it will be a very different world for our generation that's separated, but it'll be a very disciplined approach and you'll see changes in our organizational structure and so forth to really match up to that kind of environment that we have to be involved with.
So getting to the hedging strategy associated with that available capacity and energy. We will have capacity sales, it will be made through the PJM RPM auctions; also, energy sales that will be used to optimize with contracts with munis, co-ops and so forth. We really believe that, that will be a big positive for us because we have great relationships with munis and co-ops in our territories.
Also, the acquisition that's pending. It's in the Hart-Scott-Rodino period now, but we announced an acquisition of BlueStar Energy. We really did that because we weren't so concerned about the number of customers BlueStar had. What we were really focused on was the systems that were in place. They have very, very good systems to accommodate retail operations, and for us, to go to a scale of an excess of 1 million customers and beyond, those systems are already set up to do that. They're also licensed in several of the areas that we're involved with and we want to make sure we're continuing to expand within those areas that we understand.
We participate already in auctions in Maryland and other places in the eastern part of the footprint. We also participate in auctions to the west of us. And MISO, well, they have operations in Chicago and other parts of the eastern footprint, Maryland and so forth, New Jersey, even into New York. And we really see that as the potential for a hedge of that generation in those areas. So I want to make sure that everyone understands we're not trying to start a national player of retail. It really is being used as a tool in those areas that we understand to focus on the development and hedging activities surrounding that generation.
The other aspect that BlueStar brings is they have a DSM, demand-side management, company. It's located in California, but demand-side management services are important to provide to customers. And that's the growth of this business. When you put it together with the generation, with the wholesale trading, the retail operation, it can be a very credible shop to really focus on providing a platform of services for customers. They are typically high margin. So and as we look at, one of the emphasis we place is technologies of the future, we have a window in those technologies. As we have invested in the BrainWare assets and so forth, we have an advisory board seat on that. We -- it really gives us a seat to look at new technologies that are occurring and I see that platform developing from that perspective.
So we're going to grow that business, make it a credible concern, going forward, and then we'll make a decision whether it makes sense for our regulated footprint. If we can convince you, that it's presenting the kind of margins and quality of earnings associated with it on an ongoing basis, then we'll move forward with it. But we really have to go through this 2- to 3-year period and fully understand the ramifications of that business, going forward.
So you can expect hedging levels in the 70% to 80% range. And as I've talked about earlier, we have done an initial analysis to see what the makeup of that hedging would be, and that's what's demonstrated in the graph there, the various parts. And then, a small portion remains unhedged, but we may want that to continue to participate in the markets, as a result.
So I'll leave you with a summary of the discussion that I've had with you before Brian takes over.
We believe the regulated companies offer that 6% growth in net PP&E through 2015. The operating company model is going to play a very big role in that, along with the improved recovery mechanisms. The regulated fleet transformation will occur and you'll see step by step what we're going through in the next 2 years. And the efficient allocation of capital is going be critical for us during that process. And Brian is going to be going in to the capital spend and show you that, how it's layered in, and you'll see that we've been very disciplined in that approach, making sure that we adhere to the credit metrics that we want to maintain and ensure that we are providing that consistent deliverable earnings potential.
Corporate separation is going to be a big deal for us. We need to get through that, and we will, step by step, and you will see those steps taken and we'll report on those in the following quarters as we go along.
The competitive operations, we'll certainly let you know of the effects of that as we go forward. And we believe that, that business put together, will be very credible, will have the earnings potential that really makes a lot of sense for this company going forward.
So again, overall, we still believe it supports the 4% to 6% growth rate. If, and I think, probably initially during this transition period, you have to think about it as we go through, it could migrate to the lower end of that 4% to 6% but gradually pick up during the years, but it will depend on a lot of things. One is, how the market comes back associated in particular with natural gas activities. I think you probably saw Chesapeake is shutting in some more dry gas, so we may see our natural gas prices pick up and that will help with the off-system sales portion of what we're talking about.
And then, the economy itself. As we get closer to the presidential election, you may see, and we're seeing, our industrials pick up. We're about at 95% of pre-2007 levels already from an industrial standpoint. So the industrials come back. The longer they show sustainability in coming back, you will start to see that commercial part of our business come back. And that will really be an opportunity for us particularly with the rates that we've been working on in the past few years to reposition this company, going forward. It can be a very positive for us
So there is a light at the end of that tunnel but, and we are intent on getting there.
So again, thank you very much. And Brian, I'll turn it over to you.
Brian X. Tierney
Thank you, Nick, and good morning, everybody. This morning, I'd like to take a quick look back at 2011 performance and review what some of the big key business indicators were. We'll look forward to 2012 and I'll take you through what some of the key sensitivities to our earnings guidance are in 2012. We'll review the 2012 to 2014 financing plan. We'll take a look at the Ohio Power recapitalization of that business and take a quick look into what the generation business might look like. We'll look at, finally, we'll look at the company's dividend policy and the earnings per share growth rate.
So looking at that, quickly, at 2011 ongoing earnings results. You'll see that, for the year, the company made $1.504 billion in ongoing earnings with $3.12 a share versus $1.451 billion or $3.03 a share for 2010. Negatively impacting the year-on-year results were customer switching in Ohio, which was negative $0.14, and the effects of the Ohio POLR remand, which was negative $0.10.
O&M, net of offsets, accounted for negative $0.09 per share and was largely attributed to the Ohio orders relating to the partnership with Ohio and higher storm and restoration costs. Although AEP had a very hot weather in its western service territories in 2011, weather accounted for negative $0.07 per share by comparison to 2011. And normalized retail margins due to price and customer mix variances accounted for negative $0.05 per share.
On the positive side, the ongoing portion of the interest income from its Texas capacity auction proceeding accounted for positive $0.05 per share. Off-system sales, net of sharing, accounted for positive $0.06 per share. Other net, which includes the lower effective tax rate in 2011 versus 2010 due in large part to the closing out of the 2001 to 2008 tax returns, as well as certain regulatory disallowances in the year as well. Finally, rate relief for multiple jurisdictions accounted for a positive comparison of $0.25 per share.
For the year, the ongoing earnings exceeded the midpoint of our original guidance of $3 and -- of $3 to $3.20 per share. In addition to the clarity that Nick mentioned and the outputs in our stock price, the dividend allowed for a total shareholder return of greater than 20% in 2011.
Let's take a look at some of the normalized retail load trends. And this slide will cover 2 things: It will cover what the normalized load trends were in 2011, and then we'll get in some insights into what we're looking at for 2012.
First, let's look at 2011. You will notice that, overall, normalized retail load trends were up 2% and they were led by growth in industrial sales. In the top left-hand side, you'll see that headwinds in our east regulated base impacted residential normalized sales and was offset to some degree by growth in our western service territories. AEP residential for the fourth quarter was up 0.3%, and for the year, it was up 0.4%.
On the commercial side, you will see that progress in our western service territories was not enough to overcome lags in our eastern regulated utilities in our Ohio service territories where load was commercial. Load was down 1% in 2011 in the fourth quarter and, overall, down 0.3% for the year.
Industrial sales continue to be a strong point for us in 2011. You'll see that, in the fourth quarter, industrial sales were up 1%, and for the year, it was up 4.1%.
For the fourth quarter of last year, our measures of unemployment and GDP in our western service territories were equal to or better than national average and our eastern service territories were worse than our national average. In our eastern service territories, unemployment was 0.2% higher than the national average and GDP was 0.1% worse than the national average.
Let's quickly take a look at what this means for 2012. And I'll give you some sensitivities in this as well. In 2012, we expect the trend of east and west mix to continue as our eastern service territories are projected to have slightly lower GDP and slightly higher unemployment rates than the U.S., but this will be somewhat offset by our western service territories, which we expect to grow nearly 1% faster than the U.S. average. As a result, we're expecting modest load growth of 1.4% overall in 2012, with average GDP growth in our service territory expected to be between 2% and 3% depending on which part of the service territory you're looking at. We're expecting residential sales to be essentially flat year-on-year, basically up 0.3%. The commercial sector, which has been lagging the other classes for the last 3 years now, we're expecting a modest pickup in 2012 of 1.1%, with the regulated west classes expected to have the strongest gains of 2.5% in the Ohio and east loads essentially flat.
Industrial sales are expected to grow by 2.2% during the year, fueled by our oil and natural gas sectors, particularly those located around the Utica, Marcellus and Eagle Ford Shales. Natural gas liquids processing, pipeline capacity expansions and associated chemical plant operations present the greatest load opportunities in these liquids-rich shale plays. We've seen a number of these types of capacity additions, particularly in our Appalachian Power and Wheeling Power service territories located within the Marcellus Shale. We're anticipating continued strength in industrial sales and some modest growth in the residential sales will unleash some pent-up consumer demand and allow commercial sales improve in 2012.
Let's take a quick look at the very important to us, industrial sectors. You'll see that on this slide, the 5 sectors that are represented are the largest industrial sectors that we have, and they represent 60% of our overall industrial sales. Primary metals was up 14% for the year, and a large customer returned during the year that contributed a lot to that rebound in sales in primary metals. Without that one customer coming back, however, we still would've been up 4.3% on the year. Many economists are predicting a recovery in the automotive sector, and our primary metals sector contributes significantly to growth in automotive. So we expect to see some uplift there during the year as well. Chemicals was another story, it was up 0.7% for the year, but it struggled mightily in the fourth quarter of 2011, it was down 7.1%. Chemicals make up 40% of all U.S. exports, so we'll be watching what happens to the strength of the dollar to see if that's a further drag on the chemical exports in the chemical industry in the United States. But on the other hand, some economists are predicting an uptick in fertilizer, and that can further help chemical manufacturing. Two categories, petroleum and coal products and mining were both up 4.6% for the year, and we expect continued strength in those sectors in 2012. Paper manufacturing unfortunately was down slightly for the quarter and year. And we don't expect a significant recovery in paper for the year.
Finally, the uptick in industrial sales could also lead to some opportunities for our River Operations division in 2012 as a rebound in moving dry bulk commodities is occurring, and an increase in expected export opportunities to the Gulf could help as well.
Let's take a look at detailed earnings guidance for 2012. Again, our earnings guidance range for 2012 is $3.05 a share to $3.25 a share. The midpoint being $3.15, and what I'll reconcile with last year's actual results of $3.12 to the midpoint of the guidance of $3.15. I'm sure most of you have already figured out that this less than 1% growth is less than the 4% to 6% earnings growth that Nick discussed earlier today. As you'll see, we're having some significant challenges in 2012 related to the Ohio transition to market, as well as some difficulty in the power pricing environment. We expect those challenges to be transitory, and in the meantime, we'll manage costs, continue to grow other segments of our business and execute on the transition plan in Ohio so we can put these challenges behind us. This slide captures at a high level the changes in the earnings drivers again from last year. We'll work our way from left to right across the graph.
Other utility costs are unfavorable year-on-year $0.24 per share. The most significant items here included a higher effective tax rate that creates an unfavorable effect of $0.15 a share, due in large part to the benefit realized in 2011 related to prior period income tax returns. Also higher depreciation and amortization expense of $0.12 reflects construction and changing depreciation rates in Virginia. The remaining items tend to net close to 0 for other utility cost net. The effective additional Ohio switching, resulted in an unfavorable year-on-year variance of $157 million or $0.21 per share. We have made assumptions about the timing and levels of switching in this number regarding both the December 14 and the January 23 Ohio orders. On average, a 1% shopping -- change in shopping rates at the RPM prices results in a $0.01 per share change in earning on an annual basis. As we always do, the forecast assumes normal weather and the unfavorable $0.15 per share reflects the absence of the strong weather that we had experienced in 2011, even though that strong weather was less than what it was in 2010.
Off-system sales margins net are down year-on-year -- are forecast to be down year-over-year by $93 million or $0.12 a share. This decline reflects the reduction in the gross capacity payments due to lower RPM rates in 2012 and the effect of lower margins resulting from prices than what were experienced in 2011. We're assuming around-the-clock prices of near $30 a megawatt hour on the balance of the year annual basis, shaped of course, depending on the season and the balance of the year gas prices we're anticipating to be around $3 an MMBtu, also shaped on a seasonal basis. Off-system sales do see some uplift reflecting the increase in volumes available for sale due to higher switching loads. On average, a 1 megawatt -- $1-megawatt change in forward prices for energy will equate to a change of about $0.03 per share on an annual basis.
The annualization of the effect of the Ohio POLR remand order from 2011 also has a year-on-year drag of $83 -- $83 million or $0.11 per share. The nonutility parent segment together is unfavorable $7 million or $0.01 per share. This was a slight decrease -- this slight decrease in earnings reflects results from generation and marketing, also reflecting the effective lower prices, partially offset by lower costs at the parent and improvement at the AEP River Operations.
On the positive side, let's look at transmission operations. This line represents earnings from our transmission JVs and activities supported at our Transcos. Year-on-year earnings are expected to be up $15 million or $0.02 per share in 2012. Normalized retail margins are expected to add $112 million or $0.15 per share to 2012's results and reflects the load growth that I detailed on Slide 25. On average, a 0.1% change in load represents a $0.01 per share change in earnings on an annual basis. Utility O&M net of offsets is favorable $200 million or $0.27 per share, due in part to the incremental spending in 2011 related to storm activity and additional physical work that we performed on our assets late in 2011. Most importantly, the management team is committed to matching our spending with expected revenues. This discipline is evident by the commitment to controlling costs year in and year out. On average, a 1% change in O&M that does not have earnings offsets will result in a $0.04 per share change in earnings on an annual basis.
Finally, we expect rate relief to add $0.43 per share year-over-year due to significant rate activity across the AEP system. Of this amount, 84% has been approved and only 16% remains pending. Given that, I think you'll see that we've been fairly middle-of-the-road in many of our assumptions that I've laid out for you, we haven't assumed power prices are on fire. We haven't assumed that they continue to climb. We've made reasonable assumptions about Ohio switching and load growth, and we firmly believe that we'll be able to grow our earnings year-on-year from the $3.12 of last year to the midpoint of guide guidance of $3.15 that we just laid out.
Let's take a look at the 2012 to 2014 financing plan. As Nick took you through the competitive businesses and the regulated businesses, he didn't put together overall what the CapEx would be, and that's what I'm doing on the left-hand side of the slide here. 2012, we're anticipating CapEx to be about $3.1 billion and in 2013 and '14, we're anticipating that amount to grow to between $3.5 billion and $3.7 billion in response to some of the environmental programs that we're going to be building to be in compliance with, as well as some of the increase spend at the Transcos that we're going to experience.
Let's take a look at how we're going to fund that, and the main theme that you're going to see here is that a combination of securitizations and the DRIP, in addition to what the cash flows that we're able to get from ongoing earnings in our operations will allow us to fund the CapEx program on the left-hand side of the page without having to have incremental equity issued at the company.
Looking at 2012, you'll see that we're able to benefit from the securitization opportunity in Texas to the tune of about $800 million. We expect cash flows from operations and the securitization together to be about $4.6 billion, and our capital investing and dividend programs to sum to about $4.4 billion, leaving the company with a net surplus of cash for the year of about $225 million. For financing activities, we're expecting to raise $100 million through our dividend reinvestment program, issuances of long-term debt excluding securitization to be about $800 million and many of you know that last week at our SWEPCO subsidiary, we issued a 10-year note for $275 million at a yield of about 3.6%. And the balance of that activity is about $525 million that we need to do for the year, consisting possibly of a senior note at APCo, a few PRCBs refinancing and funding it for the transmission either at the parent level or at the transmission holding company level. In overall cash flow, the proceeds from the Texas capacity auction proceedings will be used to reduce debt to the tune of about $300 million, have incremental pension contributions to the tune of about $200 million and fund our capital program to the tune of about $300 million. At the end of 2012, we expect our debt to total capital ratio to improve slightly.
Let's take a quick look at 2013, where we expect to benefit from the securitization of Ohio deferred fuel and regulatory assets to the tune of $875 million. As you might be aware, Ohio recently passed legislation signed by the governor in December that allows for the securitization of fuel and regulatory assets. We expect cash flow from operations to be near $3.7 billion as our tax situation begins to turn around. And combined with the Ohio securitization, we expect total cash available to be up about $4.6 billion. With CapEx investing and dividends totaling about $4.7 billion, we will need approximately $140 million in cash. When combined with the DRIP and net retirements versus issuances of about 0, our financing needs are met. We also have an opportunity to securitize about $350 million in deferred fuel cost in the Virginia ENEC, if Virginia passes legislation that's recently been filed to support that securitization effort.
In 2014, our free cash flow after dividends will be approximately negative $800 million, financed with $100 million from the DRIP and net debt increases of $700 million. In 2013 and '14, most of the debt financing activity involves restructuring and maturing debt in Ohio, as well as debt maturities and the capital program at I&M and the debt maturity at TNC. Over the 3-year period, 2012 to 2014 between the DRIP and retained earnings, we expect to increase equity about $2.1 billion. Between securitizations and nonsecuritization in debt, we plan to add about $2.2 billion in debt to the balance sheet. So the balance sheet is strong, over this period, it will remain strong, except for the DRIP, we will not have to issue new equity. And we are committed to the capital discipline as a company and we desire to allocate discretionary capital as efficiently as possible.
Let's take a look at the Ohio Power recapitalization. We've talked to you before about this. Bond holders are obviously very interested in how we are going to go about recapitalizing the company, and it's been our intent and I'm going to show you how we're going to do it to treat our bondholders fairly and make sure that they're not hurt as we go through this capitalization.
We'll start with what debt is on the balance sheet of AEP Ohio at the end of 2011. It was about $4.1 billion, and that consists of 2 components, about $3.5 billion in senior notes and about $600 million in PCRBs. Of that amount, about $1.1 billion matures in 2012 and 2013, and $475 million matures within 1 year of corporate separation, leaving us with $2.446 billion. For the amounts that mature in 2012 and 2013, we plan to refinance those with interim bank lines for the 12 to 18 months, and put in place permanent financing at the parent and/or Genco level after separation. So what that leaves us with is, again, that $2.46 billion. Of that, about $300 million is PCRBs which tender after 2013. Some of those may travel to the Genco, and if they do travel to the Genco, Ohio Power will retain the responsibilities for those notes which leaves us, once that's happened, with $2.1 billion in senior notes that are due after 2015. We're anticipating that the debt capacity of that wire side of Ohio Power to be about $1.9 billion to $2.4 billion, and we really believe today that the sweet spot of that is right about $2.1 billion, which is what we're left with at those companies.
For the Genco, we've not yet presented a plan to the rating agencies. We plan to do that sometime in mid year, hopefully, when we've solidified more of the plans. We've not committed to getting a rating at this time, but regardless, we plan to manage this business as investment grade and plan to keep it investment grade ratings at the parent level as well. We know and believe in the value of having access to capital markets in this business, investment grade ratings underpin this belief.
We recognize that this can be challenging as the rating agencies have pointed out the increased business risk, but as you heard Nick talk, we've already begun derisking our exposure in this business with the proposed transfer. Mitchell and Amos to APCo and Kentucky Power. This helps the operating company because they get cost effective capacity to solve their needs, and it helps the competitive business with the reduced exposure to the business risk. We've already begun to go down the path, that Nick has described, to take as much risk out of that competitive business as possible. We will be conservative. We will know our collateral needs, and we will increase our bank lines accordingly, and we will have capital discipline as we've demonstrated in the past.
As we go through this transition, I think it's important to note that AEP is coming into this period from a position of overall strength, financially, and AEP is in the strongest financial position that it's been in, in a number of years.
Looking at the balance sheet side, the debt to total cap at the end of 2011 was 55.3%. This is due to our discipline around capital expenditures, O&M discipline, timely and efficient rate recovery and the benefits of the Texas securitization capacity auction true-up. We will maintain spending and investment discipline, and look to keep the capital structure stable over the time period.
Looking at liquidity. The company extended the tenure of one credit facility and repriced it as well of $1.5 billion through June of 2015, and upsized and renewed another credit facility of $1.75 billion through July of 2016, bringing our total credit facilities to $3.25 billion. We believe that these facilities are enough to support our current CP [ph] programs and the trading and marketing activity that we do. And, of course, we'll be looking at how we need to change those credit facilities as we get to that competitive business that Nick talked about in addition to the regulated business.
Over time, our Board of Directors has suggested that we diversify what our credit facility program looks like. Several years ago, we started with a program that was about 50-50 split between domestic and European sources. Over time, we've changed that so that today, our resource mix on these credit facilities is about 45% domestic, 25% European, 18% Asian and 12% Canadian. And that diversity has served us well during some of the financial difficulties that swept, particularly across Europe.
Turning to our pensions on the bottom left-hand side of the chart. You'll see that at the end of 2011, our pension status was 86% funded. From 2010 through 2011, we've contributed $950 million to the pension effort, and we plan to put another $200 million into the pension plans for 2012, which would bring our current funded status degraded to 90%. We've reviewed our investment strategies and have done everything we can to derisk our pension obligation as we get closer to fully funded, and we'll continue to do that as we do approach that fully funded level.
Finally, our credit metrics support solidly in investment grade ratings of BBB at S&P and Fitch, and Baa2 at Moody's. Our 2011 year-ending FFO to interest coverage is greater than 4x, and our FFO to total debt was in the high teens to low 20's, depending on methodology. Consider this for a moment. In the 3 years beginning in 2009, AEP has added nearly $4 billion in equity and retained earnings to its balance sheet. It has reduced debt by about $450 million, resulting in a considerable improvement in the debt to total cap ratio, while at the same time making contributions to its pension of $950 million. The 3-year period began with a negative outlook from one of the rating agencies, and we ended the period with a stable outlook, strong credit metrics and affirmed BBB ratings at the agencies.
Finally, I'd like to take a look at the dividend policy and the growth rates that we've talked about. The Board of Directors recognizes that shareholders anticipate receiving a significant portion of their return in the form of a dividend on an annual basis. That's why they regularly review and then set a dividend payout ratio of 50% to 60% of current period earnings. In the near term, as we are at the higher end of that range and we are going through the transition that we're going through to a regulated and competitive business, you might anticipate that the dividend might grow slightly less than what our earnings will grow over the transition period. And I believe that our board will be looking to see that the dividend is fully funded by our regulated businesses. The company, over the years, over 100 years, in fact, has demonstrated its commitment to paying a quarterly dividend as we have over 407 quarterly dividends, and the dividend has grown at a 4.1% CAGR since 2004. The current dividend yield of 4.8%, when the 10-year treasury of slightly above 2%, and the 30-year treasury is around 3% has been an attractive component to our shareholders.
Finally, Nick talked about our 4% to 6% growth rate, fueled by our capital investment in our regulated properties. Our goal here today was to not just show you what we were going to do and leave it out there as you determining whether or not it makes sense what we're doing, but to show you both what we're going to do and how we're going to do it. And I think we've presented a credible case here today for how we're going to do that. It's going to be driven by investments in our underlying regulated properties. It's going be driven by continued investment in our transmission properties, including the Transcos and the JV opportunities, where instead of now just looking for larger big games that may come through in years to come, Lisa Barton has repositioned that business so that we'll be hitting singles and doubles and really being that transmission investment through her formula-based rates to earnings in the current period.
We've shown a plan for how we're going to do it. We've been credible about how we've done that in the past, and that 4% to 6% growth rate is truly attainable. We're going to work our way through the Ohio transition, as Nick talked you through in some detail. Switching in low levels of capacity, prices could put pressure on us in the near term, but we expect uplift in the future as capacity prices rebound due to environmental concerns and retirements that others have already announced happening prior to the 2015, '16 capacity auction prices. Finally, with the equity needs being about $300 million through the 2012 to 2014 time period, we anticipate most of that being covered through our dividend reinvestment program and don't anticipate issuing new equity during that time period. Overall, we are forecasting an expected total return opportunity for our shareholders to be in the 9% to 10% range through both the growth that we had and the dividend that we'll return to our shareholders.
So thank you for your time today. And with that, I'll ask Nick to come up and we'll answer any questions that you might have.
Okay, at this point, we'll entertain any questions you have.
Just a few quick ones. As you know, the PUCO clarification came out. How would that impact your 2012 and future growth rates if, in fact, that were to hold, if there's any sort of sensitivity you get [indiscernible] to us on that. Also, just from housekeeping. On Slide 19, you guys gave us the competitive generation and the Mitchell and Amos megawatts, but I'm just wondering, sort of the rate base value what we should think about those buckets, what the rate base value is of those and what kind of ROEs you guys have been having with those? And then just finally, with Slide 11, you talked about 10.6 ROE in 2011 as a system average. Obviously, [indiscernible] in part, but different jurisdictions. But just on average for 2012, what are you expecting? And going through to transition, 10.6 ROE doesn't seem particularly low. Just how should we think about the normalized ROEs? You got different jurisdictions, some obviously under earnings, some doing a bit better. How should we think about those -- how should we think about that going forward with the long-term growth rate that you guys are talking about.
Nicholas K. Akins
Okay. I'll cover the PCO clarification. We were disappointed by the clarification that came out in January. And I think there was a lot of issues involved with that particular order, and we're actually pretty heartened by the fact that last Friday, the commission delayed the imposition of the issues in terms of the clarification. So, really, it allowed us to continue on with our implementation plan that was done after December until the commission ultimately decides the issues associated with how much discounted generation will become available and some of the switching activities associated with it. As they went through the process and as we've gone through the process, this latest clarification had a substantial impact, if it's put in place because first of all, the 13 and 14, it became more unclear. We felt like that the 21%, 31%, and 41% was very clear and the amount of aggregation that could be in addition to those particular numbers were very well known. And then to introduce more complexity into the situation, it was not the direction that we would've liked to have seen the commission go. So the commission, certainly, is taking into account. We did file a rehearing request today in Ohio, and we are, like I said, we're heartened that they actually delayed the imposition of those changes until they fully vetted out. So that's good in that perspective. We hold our breath that they'll continue to widely make those adjustments.
Brian X. Tierney
You asked about I think what the value of the rate base of the Amos and Mitchell units that we switched over?
Yes, [indiscernible] what's the rate base value just sort of -- just give us a sort of sense as to what you guys are -- and then what are you earning on that rate base?
Brian X. Tierney
The ones we switched over, it's about $2 billion. And I have to have some folks get back to you with what the balance of the remainder is. You also asked about what the overall ROEs would be and how we intend to sort of synthesize those, as Nick used. We're anticipating a range of between the -- about 10.4% and 10.6% in 2012. And how we think about that over time, we believe that, as Nick was saying, some of our properties will overearn during certain periods, I don't like to use that word. And some of our properties will earn very well over the period, and some of our properties will be in some of that regulatory lag type situation until they can get in for a rate case, and then we anticipate them getting back up to that about 10.5%. And if that 10.5% that's really the midpoint of what our 4% to 6% earnings growth is.
Nicholas K. Akins
[indiscernible] of these cases have been filed with, we requested ROEs in around of 11.15%, I believe, at least that's what the Michigan-Indiana cases were. And most cases, these settle out north of the 10% level, so we feel pretty good about that.
So with the Mitchell and Amos -- just to understand it, should we assume that it's still the Ohio Power ROE that you guys are currently earning on those plants? I think it was 12.8 that you had in 2011 or is there a different number because of the capacity sales, or should we think about that as a different earnings contribution that's happening from those plants right now?
Brian X. Tierney
Well, remember, you need to assume that they are in Ohio Power now, and we haven't transferred them yet. That transfer, we anticipate happening in mid '13. But it's hard to think of ROEs and earning on capacity in Ohio because they're somewhat disjointed at this point, right, because we're not earning on a cost basis in Ohio. So assume that it is subsumed in Ohio's 12.6% return for '12, and -- but remember, it's not cost based so doing the math is a dangerous thing to do in Ohio on a rate base for generating assets.
Okay. So I guess what I'm wondering is -- if you switched them around -- I'm dominating the questions here, but as you switch them over to a regulated APCo situation, how should we think about the potential earnings impact associated with that?
Brian X. Tierney
Yes. So we think about sort of as the derisking component. They will go from being an unregulated return on that asset base of about $2 billion to getting a regulated rate of return in both APCo and Kentucky Power.
Just a couple of clarifying questions. First on the growth rate, the 4% to 6%. I want to be clear, which year is the base for that, is that the '11 actual or the '12 estimate? And also, does that incorporate -- is that '12 through '14, or does that incorporate the full transition in '15 and it's '15 and beyond as well?
Brian X. Tierney
It's off at the midpoint of this year's guidance of 3.15, and it's going forward beginning '13, and as we've said, I think during the transition you may anticipate that we might be at the lower end of that range as we deal with some of the headwinds on transition in Ohio and the lower power pricing environment. And if those things change, load, whatever, power prices go up, transition headwinds aren't as big as what they've been in Ohio, you can anticipate we'd be at the higher end of that range.
So if you think of your business mix from an earnings perspective, Nick, I think you've netted out from an asset perspective about 86%, 87% of regulated, 13%, 14%, unregulated. If you think of the earnings mix that, that mix will generate, what would it be today and what would it be 2015 onwards post complete transition?
Brian X. Tierney
So today, it would be a little bit greater than that and how you take those assets again is kind of a difficult thing to do and translate them into earnings and that's why during this period, we wanted to do it as assets. How do you think of the Ohio assets today, is that regulated or deregulated, how do you think of the off-system sales today, is that regulated or deregulated. If you look at the mix -- so it's a difficult thing for us to do and leave you with some clarity for whether that earnings stream is regulated or deregulated in today's environment. In the go-forward environment, when you look at the 14% that we're claiming will be deregulated or are competitive -- sorry, Nick is always correcting me on that, the competitive business that we anticipate will be 14%, we'd that it would be in that range, maybe going 14% to 20% depending on: a, how much we're earning in that business; what power prices are; how successful we are in our retail business; what happens to capacity prices. So that range could go anywhere from 14% to 20%. If it goes to 20%, we'll look to hedge some of that in and lock it. If it goes below 14%, I think Nick's pretty clear, we'll be getting out of or selling pieces of that business to make sure that it's not a drag on our earnings.
Nicholas K. Akins
They will have a thicker equity layer in it, obviously. We anticipate having that. So we'll make the decision as we go along in terms of how successful that business is.
Last question, Nick , if I may. In the past, you've talked about relooking at your portfolio and deciding, do you need to be in all these states and all these jurisdictions. I'm not hearing that today. So is the message that this is the core portfolio, and going forward, is AEP a net buyer or a seller, or are you pretty satisfied with this portfolio?
Nicholas K. Akins
No. I think I've said this previously, but if I haven't, then, okay. During the next 2- to 3-year period, this is the plan, this is what we're focused on. It wouldn't make any sense for us to do, for example, sell a regulated entity at this point to make ourselves even more hybrid looking. At the same time, we want to show continual progress in the states that are not getting their authorized ROE, and we are seeing that progress. So I'm happy with the mix that we have today, but what I'm trying to do is eliminate the discount on our share value, improve our currency value, and at the end of that 2- to 3-year period, then we'll be in a much better position to evaluate the lines of businesses. And like I said, I'm very objective about being either a borrower or a seller. So when we get to that point, have our currency value increase as a result so we can work more effectively deal along that M&A-type activity, then we'll do that at that point in time. But right now, the clear focus for all the 19,000 employees is to execute on this plan, to make sure that we formulate what we've talked to you about today.
The 2500 megawatts that you're talking about retiring, would you consider retiring those early in advance of 2015, given low dark spreads in an effort to perhaps save costs? Or are those plans economic under current environment with power prices at $26? And then secondly, if you could talk a bit more about your retail strategy and your plans there. You've made that acquisition, sort of what your expectation is for market share and margins?
Brian X. Tierney
First of all, the first issue was...
Brian X. Tierney
On the 2500 megawatts. Those units sit pretty well in the market today, they don't run that often. Actually, they do run considerably during the summer peak periods. So I would say that we will probably continue operating those units as long as we see off-system sales margins that support running that generation. We will constantly evaluate what the process is for retiring that generation, but right now, we're obligated in PJM from an FRR perspective to have that capacity available through that transition period. So we'll go to RPM for the Ohio jurisdiction and then, we will not be bidding in that capacity beyond what's currently committed in PJM. As far as the market, we are, like I said earlier, I mean, we wanted to make sure in our retail operations, which we've already started on our own. Sort of interesting, the front end acquisition of customers has outstripped the back office ability, and that's always challenging from a back-office perspective. What we'd want to make sure of is, is that we have those systems in place to continue to grow in that business. And I believe that with that generation, [indiscernible] that's available, we'll be able to do a pretty credible job of attracting customers. And as long as we're offering other services along with it, that provides even more value. We have not looked at the market share aspects of it at this point in time. What we're really focused on is using that as a hedging activity for that generation. And obviously, once the BlueStar acquisition is complete, we have people there, obviously, who we will be working with to develop the retail operation plan going forward. But that will be put together with the generation, with our trading organization to do all kinds of transactions, as I mentioned, to fill that gap. So just reinforcing that hedging strategy around generation, not around trying to attract as many customers as possible. We want to stay with higher margin activities to provide that hedging.
Hey, Brian, I just wanted to ask the question, again, just to be clear. The growth rate aspiration of 4% to 6%, with $3.15 as the midpoint, and with current market -- wholesale power market conditions, you'd expect to be at the low end of that through '15. Perhaps at the high end, if we saw some improvement, is that a fair reiteration?
Brian X. Tierney
You said something in the middle. I just wanted to be clear...
Nicholas K. Akins
I think you have to watch the natural gas markets, obviously, for off-system sales issues. If it picks back up and if you see the economy, if you see commercial customers start to come back, then that's going to be very positive, so we'll go to the higher end of that range. The transmission business is really kicking in, and when you have that going on, you'll see more and more activity around that transmission space, so be watching for that as well.
A couple of questions, I guess. Number one, just on the clarification with PUCO, debt has captured -- a higher level of shopping has captured in guidance. At this point in time, would there be risk to the guidance you provided if that shopping level went up.
Brian X. Tierney
Yes, so like all rate cases that we're involved in, we made an assumption about what the outcome of that would be and that's reflected in our Ohio switching numbers. Obviously, we're not going to talk about that. In terms of what we filed today, if what they proposed on January 20 was fully through the shopping period, we could anticipate a hit to what we thought we had on December 14 of about $400 million through the transition period.
Over the 3 to 4 years?
Nicholas K. Akins
Over the 3 to 4 years, yes. But let me make a point there, we're going to respond to whatever the Ohio outcome is, and as we move to more of a competitive environment, we can expect costs to be taken out, certainly, to obviate the reductions associated with that. We're going to make sure that we review ourselves from a cost perspective, and really, Ohio really needs to really focus on that transition and what it means because we will have to respond in some fashion.
On the transmission investment, obviously, there's a lot of opportunity there. Do you need to get the state approvals to hit that plan for the 5 states that haven't approved the transition, those have to get done in order to meet that CapEx program, and how do you guys plan to talk about your future CapEx opportunities over the coming quarters or years to build out the '14, '15 outlook?
Nicholas K. Akins
Yes, that plan does -- come off the Transcos?
Nicholas K. Akins
That plan doesn't assume that we're going to get those approvals. Those projects are real, they're going to happen regardless. Now whether they happen within the Transco, and jurisdiction haven't approved it, or in the jurisdiction of utility, it's just a measure of what happens with those projects going forward. We'll -- but the plans we have here are based upon the Transcos that are currently in existence.
Brian X. Tierney
What we're trying to be with you is very conservative in terms of the projects we have, projects we can't get done, investments that we can make that's not long dated and subject to a lot of regulatory uncertainty. What we're going to be adding over time, and obviously, Lisa Barton and her team are out there talking to other utilities and transmission builders and others about JV contributions or projects that we may do together, we'll add those on to that CapEx spend as those become more certain over time rather than telling you about those today if there's still a lot of uncertainty in them. So we'll regularly be updating you on what that transmission spend is going to be.
Nicholas K. Akins
I was remiss earlier. Let me introduce the executives that are here and if -- Lisa, if you want to comment on that at all, go right ahead. Bob Powers, if you could just raise your hand, our Chief Operating Officer, he's in charge of the discipline for sure and the operational excellence that we provide. Mark McCullough is in charge of generation. Rich Munczinski has the regulatory efforts. Joe Hamrock is President of AEP Ohio. So if we have more Ohio questions, you can certainly get the detail there. Lisa Barton has our transmission business, and Lisa, I don't know if you have any follow-ups in the discussion.
I think as you've said earlier, Nick, what we're really trying to do in the transmission space is to create a very clear line of sight with predictable known projects. So the joint ventures that you see that are basically baked into the numbers, our ETT, well, that's very solid; Prairie Wind, which is under construction and everything else is essentially Transco development, with a small amount in there for Pioneer as well.
I just want to follow up on Dan's question. So if I look at the Slide 14 and the transmission EPS, say, $0.24 in '14, $0.31 in '15, that's regardless if you get these approvals for the Transcos. And if you got the approvals, that could be a potentially higher ROE, and it could be higher than those $0.24 and $0.31, but right now that's -- we don't really need approval for the Transcos.
Brian X. Tierney
If you could comment on the recent activity you've had in West Virginia and Kentucky around the Mitchell and Amos transfers?
Nicholas K. Akins
Yes, I'd be happy to, and well, Bob, you may want to mention that. I just want you to meet these people because they are the senior management team that really makes things happen for this company. So you might as well get the Class A information.
Robert P. Powers
Yes, thanks, Nick. And I apologize for my voice, I've been disciplining the organization. I've lost my voice. But, you've obviously had conversations with staff in both APCo and Kentucky, and these are 2 states that have a long-term view of their generation and capacity circumstance. So they're very interested in having hard assets. They're both jurisdictions in which coal assets are important to, not only their perspective on energy mix, but a broader view of their economy. So we're very encouraged by those dialogues, and certainly, we've even -- I mean, Kentucky, regarding Big Sandy received quite a bit of political support that suggest that the investment in scrubber and Big Sandy 2 is what the state would like, and certainly the political infrastructure would like to support coal in Kentucky. So that's kind of where we're at.
Nicholas K. Akins
And the 3-member approval will continue to be FRR and PJM. So the utilities that are involved with that -- certainly you want to -- want to have their own assets, and really be focused on their own long-term future related to those assets. We believe it'll be positive, from their perspective, to actually own the assets as opposed to the capacity payments they had been incurring from the Ohio company.
Do you have a sense of net customer impact from that switch in West Virginia and Kentucky?
Nicholas K. Akins
Robert P. Powers
At the end of the day, it should be a neutral -- to the customer, because for example, if you're adding rate base in Appalachian Power, which you would by moving Mitchell and Amos, you can dominantly reduce in capacity payments they've been making to the pool. So the pool, as we've talked about over the years, is, at the end of the day, at 0 sum. And as you move that into rate base, it's offset by decreased capacity payments so it should be customer neutral. And the -- a portion made of movement of assets between Ohio, APCo and Kentucky was done to basically come as close to 0 sum as we possibly could.
Nicholas K. Akins
Yes. We've looked at the capacity payments that were made versus the net book value associated with that, that would go into rate base, and they're pretty consistent. So we don't see an issue there.
And on the waterfall track, you had $0.21 of Ohio shopping payment in 2012 and then you mentioned that 1% of shopping is about $0.01. Is that the 21% in the original or as you interpreted it? Or as I understand there's some offsets net 1% if you can remarket that power, recapture some of those customers, either retailer or supply or retail their capacity. I'm not sure if you -- I'm not sure what the Ohio outcome is, incorporated in guidance.
Robert P. Powers
Right, and I'm probably not going to tell you that today because it's a pending case. So there is some assumption that's made about the 21%, and there's some incremental assumption that's made about the January 23 order.
How can we think about what percent of that $0.01 decrement from a 1% shopping you think you can offset?
Brian X. Tierney
We were very effective last year in offsetting. We offset about 75% of that in terms of off-system sales and others. We don't view ourselves as having those types of opportunities this year because of 2 reasons: one, the lower capacity charges in RPM that we're going to be crediting back to ourselves from the sales to the competitive suppliers; and two, the lower pricing environment. So our assumptions are baked into what our off-system sales number is for the year in terms of offsets, and again, that goes from about 3 43 in '11 down to about 2 50 in '12.
And just -- what's your view of your legal position on your request for rehearing?
Brian X. Tierney
As always, we think our legal position is very strong. In anything, we'd prefer to try and settle a case rather than litigating it to its bitter end. And I think Joe Hamrock, who's here, and the rest of the Ohio team are going to be working very hard to meet the customers' needs, and to meet the interest that the commission might have in their order.
Nicholas K. Akins
I think our positions are pretty clear in relation to the original stipulation and the order in December. So we'd certainly will be advancing those positions, and we certainly believe the commission went beyond the December orders. One of the commissioners is actually -is sending opinion recognized, and so hopefully, in this latest round, we'll get a hearing on that. Joe, you may want to comment on that too. I just want you to see Joe Hamrock as well.
Yes, sure. Thank you. I think Brian laid it out. We feel like our litigation position is very strong on the rehearing. And in terms of what's reflected, there are other assumptions as well that Brian didn't touch on, in terms of the rate of switching that occurs within each of the customer classes. So there's a lot of different levers and a lot of different underlying assumptions that drive our presumptions about the Ohio switching rates.
Are there specific generating units that you need further clarification or -- from EPA about before you make a decision as to what you do with them, that some 4th year, 5th year type stuff. And what are the units and what are the cut-off dates for you, as far as your making a decision?
Nicholas K. Akins
Well, in our analysis, as it stands now, there's a group of units that would require the 1-year extension, which we believe, that'll be much more flexible because of the state approval process is associated with that. And then we could probably count on one hand the number of units that would require that second year extension, and those are the ones that'll be critical around the liability, and so forth. So we've got to get through the PJM process, understand their feedback and then address that with the EPA. So I'd be hesitant to say, which units and how many at this point in time. But we do have a very credible plan and to get the number of units down to that level is a good thing, and the less units the better, but you have to discuss that second year extension, and we believe that we have a credible case for that.
Do you have any concept as to when you're going to get a decision, I mean, the second year, the 5th year is [indiscernible].
Nicholas K. Akins
Yes, the way it's set up now, you -- I mean you have to actually violate the rule before you can go in and adjust it. So we really need to test that process and say, that's not good enough because we actually have to do either construction retirement replacement, whatever, and to start that process with the state approvals is not something that you wait until the day of to decide. So I think that's one of the issues we will be talking about in our comments on the order itself. Because -- and likely, we'll litigate the outcome of that, of the order, and those are one of the points we'll make. And I'll ask Mark McCullough if you have anything you want to add to it.
Mark C. McCullough
Yes, just to echo what Nick has stated about the power plants and units that are affected by the rule, we have a very solid plan, and we've had one since last June that recognizes that 3 years is not long enough. The fourth year is very helpful on many of those projects, but the fifth year will be required on a few, and they're kind of spread out in terms of jurisdictions. So we're pursuing those issues with the RTOs, and as Nick pointed out, we'll be pursuing them at a federal level after we understand back from the RTOs what kind of same issues they see as they collect all the same information from other generators in the...
Brian X. Tierney
And the particulate matter is you helped out and reduced the number of projects, that as well.
Mark C. McCullough
Yes. We're looking at the proposed rule. We've gathered, accumulated projects in the groups, and we had 36 of those kind of major groups of projects that were associated with all of the U.S. EPA rules. A particulate matter clarification allowed us to reduce that or defer that to 24 projects, much more manageable, but still have issues with timing for the fourth and fifth year.
Are you guys aware of the recent motion to intervene at the Ohio commission filed with FERC on the RPM process. And if so, do you know what steps they could take to mitigate rising capacity prices in our state?
Nicholas K. Akins
They have a pretty corporate separation in our state, and they've also required us to go to RPM, and that's what we're doing. So they'll have to speak for themselves and under what basis that they would determine that.
Sorry. Could you just clarify a little bit more, that $400 million that you mentioned that could stem from the rehearing order, how exactly does that work? Was that just from increased shopping levels? Just a little more clarity on how you'd get to that $400 million?.
Nicholas K. Akins
Well, you see that in the Ohio application for rehearing on January 23 order and it is essentially the effective increased levels of shopping over the term of the transition years in the plant, that's the potential effect of the increased shopping.
Nicholas K. Akins
So we added additional exposure, particularly when we added the Mercantile piece. That just added a whole another part of the customer mix, and then it allowed the industrials to actually participate if they were in an auction area, an aggregation area. And those kinds of changes had that kind of impact, and that's the exposure that we have. And obviously, going to Mercantile, we believe extended what the December order actually provided for.
And is that factored into your 4% to 6% growth rate? The outcome on that?
Brian X. Tierney
Well, we've made assumptions about what the outcome will be, and that's factored into the fourth quarter.
Nicholas K. Akins
Just like with any other regulatory...
Okay, I'll try now. Two questions, first on Ohio. One other thing that has come up since the settlement was approved, there seems to be a decent amount of complaints from certain customer classes like small commercial and I guess some schools about how much their rates have gone up. Could you just -- are they valid? Like some of them are talking about them doubling or whatever, are these -- is that really what happened to those classes? And is there anything that needs to be done to kind of address that?
Nicholas K. Akins
Yes, the distribution rate obviously went up. I think the increases that have been cited aren't as high as what -- if you take the total rate, what the effect actually is. But nevertheless, in a competitive environment, low load factor customers pay more than high load factor customers, and I think there are opportunities to mitigate the impact on those customers during the transition period, and there's growth funds that exist, part of that could be used to offset those costs. And also, I mean, you really do have to look at rate design during this process, and we originally proposed a discussion of the rate design implications. But as you move to a competitive environment, those calls, particularly low load factor versus high load factor, becomes more transparent. So it will be a transition thing that we have to deal with, and I would assume that the Ohio commission will be looking at that to see what could be done. We just -- if something is done, we want to make sure that it's revenue neutral to AEP.
And then totally separate question on -- obviously, everyone's talking these days about coal to gas switching. I'm curious if you have the data for your portfolio, maybe for 2011, on what change of capacity factors are like between coal and gas in your system and maybe what you might be projecting for 2012.
Nicholas K. Akins
Yes, our gas capacity factors are in excess of 80%, which actually surprised us. But when you see where natural gas prices are with this new generation that we have with Dresden and others, at 7,000 heat rate, it will compete on a marginal cost basis with some of these designer coals. And so we do have reductions in capacity factors on the coal units as a result, but that's -- we should expect that in this market. And I think it will have an impact on how we secure fuel supplies in the future. I mean, we -- for our gas supply, we're now doing firm transportation contracts in the East, where we've never had done that before. And also, from a coal contracting perspective, we're going to have to be very mindful as we make this transitions that we do have the flexibility to respond to that kind of market response, if necessary. So coal capacity factors, U.S. market is coming down, gas capacity factors are up.
Brian X. Tierney
Steve, I've got some detail on that to lay out for what Steve -- for what Nick described, and it's exactly right. Natural gas went from a -- as a percentage of our total generation, 6% in 2009 to 11% in 2011, estimated to be 14% in 2012; and coal and lignite was 88% in 2009, 78% in 2011 and 74% in 2012, so it's coming directly from that coal and lignite component. Our capacity factor for a combined cycle is in the east. We're at 35% in 2011 and Mark McCullough and his team just brought another unit on the Dresden unit in Eastern Ohio, and we're anticipating that our 3 combined cycles in the East will have the capacity factor of 59% in 2012.
Nicholas K. Akins
That Dresden unit is an APCo unit. It's located in Ohio, but it's an APCo unit. Also, as we go through this process, we originally looked at 6,000 megawatts being retired. I think now it's 5200, since Big Sandy will stay online. But we also projected that we would replace that with about 1500 to 1800 megawatts of natural gas-fired capacity, so if this fuel switching is going to continue to occur, we're going to retire units that are out of the market as quickly as we can. And then as far as replacement with natural gas facilities, that'll be primarily the fuel of choice for us, because in our eastern footprint, we never had that really before, but now we have substantial pipeline capability and the advent of the Utica and Marcellus shale has just dramatically changed the way we look at natural gas in the future.
When we look at where the auction parameters are for the next PJM capacity auction, I mean, you guys made reference to this in your prepared comments, it looks as though due to retirements, some portions of PJM, you may see a fairly substantial rise in capacity prices. How quickly could you guys respond to the potential economic need or attractiveness on a high-capacity price where you could announce more plans to build combined cycle gas turbine plants similar to Dresden, would that require a fair amount of negotiations on your part? Or thought on your part on how the Ohio situation falls, or could capacity prices rise to a level fast enough where you say, you know what, we want to go ahead and deploy capital fairly quickly here, there's an opportunity. Could you just walk through your thought process on that?
Nicholas K. Akins
I think in any competitive market in this country, let alone PJM, there is not any adequate price signal for the building of new capacity. RPM, we know, is messed up. It's really, to me, it's a short-term wholesale capacity rate, you can't invest with it. And we're going to have to see: number one, the fundamental change associated with RPM pricing that's sustainable for us to be able to finance these projects; and then secondly, for us to build that capacity. We have an advantage because these units that will be in retired or brownfield-sized, they already have transmission, they already have permitting and so forth. So we can move relatively quickly to put that kind of capacity in. I would certainly put in new combined cycle capacity and not refuel because refueling, you lose a lot of efficiency from that so you really -- it's not an energy play, it's purely a capacity play. But we want to make sure that when we replace these facilities -- and the market's going to dictate that and from the regulated side, between the number of approvals, they're going to dictate how quickly we are able to put the capacity in. So we'll be able to respond relatively quickly, but it takes about 3 years to get a natural gas combined cycle facility put in.
I wonder if you could elaborate on the plan over the next 2 or 3 years to raise realized ROEs at the APCo and Indiana-Michigan?
Nicholas K. Akins
Yes. Charles Patton, who was previously at Texas and turned around Texas for us, so you see he's at APCo, and I think last year, it's at 6%, and I think the numbers showed 7% -- well over 7% in total. But we're expecting an order of 9.2%, 9.3%, I think, for this year. So he's making steady progress in a challenging area. Now keep in mind, the majority of the environmental expense that is going to occur for APCo has already occurred. So the rate increases associated with that are reflected in the rate structure. So we really have to move that area to -- I believe this is where the approval arrangements are really going to change the way APCo goes forward. They were always concerned about capacity payments from -- that are being made to the Ohio companies and generation not built in those areas. And rightly so. I think more states are becoming very parochial in their views about job creation, activities within the state. The more responsive we are to that, the better off we are. Charles is looking at the potential of our Clinch River project, it'll be retired to refuel that to natural gas. So those kinds of things are really going to be positive for the continued development of that jurisdiction -- for both the jurisdiction in Virginia and West Virginia. So -- and I certainly believe he's making considerable progress and will continue to make progress, as Paul Chodak has done has done at I&M as well. Just tremendous progress in both of those areas, so we're optimistic about those.
On a construction basis, 8900 megawatts in competitive generation, is that critical mass enough or do you have plans to add to it more? Or do you want to go the national footprint in terms of your competitive power, or you want to just totally shrink it and get out of that area?
Nicholas K. Akins
Certainly, I think the market's going to dictate what that capacity mix is. But right now, my focus is to hedge that 8900 megawatts. I don't want to add to it at this point until we understand where the market's going, and how that business is going to continue to function. I don't want to do anything to jeopardize the regulated status that we have today, and certainly as we go through that process, there's going to be more definition around which units survive and which don't. If we want to put a new source standard that happens to include existing generation, which are different threshold for coal-fired generation, so we really have to feel our way through that process to determine that. But on this space, I'm going to be risk-averse to expansion of that business.
I was wondering, do you see any obstacles in transferring -- sorry, here. Do you see any obstacles in transferring Amos and Mitchell out of Ohio, and what could those obstacles be?
Nicholas K. Akins
Brian, did you get that?
Brian X. Tierney
I'm sorry, I couldn't hear you.
What could be the obstacles you would face in transferring Amos and Mitchell out of Ohio?
Brian X. Tierney
So for some reason, over in that corner, you're sounding omnipresent.
The obstacles to doing what?
The obstacles to transferring Mitchell and Amos.
Brian X. Tierney
Oh, the obstacles to transferring Mitchell and Amos. Oh, okay good. Yes. We'll just be -- I'm sorry, we can't hear from that corner. I think those assets are going to meet the needs of APCo and Kentucky Power. We filed to do that at FERC. Obviously, the discussions will be with the regulators in Kentucky and Virginia and West Virginia to see what their interests are in having those assets. But it seems to me those entities have a need, and what we're trying to do on our filing today at FERC is to try and meet those needs out of the gate. And if that capacity meets those needs and helps us to hedge the unhedged portion, that makes a lot of sense for us. Obviously, Mitchell and Amos being in West Virginia, the way they are, might have a particular appeal to the West Virginia and certainly the Virginia regulators in terms of they're in-state, and they can regulate them as they do with the other assets. And if it meets the need of Kentucky Power and reduces a significant CapEx spend that we're going to have to have in Kentucky Power, that would likely meet their needs as well. So what we tried to put forward was a settlement position that met everyone's needs and we'll just work through the process, talk to the regulators and work our way through the settlement process. And we don't anticipate any difficulty, but it's a negotiation like anything and we try to put forward a strong settlement position out of the box.
Nicholas K. Akins
I think the only potential obstacle could be if the state really needs to think about whether they have an RFP process or something like that. But in this case, these units are a no-brainer. And when you look at the long-term value of fully controlled coal in coal states, West Virginia in particular, and these units are located in West Virginia that they already participate in, it's really a great, great deal. And then we've already added natural gas-fired capacity for APCo. We'll likely to add some more natural gas capacity. So you're going to see sort of a repositioning of this thing, and in the market where you're having the retirements occurring, it will be very advantageous for them to assume that capacity mix. So while there could be potential obstacles, the benefits far outweigh those potential obstacles.
Andrew Levi - Caris & Company, Inc., Research Division
It's Andy Levi from Caris, and I apologize, I came in a little late so you may have covered this at the very beginning. Just -- the hedging strategy, I mean I know you're talking about 75% to 80% that you want to hedge, the year forward. But as you get out to the outer years, what should we think timing wise, just kind of give us a little bit more detail on the hedging strategy and the years presents.
Nicholas K. Akins
I think what we've said is 75% hedged by 2015, and the reason why is because -- I mean, with the long-term contracts to co-ops and others, we haven't been able to do that because we didn't have the capacity available. Now that we have the capacity available, we can assume our longer-term contracts, and those discussions will continue as soon as corporate separation is put in place in the first quarter of '13 in preparation for '15. And then the retail play is going to be a continual operation that we can begin effectively now. Although, we can't hedge against that generation until we fully get that corporate separation activity done, so it's going to be key for us.
Brian X. Tierney
Really, I think that it's that 25% -- the 20% to 25% that won't be hedged, we'll be thinking of that in the shorter-term, and hedging that in years 1, 2 and 3, and the rest of that would be beyond those time frames.
Andrew Levi - Caris & Company, Inc., Research Division
Quick question around O&M. You're taking out a lot in 2012. How should we think about the right growth rate after 2012, and what are the right levers that you have to pull around O&M?
Nicholas K. Akins
Well, this company is a huge company, and as we progress particularly to a competitive environment in Ohio on the generation side, there will be O&M reduction capabilities there. Also, when we look at the operations that we went through a pretty substantial severance program here last year. And when we went through that, it was fairly uneven, we basically took up everyone who raised their hand and then, some areas, though, have not experienced the same type of reduction. So we may look at consolidation of operations, those types of things that will benefit us from an O&M standpoint. And then, the O&M continues to be reduced because of optimizations of the power plant operations. Mark McCullough and his team have done an extremely good job of continuing, refining that generation. We went to -- I guess, it was a seasonal operation here when the economy went down. Now he's talking about a super seasonal operation. So there's things like that, that will occur along the way and that we have just -- we have a lot of leverage to pull. But one thing's for sure, we have to position this company for success in the future, and that means, we'll be expanding in transmission, expanding in the retail organization so that we're effective, and we have to be able to accommodate those areas, and as well, continue to function on those basic necessity areas that we're currently doing. So we have a lot of work to do on that front. Any other questions?
I just wanted to kind of circle back to the question asked before. Do you have any color as to kind of why PUCO's intervening -- trying to intervene in the RPM process? Any color whatsoever, just...
Nicholas K. Akins
No color. Well, I think they probably are sensing the retirements of generation and auction results, and they want to have their say in terms of discussions going on. That's my assumption, but you'd have to really talk with them.
Brian X. Tierney
I think their intervention was pretty plain vanilla. I don't think they'll really reveal the reasons why they are intervening. They just have to intervene out of time. And I don't think we've heard on that yet. So I don't think they've revealed what their reasons are.
Brian X. Tierney
I do think, though, that it's -- like I said before, it's important for competitive markets to work for there to be adequate price signals for the building of new capacity. And I believe that any state that moves in that direction needs to think about that kind of approach. So it could be that kind of thought process on their part. I don't know, you have to talk to them. Any other questions? Okay. Well, thank you very much, everyone. Thanks for coming.
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