Nicholas K. Akins
While everyone's getting a seat, good morning, and welcome to AEP's Analyst and Investor Meeting today, and thank you for your interest in AEP as well. So I guess, legally, please refer to the Safe Harbor Statement in the package that was given to you, so -- and we'll continue with the presentation.
We have an excellent lineup of speakers today, and it's great to be back after 1 year, back in the saddle again with providing guidance, but also really providing a growth story for AEP. We're in a distinct position now, where we've cleared the decks, where now, we can really start thinking about how we reposition the company. And I think you're going to hear a pretty compelling story about why you should be investing in AEP.
So we have an excellent lineup of speakers. Brian Tierney, CFO, will be up here a little bit later with the financial update. But we also have Lisa Barton, who heads up our transmission effort. I know there's a lot of questions about transmission. It's a major growth area for us, and we're very focused on that type of business. She's going to talk about some of the issues that I'm sure you have questions about relative to ROEs and things like that associated with transmission. And then Chuck Zebula, who you all know has taken over the competitive part of our business. So as we move toward that competitive environment in Ohio, he's very focused on dealing with the -- what will be unregulated generation, along with our retail play and the wholesale trading operation that goes along with that. So with those speakers, we should be in a position to answer many of your questions on the front end, so -- but if you have questions after that, certainly, we'll be happy to take them.
We also have some of our senior leaders here in the audience as well. I wanted to at least point them out, so if you have questions, you can catch them as well later. Bob Powers, who's our Chief Operating Officer. If you could just raise your hand, Bob? Rich Munczinski, who heads our regulatory efforts, so all of the regulatory questions, you can go to him. And then Mark McCullough, who heads up our Generation area, heavily involved with the environmental effort and other activities associated with moving to the unregulated generation. And then, Lonni Dieck and Julie Sloat are here as well. Julie, I think you know from the past as well. So we have a very, very strong team here and people here who can answer the questions that you might have.
So let's talk about what you're going to hear today. There's a positive story about our accomplishments in 2012, and I think you're going to see, we did a lot to clear the decks and eliminate risk for this company, but even more so, we're in the position now where we can talk about the strategic repositioning of our corporation.
So as you see from the slide here, we delivered 2012 GAAP and operating earnings of $2.60 and $3.09, respectively. I think we beat consensus on 2012. And then now, we're providing guidance again, for 2013 and 2014. 2013 guidance is in the range of $3.05 to $3.25 per share, and then operating earnings range for 2014 is $3.15 to $3.45, with midpoints at $3.15 and $3.30, respectively.
Earnings growth we'll reaffirm at 4% to 6%. We think that's supported by our regulated companies. And we're also, with board approval, increasing our dividend payout ratio, supported by the earnings of the regulated operations. Previously, we had 50% to 60%. We're raising that to 60% to 70%.
You're also going to see that a lot of work's been done to make sure we have a strong foundation for growth, but also a strong foundation financially. Brian will be talking about the things that they have done relative to the financial effort, and it ensures that we're well into BBB credit rating and certainly well positioned to be able to move through the process of unregulated generation and so forth related to Ohio.
And then the transmission growth. I hope -- you've probably had a chance to read the book at this point and know all the answers, but you look at the transmission growth, it's phenomenal. We continue to focus on that piece of the business. I think when you look at this business for the future, when you're retiring generation, when you're thinking about new sources of renewable energy and so forth, transmission will be key to that, robust transmission, and it certainly is a compelling growth engine for this company.
The generation profile is changing, obviously. Chuck will be talking about that in detail, but generation is one of those areas where we'll still have a huge amount of regulated generation, but as a result of the corporate separation in Ohio, we'll be moving some of that generation out to an unregulated effort, and we'll work to hedge that. The Ohio situation is clarified. We were in the situation last year where there were orders going back and forth and a lot of changes were occurring during the year, and it was very difficult for us to provide guidance. But now, we have a clear path toward an unregulated environment and a competitive environment in Ohio, and we're well positioned to take advantage of that as well.
But I do want to reaffirm to you that we are a regulated utility. We're 86% regulated; 14% unregulated; 4%, we already had with river operations; the other 10%, we'll pick up after the corporate separation. But we still are a regulated utility, and that is our focus. And in the future, you'll see that we'll continue to focus on regulated operations as well.
So let's move on to some of the detail. For 2012, there were a lot of operational accomplishments, but things that you'll see that really presents a foundation for us so we can start really thinking about the growth and repositioning of the company. So 2012 was all about clearing the decks, all about reducing risk and repositioning the company for quality customer service and growth.
So I always maintain, the first part of the slide is around safety. We had 0 fatalities during 2012, and we had one of the best safety records from an occurrence standpoint and a severity standpoint that we've had ever at AEP, and that's the first early indicator you'll see of operational excellence in any company. We maintain that. We focus on it. And it's shown during the work that we've done during the year.
So the things we did from a construction standpoint: Dresden, a combined cycle gas unit, we brought online early in the year. And then what we're very proud of is the John W. Turk ultra-supercritical coal plant, which we brought on December 22 of last year. It went online in 2012, and we said it would go online before the end of 2012. It was important to do that from a regulatory standpoint. But from an operational standpoint, we couldn't be more proud of the way that, that unit is operating. In fact, we originally anticipated that it would be one of the lowest heat rate coal units in the country; it is. But in fact, it's even lower than we anticipated. We thought it would be 8,900 Btu/kWh heat rate. It's coming in at 8,700 Btu/kWh heat rate. And for our coal unit -- our average coal unit heat rate's about 10,000 Btu/kWh, so significantly better. That means less emissions, less carbon emissions and certainly, a very positive addition to the fleet for SWEPCO.
We also participated in several storm activities. The derecho, which was amazing given there was only a 10% chance of thunderstorms, rolled through Ohio and our West Virginia territories and Virginia territories and on into Washington and so forth. But the derecho was an eye-opening experience for us because we had to mobilize crews very quickly in response to that kind of effect. We responded well. Certainly, it was during the hottest part of the year, and our Ohio customers and West Virginia customers were truly troubled by the heat and the time it took to get customers back. But we did get customers back very quickly. There were some that took upwards to a week, and that was certainly a serious issue for us, and we mobilized crews effectively as a result. We're very proud of the efforts associated with that given the conditions that were occurring.
We also participated heavily in hurricane -- or Superstorm Sandy. We had about 3 feet of snow in West Virginia, so we had to recover our own customers and then we moved on with substantial crews to the Northeast to support that cleanup effort. And I would -- this is probably one area where I would say the President was intimately involved. We had CEO calls where President Obama did join the call and was very focused on the effort in terms of cleanup us well, and it really forged a new relationship between the federal government and the utilities in support of these kinds of major calamities. So certainly, it was a great learning experience for the entire industry, and we'll continue to take those lessons learned as well.
We also further optimized, and as you'll see later in the capital associated with our environmental spend, we further optimized that environmental compliance situation. So we'll talk more in detail about how that occurred. But certainly, as the EPA came out with the final orders and some of these rules, we saw that there was some opportunities to reduce the capital spend associated with that. It's important for us to reduce that spend, to levelize it so that we can we reallocate capital to other parts of the business, such as Transmission. And we're very focused on doing that, and you'll see that we've been very successful in doing that.
The growth in Transmission has been very good for us. The CREZ buildout in Texas in ETT continues to grow. And we've had $720 million of cumulative investment into Transcos, which is a considerable positive associated with that.
We also completed settlement related to the turbine outage that we had at Cook. We achieved a settlement with NEIL, the nuclear insurance mutual company related to that outage.
The Ohio situation. We've been through multiple orders and multiple areas where we had to deal with capacity cases, ESP cases, all those types of things, but we finally reached a point where we have clarity related to Ohio, and that's a good thing. I think certainly, the commission and the company was very focused on trying to achieve a solution that made sense for the customers in Ohio but also made sense for the company. And we wound up in the situation where we do have that clarity to move forward, and that's a great thing.
We also have filed all the FERC cases, and they're going well. We continue to have discussions with the interveners in those cases and with the states involved, and those communications are going very well, as well, on the transfer of those -- of generation to APCo in Kentucky.
So really, when you look at the suite of changes from an operational accomplishment perspective, it's very impressive to go through that. From the financial accomplishment standpoint, we did a lot in terms of securitization. Earlier in the year, we securitized bonds at Texas Central, and then we also are in the process and will soon complete securitization around the reg assets in Ohio and then some of the deferred fuel costs in West Virginia. So that securitization is important for us so that we can continue capitalizing in other areas. We also expect, and we did get -- begin recovery of the deferred fuel in Ohio, but we also expect by 2014 to have securitization in place for that as well.
And then we also, from a parent debt perspective, refinanced a considerable amount of parent debt at advantageous yields, and you'll see the numbers there, that very substantial positive benefit for the company ongoing.
And then from a discretionary contributions to the qualified pension, we made $200 million of contributions to the pension during 2012. We were funded at 92% at the end of the year. I'm pleased to say at the end of January, that's 93.7%, so we stand very good in terms of our pension being well funded.
And then we also changed some medical benefits for retirees. And we've done an overall benefits review, compared to market peers in the space, and we've made certain changes that actually provided benefits of $460 million on our OPEB liability.
So it's been pretty substantial changes from a financial standpoint that positions us well for the future. And we'll continue to address those types of issues, which I'll talk about in the repositioning later on.
So the next slide is my favorite, it always is. I always call it my equalizer slide. But one thing about it, today is very different than last year. Last year, when you think about the complexity of what we were dealing with -- and I know many analysts believe that we're in multiple jurisdictions and it makes this very complicated. We're seeing that clear up considerably. And now, where diversity used to be an element of complexity, now we believe it's an element of strength. Because as you can see, these have changed from last year. And I went back to the February 10th presentation of last year and looked at the ROEs of the various companies, and you see them going up and down, based upon where they're at in the cycle from a regulatory standpoint and also, based upon the work -- the incredible amount of work that's being done by our operating company presidents to bring more concurrent rate recovery and improve the ROEs.
Now as you probably remember, Ohio was at 12.81% last year. It's now at 11.1%, which is lower than what we actually anticipated at this time last year. I think it was a very -- it was a very tough process we went through with the Ohio Commission, but it's one where we do have clarity now and we're at a point where we've achieved and continue to achieve the 11.1% return on equity, which is very, very credible, but also, at the same time, the other states improved. So the jurisdictions have really worked together to come out with an overall ROE of 10.6%.
So I'm going to go across here and explain to you some of the differences. In APCo, we were at 7.48% last year, and -- which was low. We knew it was low. We talked to you about some of the things we were trying to do to move the ROE up. And today, it's at 9.4% ROE. We actually anticipated it to come to 9.2% at the time, but we've done better there.
Also, at Kentucky Power, many people were asking at that point in time what we were going to do with Kentucky Power because it was lower at 9.66%. It's now at 11.1%. So incredible amount of progress there as well. And there are substantial cases that are continuing on, obviously with the transfer of capacity from the unregulated fleet, and that's going very well in those jurisdictions.
I&M is the one that we have really been focusing on. Last year, I&M was at 8.82%, and it shows up at 7% here. And it's because of all the capital that's being deployed, but it's also because of the regulatory lag. This is the -- probably the largest regulatory lag situation that we have on our system. We just completed a case 2 days ago that's certainly going to help us improve the ROE as an $85 million benefit and it also sets the tone for the future. We expect the ROE to improve there. But even more so, we've been working on the legislative front to try to address the issue of regulatory lag. And we now have a bill that's passed through the Senate in Indiana that would provide for not only more concurrent regulatory recovery. It's a 10-month period to get a case completed, and if you don't get it completed in the 10 months, then you have 75% of rates going into effect at that point in time. It also has a forward-looking test year. So those are the kinds of things that we're focusing on from a legislative standpoint and a regulatory standpoint to support the ROEs being more concurrent with existing capitalization, because we have a lot to spend at I&M.
As you know, we're doing a loss cycle management on our Cook nuclear station. It's about a $1.2 billion investment, a pretty substantial investment. And now we're deploying it in Michigan, where we have 80% of that preapproved, with a deferral associated with it, and then the other 20% will go into a rate case. And then in Indiana, we're still working on the process with the Indiana Commission on that, but we fully expect to get some kind of pre-approval there as well. So it's important for us to understand it's not new nuclear, it's replacement of existing components so that we can extend the life. And we have a life extension for -- that's approved for Cook, and we need to make these investments. And they're also very positive investments when you look at the overall scheme of these types of investments versus other opportunities that may exist out there. So a very positive message there, and we fully expect I&M to improve.
As you can see, the Western companies continued to perform well. PSO, we always call it the Utility of the Year in our space because they have the best safety record. They have -- certainly from a customer satisfaction standpoint, they're very good, and that's what we're after. Happy customers obviously make happy regulators, and that's something that we're very focused on.
SWEPCO, just yesterday, had a hearing and are now in a position where the settlement, it was approved that would include Turk in the formula-based rates is now moving to the commissioner for approval. And as you know, in Louisiana, the commissioners are -- I think they're meeting in the next couple of weeks, so we should be able to get a result there, and we expect it to be positive.
So AEP Texas continues to benefit as well.
Now what's going on in our Western properties, we continue to see growth in those areas, certainly driven by shale gas activity. The oil and gas activity has been very positive in those territories, and we expect that to continue at least for the next couple of years for the buildout, and then pump load and other things will continue to drive that. We're also seeing a pretty significant list of new proposed projects, industrial projects, in those territories as well. So we're very keen on our Western properties continuing to improve.
So with that, I'll move on to the next slide. What we have, so far, from an AEP return and stock performance perspective, if you look at the 1-, 3- and 5-year TSRs, we're very attractive against not only the S&P 500 utilities, but the S&P 500 itself. For 1-year, 3-year and 5-year, we've outperformed each one of those, with the exception of the S&P 500 when you take the 1 year into account, primarily because of the dividend tax issue that came about and also the market issues that exist today. So we are very, very fortunate to be able to perform well against both of those measures. in fact, you look at the right side of the graph, and we've actually eliminated that 17% discount that we had last year. We told you that we were very focused on eliminating that discount, and it is now eliminated.
Now that's to the S&P 500. We're not happy with that because we want to do better. We want to measure up against -- well against the regulated utilities, but also, we believe that when you look at the risk profile of AEP and what we've done during the last year, and once we get through corporate separation, you're going to see utilities that pretty much operate the same way in terms of recovery mechanisms and so forth. We believe we should trade at a premium. So we're not through yet. We have a lot of work to do, but that's what we're focused on.
So why do we have a strong investment platform? Well, there are several reasons. As we said earlier, we're predominantly a regulated business, but we're focused on clarity, execution, line-of-sight and discipline. Those are the things that we need to do to achieve very positive customer service, where regulators are comfortable with what we're doing, having discussions with our regulators on an operating company perspective that are meaningful, particularly in light of the changes going on in our Eastern footprint. In the past, we had this convoluted issue of the pool. Once we get past the pool, then each utility will be responsible for its own resources and decisions around that. And I think that's a very credible conversation for commissions to have, particularly in light of the multitude of technology and preferences associated with resources that we have today. So I think it's going to be very positive for us and it continues to be, as evidenced by the graph that I showed you earlier.
Significant Transmission growth opportunities. The amount of Transmission growth, I think if you see the earnings slide from later on that -- Lisa, I hate to steal your thunder -- but that continues to grow substantially. And we have plenty of projects in Transmission. We now have a repositioned business, where we have fortified the resources for Transmission to ensure that it can continue to grow. And as I go through the repositioning exercise, you'll see the linkage of that to making sure that the Transmission business does have those resources.
And we now have stable regulatory relationships. Our operating company presidents are very focused, very determined to have positive relationships with our commission, with the legislators and so forth. They have more of a say. They are now doing the capital allocation among their own operating companies. And that's an important distinction because when an operating company president can talk to a regulator with a sense of authority, that is a positive thing, and that's something we're very committed to.
From the cost structure perspective, the repositioning certainly helped us in that regard. I think you'll see later on that we've kept O&M flat from year to year. The repositioning exercise enabled us to do that. It's not done. It's not over. There's more work to do, but we are seeing substantial benefits associated with that. We have -- out of that process, we had 80% of our Gavin plant looking at lean practices. We had teams of employees from across the company working on ways to not only review processes, but also to eliminate those things that didn't make sense to us anymore. And they came up with a very, very good slate of reductions associated with our O&M.
And also, the outgrowth of that is a strong culture of collaboration. In combination with our repositioning study, we are also having a very focused effort on changing the culture of AEP, more toward an entrepreneurial culture that's willing to change and is willing to move forward with many of the changes we have relative to the growth engines of the company.
The Ohio generation fleet is certainly in the process of being formed. It's being put together with the retail and the wholesale marketing business. Our wholesale business has been around for years. It's a very credible business. We've kept it in place. I do want to reiterate that the reason why we have our wholesale business, our retail business, is really to focus on hedging that generation. It's not about being a national energy player in terms of retail. That's not what we're about. What we are focused on is margins in our retail play, not -- and that's focused on specific customers. It's not about how many kilowatt hours or how many megawatt hours you can serve. That's not a good thing for us. We're trying to maximize the hedging margins associated with that generation that becomes available.
So the growth opportunities are driven by the investments in the regulated properties, and our dividend growth is certainly supported by that.
Okay, next slide, please. Okay, so from a fleet transformation perspective. I've talked a lot about the transformation that's occurring in the resources of AEP. Historically, our culture was that if a coal unit went down, we did everything possible and spent everything possible to keep it running. We wanted to keep it running 100% of the time. Today's analysis is very different. Not only is it a measure of how you run the generation, but also what capital investments you make and are they, in fact, going to pay back over a period of time. And we look at the lifetime of the units. And as a clear indication, the Big Sandy example that you probably all have heard about. We anticipate that we would put a scrubber on Big Sandy, and it didn't work out that way. And the reason why is because of economics, but also a further review of coal in our footprint. We're looking at it from a portfolio perspective. We want to see a balancing out of our portfolio. And actually, the shale gas revolution in our Eastern footprint has been very positive in terms of our ability to take advantage of trying to reprioritize and balance out our fleet from a coal perspective.
So you'll see our coal capacity come down. We plan on retiring additional generation in the '14, '15, '16 time period. And that's certainly something that we're focused on doing to ensure that not only are we meeting the EPA obligations, but from a financial standpoint, we're putting customers in the best position to take advantage of lower cost resources as they become available.
In 2012, we had generation from a gas perspective increase 40% to 50% in our Eastern footprint. That's just a phenomenal change. But it also said that we had the flexibility to go back and forth between coal and gas that benefited customers. So in the first 3 quarters of the year where natural gas prices were lower than $3.25, we were burning more natural gas. Then as the winter months ensued and -- really, our breakpoint is around $3.25. So when you get past $3.25 on the gas price, our coal units are going to start picking up at full capacity. So during the latter part of the year, the coal capacity factors picked up.
So it's those kinds of things that are going to be very positive, not only for our customers, but also positive for Chuck's generation effort as well because he'll emerge with 2/3 coal, fully compliant coal that's very positive from a delivery standpoint, from a fuel perspective and so forth, but also, 1/3 natural gas. So it'll wind up being a great combination for him.
Estimating the capital spend for our environmental effort. Originally, we started with a $6 billion to $8 billion anticipated capital outlay for these types of requirements. And that changed, from $5 billion to $7 billion, over a period of time when the EPA came up with the -- came out the rules, particularly on particulate matter. We had one situation where, instead of achieving 99.7% removal rate, the proposed rule was saying you had to achieve 99.9%, and that 0.2% was costing us about $800 million. So the EPA did listen and made the adjustments, so that adjusted reduction down as a result. And then now, we're saying the cost is going to be from $4 billion to $5 billion. And we've looked at technologies. We believe from a compliance standpoint that we can achieve further compliance reductions as a result of technology improvements, but also how we run the generation. So those are the kinds of things that we're looking at as well.
We also have a proposed settlement relative to Rockport that would enable us to achieve the environmental compliance necessary. So we have reflected that in our capital plans as well.
So we believe it's going to be $4 billion to $5 billion, and we're committed to continuing down that process. But now -- right now, it says $4 billion to $5 billion. We still have analysis to do at the time every time we make a decision relative to these compliance measures, and we will be making wise decisions with a blank slate in the decision around coal versus gas or any other type of resource. We include transmission as a resource. We include renewables, energy efficiency, demand side management, all those are resources that we need to take a look at. But clearly, we're probably one of the few that look at transmission as a major resource as well.
Next slide. Okay, so let me talk a little bit about the repositioning cost study that we did. Had a lot of questions during the last half of the year about how the study was going, always said the study was going fine. It was a very positive thing for AEP to do. I don't -- it'd been years since AEP went through a process looking from top to bottom at the processes that we actually have. And it turns out that the reductions that came into play that enabled us to keep O&M flat and reposition resources over to the transmission effort, over to Chuck's competitive business effort, we were able to achieve that because 75% of the reductions are relative to the process changes alone.
Some of those things are like looking at everything from gloves to equipment from a supply chain perspective, to look at the efficiencies there. We had thousands of different types of gloves. We brought it down to less than 100 pairs of different kinds of gloves. So it's those kinds of things that are very simple, but they're things you have to go through to make sure you are achieving the objective. 75%, as I said earlier, were those kinds of process changes. And as I mentioned earlier at Gavin plant, 80% of the people were involved, including the unions, in determining a solution for that. We had over 1,000 contractors working for AEP. And by looking at what they did versus what the needs of the company were, we were able to take advantage of lowering the contractor requirements as well, and that provided significant benefits for AEP.
Now there's nothing like having an AEP employee that has that focus, that has that determination to get the job done on a regular basis, and that's, in fact, the way we look at it.
Now we also put 5 initial teams in place, and you see the 5 listed there. They were the major areas that we saw immediate savings in, but there's some work that's continuing to go on related to some of those efforts. We not only achieve the benefits that are reflected in the 2013 guidance that we've shown you, but also for areas like information technology, IT, those areas may be more of a 2- to 3-year process that we go through as we redefine the way we serve customers within our IT organization. We slowed that process down because we didn't want to impair the other changes that are so dependent upon the IT solution. So it is a stage thing, and you will see additional benefits in future years associated with these initiatives as we move from Gavin to all of the other power plants in terms of lean practices and as we look at IT. So those are very positive benefits.
The study reinforced that our resource allocations throughout the company should be focused on customer service and focused on those growth areas, and that enabled us to do that.
And also, the cost profile, as I said earlier, substantially absorbs the O&M, and that's why you're seeing a flat O&M line from 2012 to 2013, which is different, I think, than other utilities have reported relative to their O&M. We also see a further mitigation in O&M costs in the future as well as a result of this repositioning effort, and as a result of the cultural changes that are occurring within our company.
So moving ahead to the dividend policy. That's probably the -- one of the surprises for today. Our current yield is 4.2%. Our current payout ratio is 59.7%, and it shouldn't be in small letters; it should be in big letters that we paid 410 consecutive quarters of dividends. So we're very proud of that and fully intend on it continuing. The board did review and increased the targeted payout ratio to 60% to 70% of consolidated earnings to bring us more in line with the regulated utilities, and it showed the confidence that the board had in our ability to produce those kinds of dividend payouts.
The dividend level is obviously -- we talked about this in the last presentation. When you look at PP&E and the regulatory piece of the business, it certainly does support that dividend level. And then the board is also very committed to the dividend that's expected to grow in line with our earnings from the regulated operations. So that is a very positive thing and certainly something that the board will continue to review.
Then as you can see our dividend history, we've continued to increase the dividend, and it's been very positive, and we fully intend on our dividend policy to be positive for our shareholders.
So our expected growth rate. We reaffirmed our expected growth rate of 4% to 6% using 2013 as a base because, when we move from 2012 to '13 with the Ohio situation, you look at Ohio and look at the ROE, it's come down substantially; it had a tremendous impact on the revenue of the company. We have been able to mitigate that with the other states. The other states have been very, very positive. And as well, from a cost control and discipline standpoint, we've been able to absorb the tremendous impact of the Ohio situation. Nevertheless, we are seeing the 4% to 6% growth rate in the future based on the 86% regulated business that I talked about previously.
We also felt confident enough to give 2 years of guidance with that growth, so you'll see that we had 2013 and 2014 ranges for guidance. The range for 2014 is a little bit broader because we still have some issues to get through with corporate separation and other things, and we wanted to make sure that we're able to fine-tune that as we go forward.
Our capital program. Very proud of our capital program. We were looking at huge cliffs to overcome associated with our capital program. We don't have that now. We've really focused on mitigating the capital impacts and making sure that we're able to manage within that so that we're not having to issue additional equity, other than the DRIP that's currently in process. And we're very committed to having the capital plan to do that. The $3.6 billion in 2013 and the $3.8 billion in '14 and '15, respectively, provide for the benefits not only from the environmental compliance perspective, but a lot of block and tackle type of spending that typically regulatory recovery is not an issue. And now you're seeing not only how much we're spending to attract growth, but where we're spending it is even more important. And that's something we're very, very focused on in getting it right. And that's what the operating company model is about, to make sure that there's conversations with the commissions and our customers to ensure that we are spending on the right things. And certainly, from a transmission perspective, that is a growth area, and we're trying to do everything we can do to refocus investment there as well. And that certainly improves the reliability and the customer service experience. So very focused on that.
Our authorized ROE range across the board, if you look at the 2 bounds, 9.96% in AEP Texas, that's related to the transmission. That's been in place for a pretty long period of time. The recovery mechanism there is quite good, though, from a transmission recovery standpoint. It works more like a fuel cost type adjustment.
And then also, on the top side, 12.8% at our Prairie Wind project, which is also transmission, and Lisa will be talking later about the ROE trends and what we see relative to the kind of projects that we perform in Transmission. But still overall, a 10.6% overall in the utility group, and we're very happy about that.
So with the confirmation of that 4% to 6%, now I'll turn it over to Brian. He's going to go over the financial update, and then I'll rejoin you to wrap things up a little bit later. Thank you.
Brian X. Tierney
Thank you, Nick, and good morning, everyone. We have a lot to cover today, so I'll jump right into it. And I'll give a comparison of GAAP and operating earnings for the fourth quarter of 2000 -- for the fourth quarter in the year of 2012 versus '11.
GAAP earnings in the fourth quarter of 2012 were $0.05 per share compared to $0.64 per share in the fourth quarter of 2011. Operating earnings, however, were $0.50 per share compared to $0.40 per share in the fourth quarter of 2011. Reconciliations between operating earnings and GAAP earnings for the fourth quarter include the Ohio plant impairments, the costs associated with the restructuring program, as well as a reserve associated with the U.K. windfall profits taxes issues from when we owned plants over in the U.K.
On the right-hand side of the chart. For the full year of 2012, GAAP earnings were $2.60 per share compared to $4.02 per share. And remember that in 2011, GAAP earnings included the $1.16 per share associated with issues related to the Texas capacity auction order.
Operating earnings in 2012 were $3.09 per share compared to $3.12 per share in 2011. In addition to the items that explain the quarterly differences between operating earnings and GAAP earnings, similarly to the annual component, there were an additional $0.02 per share associated with costs associated with the restructuring program, and there were also $0.02 per share associated with the Turk plant impairments that was due to the Texas regulatory cap on the cost recovery for the Turk power plant.
Let's turn to reconciliations between the fourth quarter of 2012 and full year operating earnings for 2012 as well. Many of the drivers that are the -- are the same for the annual as for the quarterly, so I'll focus my results -- or my discussion on the annual component. And we'll talk on the right-hand side of the page where the annual reconciliations are focusing mostly on the larger items. If you have any questions on some of the smaller items that I don't cover or on some of the quarterly reconciliations, we can either handle those in Q&A or with the IR team.
In 2012, like we said, we earned operating earnings of $3.09 per share for the year compared with $3.12 per share for 2011. The net effect of Ohio customer switching and capacity deferrals was negative $0.23 per share, and that included the loss of generation-related margins that were partially offset by capacity deferrals of the ESP. As of the end of 2012, 51% of load in Ohio had switched and an additional 3% was in a queue waiting to switch.
Higher depreciation and amortization accounted for negative $0.20 per share relative to 2011 and reflected plant additions, as well as increased depreciation rates at APCo and I&M.
Nonutility operations and parent were negative $0.17 per share from 2011, and reflected primarily 3 items: one is the early retirement of parent debt at the end of 2012; two are lower results from River Operations associated with challenging river and market conditions; and three was the impact of losing the production tax credits at our Texas wind farms.
Let me now focus on some of the major positive items that are comparisons of '11 to '12. Rate changes accounted for a positive $0.08 per share, and came from multiple jurisdictions, including Appalachian Power and Ohio Power.
Fuel orders and other accounted for positive $0.19 per share and were due to 2 areas primarily: mostly, unfavorable fuel provisions from an Ohio order in 2011 that were reversed in 2012; and also some favorable fuel related orders in Appalachian Power that were partially offset by operating earnings components associated with the Texas capacity auction issue in 2011.
O&M was favorable $0.34 per share, and that was primarily due to cost control efforts and cost components that were eliminated in 2012 with the reversal of an Ohio 2011 order. All in all, O&M discipline in rate changes helped to offset other negative items that were comparisons to 2012 for operating earning.
Let's take a look now at normalized retail load trends for 2012. For the year we ended, total normalized retail load was down 0.8%. And for the quarter -- last quarter of last year, we were down fully 2%. Much of that 2% in the fourth quarter was described by industrial sales in the fourth quarter that were down 4.2%, and industrial overall for the year was down 0.9%. Industrial performance was driven by a large aluminum smelter in Ohio that reduced to 2/3 production in the third quarter of last year. Excluding that customer, industrial load would've been down 1.6% for the fourth quarter and would have been flat for the year.
Taking a look at residential load. It was down 1.1% in the fourth quarter and down 1.6% for the year. Decreases in residential customer classes in the East part of our system were more than offset by customer accounts in the West part of our system. Unfortunately, and this happened throughout the year, average residential customer usage was down 1.8% for the year.
Looking at commercial loads. Commercial was down 0.4% for the quarter, but was actually up 0.3% for the year. This is the first time we've had annual increase in commercial load since the beginning of the recession in 2008. For the year, commercial load growth in the East and the West and Texas more than offset decreases in the East part of our system.
Before we move on to 2013 estimated load growth that's associated with our guidance, let's take a look at some key economic indicators for the AEP system. Unemployment for the AEP service territory is at 7.3% compared to 7.9% for the U.S. average. Both the AEP East and West unemployment rates are below the national averages at 7.6% and 7%, respectively. When we look at fourth quarter of 2012 year-on-year growth in GDP, AEP was up 2.7% compared to a national average of 1.5%. AEP East fourth quarter year-on-year load growth was up 2.2%, and growth in the AEP West part of our system was actually up more than twice the national average at 3.3%.
Quickly taking a look at what's in our guidance for 2013 guidance, let's look at overall load growth. It's anticipated to be up 0.5%, and industrial load is driving much of that, estimated to be up 1.8%. We'll have more detail on that on the next slide. Residential growth is anticipated to be down 0.4%, and commercial growth is estimated to be down 0.1%.
Let's take a look on Slide 20 about some specific identified load increases that are associated with industrial load. In Ohio, West Virginia, Oklahoma and Texas, we are anticipating significant load increases associated with shale gas developments and oil and gas productions.
Incremental monthly load of 149 gigawatt hours is expected to come online between March and October of this year. This represents specific customer requests for new or increased service. Our operating companies are investing capital and working within tight timelines to meet customer schedules for requested increases in load. Most of the increase that you see here is associated with gas pumping, compression and processing, and there's some also associated with coal mining expansions that are offsetting other coal mine reductions. Overall, shale gas expansion is a fundamental positive for the AEP service territory.
Let's now look at detailed 2013 guidance. As Nick said, we've established a guidance range for 2013 of $3.05 to $3.25 per share, the midpoint of that being $3.15, and we'll do a comparison of that against actual results of $3.09 for 2012. I'm only going to focus on the major items here.
The effective tax rate in 2012 was 31%, and we're anticipating it will be 35.8% in 2013. Key drivers of this include nontaxable AFUDC being down and bonus depreciation tax benefits being down as well. Both of these items were largely due to the Turk power plant coming online in 2012. AFUDC debt equity is also down $0.16 per share, and is also due to the Turk power plant coming online in 2012.
The net impact of Ohio customer switching and customer deferrals is down $0.15 per share, and includes increased switching partially offset by capacity deferrals.
Let's take a look on the positive side of the ledger now. Estimates for O&M costs, excluding those with earnings offsets, are anticipated to be favorable $0.02 per share relative to 2012. And earnings from Transcos and the Transmission JVs are anticipated to be positive $0.05 per share. Total earnings from this category is expected to be $67 million in 2014 -- 2013 or fully $0.14 per share. This is a 56% increase over 2012 and a 133% increase over 2011 results. Lisa will give you more detail following my presentation, but the anticipated load growth from this sector is truly impressive.
Nonutility and parent operations are estimated to be positive $0.24 relative to 2012, and this reflects 3 items as well: the early redemption of parent debt in 2012; improved results at River Operations that are expected from improved river conditions and market conditions; and improvement in generation and marketing that's associated with increased contributions from our retail sales.
Rate relief net of offsets is anticipated to be fully $0.45 per share positive relative to 2012. A lot of this has to do with the Turk power plant coming online, and much of the overall rate relief has already been secured. It's something that our operating company presidents take very seriously. A key component of our capital program is to get that capital with reflected in rates. And we have a credible track record of getting CapEx invested and incorporated into rates and getting recovery of the dollars that we spend.
In summary for 2013, challenges associated with normalized tax rates and with the loss of AFUDC, as well as challenges from Ohio, are more than offset from increased Transmission Operations, increased rate relief and continued O&M discipline, as well as getting back to normal in terms of River and Generation and Marketing.
Let's take a look at where we anticipate spending our capital in 2013, and much of this is illustrative in terms of a comparison to 2012. We anticipate spending $3.6 billion in CapEx and JV contributions in 2013, as compared to $3.1 billion in 2012. We are allocating capital wisely and within our financial means to maintain our investment grade credit ratings.
Let's look at some specific categories, and I think you'll get a sense for the fact that we are moving capital around and allocating it to places where we believe we have customer desire for that capital to spend -- to be spent, regulatory support and attractive regulatory environments.
Transmission, the Transcos, which are the Transcos and the JV investment opportunities, we're anticipating to spend $747 million in 2013, up from $505 million in 2012, an increase of 48%. We believe this is sound asset -- investment in asset allocation because these Transcos have forward test years, formula-based rates and attractive ROEs. And what does that meet mean to us? It means reduced regulatory lag, an efficient investment to earning cycle and attractive earned returns. Overall, this business means to us increase in transmission investments leads to increased grid reliability for customers, leads to increased returns for our shareholders.
Nuclear spend is another place where we're increasing our investment. We anticipate spending $256 million in 2013 as compared to $180 million in 2012, an increase of 42%. $215 million of that spend is associated with Cook lifecycle management that you heard Nick talk about. More than 80% of this spend in lifecycle management has been or will be preapproved with -- and will be recovered in trackers or formula-based rates with authorized returns anticipated to be greater than 10%.
New generation spending, as you'd anticipate, would be down as we brought the Turk power plant and the Dresden power plant online, and we're anticipating spending some of those dollars that we've been spending on new generation on environmental spend. A vast majority of that environmental spend is going to be spent in regulatory -- in regulated companies with constructive regulatory environments. Nick talked earlier about how we've modified the environmental spend between now and the end of the decade, how it's gone from $6 billion to $8 billion estimated, now down to 4% to 5% (sic) [$4 billion to $5 billion] estimated. A lot of that was associated with projects that we've canceled for economic or other reasons, Big Sandy, too, have been associated with environmental spend that's been pushed out because we found other ways to be compliant during this part of the decade, so we can push some of that spend farther out, perhaps in the next decade. And a lot of it's associated with a very thorough approach that we've had to testing and evaluation of technology. All of this has been designed to arrive at the most economic and efficient approach to compliance, while keeping the impact on customer rates low.
You've heard us talk a lot over the years about asset allocation and capital allocation. It's something that we take very, very seriously. We work hard year round as an executive management team to work with our operating company presidents, to work with our business unit leaders, to focus on getting capital to work where customers want it, where regulators support it, where we have attractive returns and reduced lag. And I think you'll see moving dollars into Transmission, into nuclear and into the regulated environmental component are all putting dollars to work where all 3 of those things are taking place. We take it very seriously, and will continue to do so.
So earlier this morning, you heard Nick articulate the 4% to 6% earnings per share targeted growth rate that we have, and I'd like to provide some detail on how we anticipate getting to that growth rate. We anticipate spending over the next year in -- incremental cumulative net increase in regulated net plant, property and equipment of $7.5 billion. That represents an increase over those 3 years of 6.9% on a compound annual growth basis. We're making the regulated investments. We're getting them into rate base. And we're earning reasonable returns on equity on this spend.
Let me take you through the 3 major categories that we've highlighted here, the first being the regulated vertically integrated utilities wherein we anticipate spending $4.4 billion over the next 3 years or 59% of the total. This is the CapEx that we put to work to keep lights on, to serve new customers, improve reliability and do things like the lifecycle management at the Cook nuclear power plant. We have largely supportive regulatory environments. In addition to base rate cases that we'll always be going in for, we'll have trackers associated with reliability and environmental spend, as well as trackers for a lot of our Transmission spend at a number of our jurisdictions. We invest in the infrastructure for the benefit of our customers. We earn a return on the capital for the investors that make that capital available to us.
The second major category where we'll be spending capital is in wires-only companies, where we'll be spending $1 billion of the total $7.5 billion or 13% of the total. This is 2 jurisdictions primarily, Texas and Ohio Wires. In both, we have favorable mechanisms for updating the rate base in generally supportive regulatory environments. In Ohio, we can recover the Transco investments through a rider with attractive returns, and we can get distribution investments recovered through a rider that has minimum regulatory lag and an ROE of greater than 10%.
In the Transmission Holding Company category, we anticipate spending about $2.1 billion over the 3 years or 28% of the total growth that we're talking about. Lisa will provide the detail later, but these projects either don't need approval, are approved and they have formula-based rates, forward-looking test years and attractive returns. In all, when you look at where we're putting these dollars to work to support the 4% to 6% growth, we're putting it to work in regulated companies, in regulated properties for the benefit of regulated customers with the support of positive regulatory environments. It's this way that we intend to grow the company by 4% to 6% earnings per share over time.
Okay. So we've given you some detail on the earnings. We've given you some detail on the CapEx and how we intend to grow earnings over time. Now I'd like to spend a few minutes talking about how we intend to support this growth within the means of our balance sheet, cash flow and credit metrics.
Let's take a look at a particular area where I think we stand out relative to our peers, and that's in terms of qualified pension funding.
Over the last 3 years, we plowed $1.15 billion into our qualified pension funding between -- from 2009, we've moved our qualified pension funding from 74% to, as Nick said, at the end of January, 93.7%, all during a period of volatile equity markets and declining discount rates. As we've approached full funding, we've also derisked the asset portfolio of the qualified pensions. We now stand at a percentage of fixed income to total assets of 50%, with a goal of greater fixed income weighting as the funds improve. And to help protect against decrease in interest rates, the duration of the portfolio has been matched to the duration of the liabilities. In addition, in 2012, we offered lump sum payouts to term-vested employees, and were able to decrease both the assets and the liabilities of the qualified pension by $80 million.
Nick mentioned that we did make some changes to our retirement medical benefits for current employees in 2012. And by doing that, we were able to reduce our OPEB liability by $460 million or 21%. We anticipate that the combined pension and OPEB costs to decrease 2012 to 2013 by about $60 million pretax. It's clear that the management and the board of this company has seen the impact that volatile equity markets and declining discount rates can have on our pension and OPEB values. We've taken proactive steps to help reduce the exposure to our balance sheet and earnings while at the same time, maintaining our commitments to our current and future retirees.
Let's take a look at AEP's overall financial strength. Liquidity at the end of 2012 stood at about $3.1 billion. It was supported by sources of liquidity of about $3.5 billion that were primarily funded by our revolving credit facilities, and we had uses of that liquidity of about $400 million, which was primarily commercial paper to get us to the total of $3.1 billion. On February 13 of this year, we repriced, resized and extended our revolving credit facilities. So we increased total capacity from $3.25 billion to $3.5 billion, and we pushed the maturities of those revolving credit facilities out 1 year, so they now have maturities in the summer of 2016 and 2017, respectively.
We also obtained a 27-month unsecured delayed draw term loan facility associated with maturities that will happen at AEP Ohio in the near term and that will support our recapitalizations of AEP Ohio and AEP Genco. I know many of our banking partners are listening on the phone and are here today. I'd like to thank them for their support in these facilities and these renewals and extensions that we've had and let them know that their faith in this management team and this company is well placed. So thank you so much. We do have ample sources of reasonably priced liquidity, and like I said, very, very supportive banking relationships.
On the credit metrics side, we have solidly B credit metrics. We are committed to maintaining our investment grade credit rating. In September, S&P completed its review of AEP's credit and maintained the company's business risk profile at excellent -- as excellent. In the recent past, in the last 10 days, Moody's has recently reaffirmed the ratings of 4 of our key operating companies, and they've highlighted the generally supportive regulatory environment that we have and the need for upcoming rate cases, which we've talked to you about in some detail.
Our balance sheet is strong. Our credit metrics solidly support the BBB corporate credit rating, and management has demonstrated a commitment to maintaining solid investment grade credit ratings. That commitment is unwavering and continues to go forward.
So we've talked about earnings. We've talked about growth, capital allocation and all those things. And I think the obvious question many of you might have is, how are you going to finance the growth that you're talking about? Nick identified earlier today that we anticipate spending $3.6 billion in CapEx in 2012 (sic) and $3.8 billion in each of 2014 and 2015. On this slide, we've laid out cash flows from operations, required capital needs. And what we're highlighting here is cash inflows over the next 3 years.
Significant cash inflows are going to come from bonus depreciation, and we've laid that out on the slide. And then we're also anticipating significant cash securitizations in addition to some of the equity inflows that we anticipate from just the regular DRIP and the employee 401k program. Altogether, over the next 3 years, those 3 items are going to bring in $2.4 billion of cash that we can put to work growing this company.
We are committed to maintaining those investment grade credit ratings. With the cash that we have coming in, we fully believe we'll be able to do that. If things change going forward, we're not with our back against the wall. We can modify our CapEx plans, whether it's on the transmission side, whether it's in the wires-only side or whether it's in our integrated utilities.
We've not accounted for in this future bonus depreciation. Congress seems to keep re-upping that because it scores very well in the budgeting process. And we've not put on here securitizations that could happen going forward, and there are some of those that are on the horizon, but they are speculative enough now so we've not put them on the chart. So there are pluses and minuses that we can make to this plan as we move forward. But against the backdrop of the cash flows from operations, the strength of our balance sheet that we have going into this incremental spend that we have and all of the cash that's coming in from those 3 items that I mentioned, we're very confident in our ability to fund this growth and this capital expansion without having to issue incremental equity during the 3-year period.
Let me try and wrap things up here as quickly as I can. Nick talked about some of the operational and financial strides that we've made over the last year. On the operational side, bringing Turk and Dresden online, the safety accomplishments that Nick identified, as well as getting some difficult but workable orders in Ohio that allow us to transition to restructuring as we go forward. On the financial side, we had both completed and in-flight securitizations, the refinancing of the parent debt and all of the progress that we've made in terms of funding the pensions and the OPEBs.
You've heard us talk about capital allocation. We talk about that as a management team all the time. We spend a huge amount of our time and effort on that, and we're doing what we said we're going to do. We're going to put capital to work where customers want it, where our regulators support it, where we have reduced lag and where we have attractive ROEs. We've been doing this. The investment review committees are focused on it. We're going to continue doing this. And you've seen from our 2012 to 2013 comparison, it's working.
We have a strong balance sheet with strong investment -- with solidly investment grade credit metrics and a commitment by the management team and the board to maintain those. Like I said just before, we don't anticipate incremental equity needs to fund the capital plans that we're going to put in place over the next 3 years.
Nick identified a targeted dividend payout ratio of 60% to 70% of earnings. This is fully supported by earnings from our regulated operations. And we anticipate a 4% to 6% earnings growth rate supported by investment in our regulated operations, as I laid out some detail for you previously.
In all, we have a healthy American Electric Power. We're providing a vital service to our customers, and we're providing a total return proposition to our shareholders of 8% to 10%.
With no further ado, I'll turn it over to Lisa Barton, who will take us through her plans for how she intends to grow the transmission part of our company. Thank you.
Lisa M. Barton
Can you guys hear me okay? All right. There are 3 items in particular that I'd like to cover with you today. First and foremost is to summarize our 2012 performance and talk about how that performance will really position us for the future. Secondly, I'm going to highlight the breadth of our transmission investments, basically give you a breakdown of the projects that make up our long-range plan, and these are the projects that are really going to propel our growth in the future. And finally, I'm going to address the subject of FERC ROEs and incentives and review where our performance has been in that space.
So 2012 was an extremely positive year for AEP Transmission. Our earnings were 50% higher than they were in 2011. We secured approval of our West Virginia Transco. And why that is so crucially important is because that serves as the foundation for our Transco growth. As you may recall, AEP Transmission Holding Company is the parent of our state-based Transcos, ETT, ETA, our project-based joint ventures, as well as our new competitive affiliates with Great Plains Energy, Transource.
Our Transcos ended the year with $373 million of plant in service with a net PP&E of $744 million. In 2013, we're projecting to have $770 million in plant in service with a net income of $47 million. ETT reached $880 million in 2012 and is on target to be self-funded in 2013, with a projected income of $25 million. And that represents AEP Transmission's Holdco share in that investment.
Some of the things that we're particularly proud of in 2012 is the fact that we were able to be ahead of target in terms of our in-service assets, and this was during a time where we had both our own crews as well as the contract labor crews that we rely so heavily on to get our assets in service, deployed to the restoration efforts in the East in support of the damage caused by Sandy. One of the things just to note in the transmission businesses is that our outage windows to really get these assets in service are often in the spring and more often in the fall. So fall is a crucial time for us in terms of deploying capital.
In 2012, we also secured $1.7 billion worth of new investment opportunities through the 3 RTOs that we are currently operating in, $1.25 billion of which is in PJM alone. And as Nick mentioned earlier, the transmission system is very much the backbone of the grid. This allocation of the $1.25 billion is very much tied to the region-wide retirements in PJM, which would be about 14 gigawatts between now and 2015.
In 2012, we also deployed new technology and improved our standardization, basically with the intent to improve our ability to move capital more efficiently, deploy it more efficiently to meet in-service dates. And the in-service dates, we really needed to speed up to address the growing shale gas loads that we're having in our territory. It's no longer a situation where you can say to the customer that will be -- it'll take us 2 years to get you interconnected. We really have to do that in a very short period of time. So we used a number of technologies to make that happen. We also use it to manage our RTO outage windows, as I mentioned earlier; those are critical to our success. And finally, to reduce costs to our customers. Aggregating our growth under the AEP Transmission Holdco is providing greater visibility and transparency for these investments.
On Slide 31, I'm going to talk a little bit about what our outlook is with respect to transmission. Certainly, diversification was key to our success in 2012. We're managing a large number of projects in a number of states. And what this slide attempts to do is to really break down that growth for you.
So in our long-range plan for our transmission investments that we have across our system, and so this includes everything that we're doing in ETT, the Transcos, as well as the operating companies, we have nearly 500 new or enhanced stations, just under 22,000 MVA of new transformation capacity, nearly 2,000 miles of new transmission lines and just under 4,000 miles of rebuilt transmission lines.
This really makes us unique. I'd really like to pause here for a second because we are -- we do not have a portfolio that is reliant on a small handful of projects. We have a portfolio that is spread really across the 11 states that we serve, as well as Missouri and Kansas where we have our Prairie Wind project as well as our Transource development efforts. So we're not as susceptible to that individual project risk that you might see if somebody has issues with getting siting approval and things like that. As Brian mentioned earlier, these are 2 approved projects, they're projects that are completely under our control, meaning that execution is also within our control. This, coupled with the diversity of the portfolio, puts us in a very strong position for executing well in 2013 and beyond.
From a local reliability standpoint, we're replacing a lot of our obsolete voltage classes, the 46 kV system, the 88 kV system. And as you probably have heard, not a lot of people are talking about those voltage classes anymore. These rebuilt lines really serve as the ability to better serve our shale gas loads that we're seeing all across our territory, as well as improved local reliability to our operating company customers.
We have the largest transmission system in the country. Again, as Nick mentioned earlier, this is the backbone of our system. It's going to fuel our investment opportunities and provide benefits to our customers as well as earnings growth for our investors.
On Slide 31, I really wanted to pause for a moment and talk about FERC returns and incentives. Certainly, it's been depressed for quite a bit over the past month or so. And as you can see, our transmission company ROEs, these are for our Transcos, are pretty much in the middle of both the PJM and SPP ROEs. One thing to note about our ROEs is that they were either approved or settled within the past 5 years. So they're fairly recent ROEs. They were all calculated under the current median methodology that's applied by FERC to single-entity developers.
One thing to keep in mind is that there are 2 types of filings. There are utility-triggered filings, which are 205 filings, and that's where the utility basically seeks to set or modify an established rate. In those cases, the burden of proof is on the utility to set the rate. The second type is, of course, the 206 complaint, where a third party basically needs to establish that the rates are unjust and unreasonable. And so the one distinction that I think is important in this space for folks to keep in mind is that this process can, in essence, result in different outcomes based on who has the burden of proof in those cases.
But I think one of the things that's most important to remember when we think about FERC is that FERC is open to utilities modifying their rates. You can go in at any time after you have an established rate and modify that rate. This, coupled with FERC's track record of supporting transmission, makes us comfortable with investing in this space over the long term.
I'd like to talk a little bit about incentives and where we are positioned in that space. So FERC provided greater clarity with respect to their position on incentives with their recently issued policy statement. And in that policy statement, they said a couple of things. They basically said that they expected utilities to pursue non-ROE incentives first, things like abandonment, things like return of construction work in progress, hypothetical capital structures. And then they said you really need to tie the incentive to the individual project risk, not the company's risk, the individual project risk.
And they also indicated that they would view favorably incentives that were tied to developers who sought to contain project costs. And what was interesting is in that policy statement, they actually referenced the AEP Exelon project, RITELine, where we basically tied incentives to the forecasted cost of the project at the time of RTO approval.
So what does this mean for us? It basically means that we have a proven track record with respect to incentives. We view credibility as the key to that success, not only for the investment community, but for our dealings with our regulators, including FERC. Without credibility, you really don't have anything.
So FERC wants to differentiate between projects. In terms of our track record, we ask for incentives only when the project risks warrant it. If you think back to the slide before, we are rebuilding a tremendous amount of projects. We are investing in thousands of miles of new projects, but there's only really a handful of projects that we've actually thought to get incentives on. And because of that, when we ask for it, we have a proven track record of getting those. Our Transource order is probably a good one to note where what we asked for, we received, and it was basically issued just before FERC's issuance of the new incentive policy.
So lastly, what I'd like to cover is the fact that we are delivering on our commitments, and delivering on them in 2012 and in 2011 was key to our success over the past 2 years. We're growing a new business, but this is by far not a start-up. AEP has over 100 years experience in building transmission. We operate ourselves as a separate business unit with nearly 2,000 employees that are dedicated to providing service to not only our operating companies, but our Transcos and our joint ventures with which we serve. So we're taking this experience and deploying it in support of transmission growth.
By the end of 2013, we'll be doubling our net PP&E to the tune of $1.4 billion. We're deploying significant capital in support of transmission, which provides benefits to our customers and earnings growth to investors. By 2015, AEP Transmission Holdco expects to contribute $0.36 towards AEP's earnings, making it a significant increase from what we've contributed in the past.
Our long-range plan is comprised of known and well-defined projects. I really can't emphasize this key enough. These are all projects that are included in our capital plans. They're all projects that we have underway. Because we have them underway, we're very well positioned to execute them; because we have these projects over the breadth of our territory and the diversity in the number, it really gives us a platform for future growth that is, again, unique to AEP.
Also, as Nick mentioned and Brian mentioned as well, these are projects that make up our forecasted earnings per share contribution. There are additional transmission opportunities on top of it. What I've highlighted is just the stuff that we've got in the pipeline right now. So additional uplift potential includes the opportunities provided by the various joint ventures that we continue to pursue, such as RITELine, Pioneer and of course, our competitive affiliate with Great Plains Energy, Transource.
In closing, we see ourselves as stewards of the largest transmission system in the country. In turn, this is fueling our need to invest in transmission and fueling what will be what we deliver to the investment community. Transmission is the resource that fuels our economy, energy markets and furthers regional and local reliability, and that's going to be the foundation for our growth over the next several years.
With that, I will turn over the microphone to Chuck Zebula.
Charles E. Zebula
Thank you, Lisa, and good morning to everyone. Let's start with a discussion of the principles that Nick has laid out for the unregulated businesses at AEP.
The first thing that Nick has talked about is to mitigate risk, and that's going to be done through our participation in the capacity markets, the retail energy markets and the wholesale energy markets, as well as how we operate, invest and finance this company going forward. The second principle is don't get ahead of the cash flows in this business. We intend to run this business with a CapEx funded by internally generated cash flow. Thirdly, conservative capitalization, maintain an investment grade look in this business. It's important in terms of how you do business with counterparties, and that must be maintained. And lastly, to make this business look as regulated as possible.
So where are we in the process? In terms of the regulatory process, Nick had mentioned that the corporate separation order is in rehearing at the PUCO. We have applications for corporate separation in before the FERC, with an effective date of 1/1/14 that we've asked for. Secondly is in terms of integration. We have generation that has operated in a 4- or 5-company pool for decades and decades. We need to extract that generation, make it competitive, combine it with a retail business that is relatively young, but also complement it with a wholesale marketing and trading business that is mature, competent and experienced.
On Page 35, you'll find a lot of information, and I'll start with the bar graph up in the upper left corner. So you'll notice 3 colors to the bar in 2013: blue, yellow and I guess, a reddish color, and they represent different things, of course. The red represents capacity that's going to retire. That's about 1,920 megawatts. The yellow represents capacity that is planned to be transferred. It's about 2,450 megawatts. That represents our Amos 3 capacity as well as the Mitchell plant capacity. There are applications to transfer that capacity to our regulated affiliates, Appalachian Power and Kentucky Power. And of course, the blue represents the residual capacity, if you will, that will remain in AEP generation resources. That's about 8,900 megawatts. So 2014, the transferred capacity disappears, right. And in 2015, there will be retirements of the remaining capacity in red.
So for the 8,900 megawatts, if you look now down to the pie chart, that represents the fuel profile for this business. You'll note that 65% is coal, it is predominantly controlled; 35% gas. There's combined cycle and combustion turbine capability. There is a small run-of-river hydro unit that's on the Ohio River. And it spans the capability, the operational flexibility, baseload, intermediate and peaking capacity, with the Darby combustion turbine units, representing about 6% of the capacity.
Moving on to the map. In real estate, it's all about location, location, location. And really, from a field perspective, it really is about location, especially when you're dealing with coal. And if you start in this map at our Cardinal plant, which is located in Wheeling, West Virginia, get on a boat and take a ride down the Ohio River till you get to Louisville, you will pass 4,600 megawatts of coal capacity that is located on the river. And you got to be looking at the Ohio side. Don't look at the West Virginia side because you'll be looking at other plants.
So if you look at the Ohio side of the river, you'll see 4,600 megawatts of capacity. That is basically AEP generation resources. The backbone is the river, right. The river access gives us access to a wide variety of fuels that are available on the river. The plants have much flexibility in the kinds of fuels they can burn, and it has the great advantage of transportation by the river and barge industry.
Moving into the other coal plants. Our Muskingum River plant, which is turned green. It's because that plant, our Muskingum River units 1 through 4 will retire, they're part of the 1,900 megawatts, and Muskingum River 5 is under consideration for a refueling to natural gas.
And just east of Columbus, Ohio, our Conesville plant. That plant is served by rail, the Ohio Central Railroad goes into Conesville. It's about 1,140 megawatts. It's dependent primarily on local coal sources. It's a rather difficult coal location, and it's much more expensive to source coal and deliver coal into this rail-served plant than the plants on the river that we talked about earlier.
On the gas plants, our Lawrenceburg plant in Indiana near Cincinnati, it's is about 1,200 megawatts. Our Waterford plant in Southeast Ohio, about 840 megawatts. All on good pipeline capacity locations. Also, the Darby plant in Central Ohio is fired by 100 combustion turbines, 12,000 Btu/kWh heat rates, provides peaking capacity as well for the portfolio.
The next slide, on Page 36, represents where these plants stack up in terms of the current market conditions that we are in, and if I could spend a time just talking about the graph. You'll note that this is a supply curve of the capacity versus its fuel and consumables cost, the cost to run the emission control equipment. And the lines represent basically where the off-peak market is, the around-the-clock market and the peak market. Basically, the peak market is around $40 average, around-the-clock in the mid-30s and the off-peak in the high 20s. And you'll note that about 4,600 megawatts is at or below the off-peak line, which represents all of the river-served coal plants.
Not only do the river-served coal plants give you great locational advantage for delivering coal, they're also advantaged to delivering the consumable materials that you need to run the environmental equipment: the limestone, the lime, the urea. All the things that we need to deliver into the plant to run the environmental equipment are also delivered by barge. In between the off-peak and the around-the-clock line are the intermediate units representing the combined cycle capacity, as well as the rail-served coal plants. And of course, at the top, above the peak line, are the peaking capacity plants, the Darby plant we talked about earlier.
So the generation from this fleet, expected to be in the range of 40 to 45 million megawatt hours against the current market conditions. That puts coal capacity factors in the low 60s to mid-60s; combined cycles in the 40% to 50% range; the combustion turbines, 3% to 5% range, for a total capacity factor for this fleet in the mid-50s range. So it's very competitive, and it is about location.
Turning to the next slide. It's a rather busy slide, but it's important to understand this slide to understand the revenue opportunities available to the new company as we go forward. So let's start with the row that says capacity and go across the timeline. As you will remember, AEP and its regulated affiliates, for many years, participated in the FRR capacity markets, and PJM was a self-provided capacity market. And that obligation goes through May 31, 2015. While if corporate separation occurs on January 1, 2014, AEP Generation Resources is obligated to provide that FRR resource back to the regulated affiliates as -- to meet their requirements in PJM. And that revenue will be determined according to the recently issued ESP by the PUCO. That's the $189 per megawatt day, the RSR payment. Those revenue streams are available to AEP Generation Resources for providing that FRR capacity back to the regulated affiliate.
Then on June 1, 2015, you'll note that the box turns blue. Blue basically represents market exposure. And those assets were bid into the PJM RPM market in the last auction last year. They did clear the market, and they'll be participating in that market going forward as well.
Moving to the bottom box, which says off-system energy, when you look in 2013, it says BAU, business as usual. The 4-company pool is still in place. Basically, the generation in Ohio is still participating in that 4-company pool, and off-system sales are calculated or results are recorded as they always have been historically at AEP.
When you get to 2014, AEP Generation Resources, as its own company, still has the obligation to serve energy to customers who haven't switched from Ohio Power. And then the excess energy that's available can be sold in the retail and wholesale markets. And the energy we provide to the AEP Ohio customers will be covered according to the fuel clause that has been in place and is referenced to in the ESP.
When you get to 2015 and beyond, all of the energy is available to sell in the retail and wholesale markets for AEP Generation Resources.
When we look at the revenue opportunity in 2014 against capacity revenues and potential energy margins, we believe about 80% of the revenue opportunity or gross margin has been determined. And when you get to 2015, between the FRR obligation, the RPM capacity and the energy opportunity, we think about 60% of that gross margin opportunity has been determined.
Moving through the line that says SSO load -- you switched too quick, Julie. I should point out that there are actually 4 auctions that will occur. A 10% auction that will occur this coming year. It will likely occur in the third quarter. That's a 10% slice of system auction. In 2014, there will be 2 incremental 25% auctions, bringing a total for a 60% slice of system. The remaining energy or customers that are at AEP Ohio are auctioned. And then in the summer of 2014, the remaining 40% will be auctioned effective January 1, '15. So all of these auctions cumulatively have a delivery date through May 31, 2015.
So one of the questions we've been asked is where do we plan to place this energy. As I talked about earlier, this fleet will produce about 40 million to 45 million megawatt hours. And in 2014, it's pretty clear where these opportunities are going to be placed. The first tranche is what we call competitive retail customers. As you know, we've been active in the retail markets, particularly in Ohio. We think about 25% to 30% of that 40 million to 45 million megawatt hours can be placed in that market. Last year, we served 7.5 million megawatt hours. About 60% of that was in Ohio. We are focusing on that opportunity as we roll into next year. The next tranche up is the unswitched AEP Ohio customers. That's what I talked about earlier. That's the load that we still need to serve and provide energy to those customers according to how fuel will be recovered in the fuel clause.
The next 2 boxes up represent our participations in AEP Ohio auctions, as well as other auctions throughout PJM, muni and wholesale customer load, as well as financial instruments that we may enter into in order to hedge the output. And then lastly, a block on the top, that is short term. That could be the hedge, spot, balance of month. It could be balance of year, depending on the opportunity and where we see opportunity. So we're looking at a portfolio of options to place those megawatts -- megawatt hours into the various markets for next year. So when you get into 2015 and '16, this will look a lot different because the unswitched, the SSO load will go away. We'll have additional opportunities between the retail and the wholesale markets. And we are focused on opportunities longer term so that we can deal with muni and co-op customers as well. This is a relationship business dealing with muni and co-op customers, something that AEP has always had a good-standing reputation. And really, credit quality is extremely important on both sides of that equation.
These markets tend to have a lot more activity when there's some urgency in the market from the perspective of rising capacity prices, maybe an expansion of the heat rate complex, maybe fuel volatility, because this is a rather risk-averse group and they like to contract for some period and take the risk off in that manner.
So in the past, we've historically served several thousand megawatts in this category. And just a couple of weeks ago, we extended a contract with 7 municipal customers in the Midwest into the 2018 timeframe. So this is representative of what we believe will be a continued risk aversion sought by that group, and they are ready to do business with a willing and reputable, creditworthy counterparty like AEP.
Also, in our deregulated book, there are several large muni deals that we have in that are currently backed by market purchases. So this market is available, we dedicate staff to it, and we're very focused on it as well.
So in summary, on terms of the energy sales opportunity, there really is a portfolio approach, looking at both the retail and the wholesale markets, seeking an optimum result that will align with our goals and our appetite for risk, as Nick has laid out for us.
On the right side of Page 38, just a few comments about AEP Energy. AEP Energy is our competitive retail electric supplier. In 2012, probably, the marquee event was the acquisition of BlueStar Energy. BlueStar Energy is based in Chicago, Ohio. We run our retail group still out of Chicago. In 2012, they served 168,000 retail customers. As I mentioned early, we served about 7.5 million megawatt hours in 7 states, primarily focused in Ohio, where the retail markets have opened up considerably. It has been profitable in its first year. And it's important because all of the retail activity currently has to be backed up by market purchases. Clearly, as we go forward, one of the objectives will be to not back that with market purchases but, of course, back that with our generation as we go forward. About 87% of that load was in the C&I space and 13% in residential.
So the 2013 plan is relatively simple for AEP Energy. It's really focused on the margin opportunity. As Nick mentioned, we're not looking to be a national player in retail or some grand strategy to be the biggest retailer out there. But there is margin opportunity that is greater than you can observe in the wholesale markets, and that opportunity is important in this low price environment. So providing that hedging opportunity for the generation is extremely important, as well as we'll focus on growth in our traditional footprint areas where AEP has traditionally done business, the likes of PJM and the Midwest.
Turning to the next page, capital expenditures and environmental control profile. So the chart that has a lot of green, I think we probably ran out of green ink when we printed this. But green is good. And when you look at this lineup of our coal-fired power plants across the top, the first row represents our investments in NOx controls. All of the units have SCRs, except Conesville 5 and 6. No SCR is currently planned at that unit because we believe we can comply with the current rules without making that investment. SCRs began to be built in 2001. Particularly, the first one that was built here was Gavin, so we have over a decade of experience in terms of operating this kind of equipment. And those SCRs were primarily built for the NOx SIP call. For those of us who've been around for a while, remember that in 2003 and '04. And later, for the CAR rules, where some of the other additions were added.
Moving to the next row, represents our SO2 controls. All of the units have FGD, except for Muskingum River 5. Some of these are newer FGDs, such as at Cardinal, Conesville 4, Stuart and the OVEC capacity. I believe they all have JBR retrofits on them. Yes. And the other scrubbers at Gavin, Conesville 5 and 6 and Zimmer were made in the early '90s, and actually, at Conesville, in the late '70s. Those scrubbers were built either for NSPS requirements or for the Clean Air Act amendments of Phase 1 requirements that went into 1995 for SO2.
Moving down to the mercury and particulate line, you'll notice a yellow on Gavin. On the scrubber dewatering circuit at Gavin, there are centrifuges that are not quite as good as bell presses in terms of giving the quality of effluent you need to meet the requirements of HAPs MACT. So we may need to do some additional polishing in that step, either through some polymers or chemicals or some ACI investment as well. At Conesville 5 and 6, we do plan an ACI investment as well and are looking at deeper washing coal there as well. And at Muskingum River 5, there's an opportunity for us to refuel that unit with gas. It's a discretionary investment, and we certainly will only make that investment if the market is willing to reward us for that investment.
In terms of the average CapEx for this fleet, over the 2014 to '16 time frame, we think that it needs about $180 million per year average over the next 3 years. That's an annual amount per year. About $100 million of that is ongoing maintenance CapEx in landfill extensions, and about $80 million of that is environmental. Most importantly, we think that the ongoing capital requirements in that period are funded by internally generated cash flow.
Turning to the next slide, in terms of finance, there are really only 3 words that I have to say here. One is conservative. And by that, I mean conservative capitalization, 60% to 65% equity layer and maintaining an investment-grade look, although we have no current plan of getting the unit initially rated. The second word is transitional. As Brian mentioned, the transitional financing is in place. The $1 billion 27-month term loan is in place. That will be used to fund Ohio Power maturities. And basically, the permanent financing at AEP Generation Resources will fund the takeout of that bank loan sometime before the 27-month period is up. And lastly is adequate. And by that, I mean adequate liquidity. There's a deliberate plan to upsize our credit facilities by $250 million, the last time, and the time before that, an incremental $250 million, basically a $500 million adder to our credit facilities to basically fit this business and its collateral needs into the liquidity requirements of the company.
So what have I told you today and what are we focusing on? Really, it's about integration, integrating these generating assets with, again, a relatively young retail effort but a mature, experienced wholesale marketing and trading team, consistent with the operational goals, the financial goals, the credit goals that we have as a corporation and certainly aligned with those corporate objectives.
This year, we're actually focusing on the things we control. We're not running the generation in an unregulated market today, but we're focusing on the things we can control. I can't control the capacity markets. I can't control gas prices. I wish I could. But nonetheless, the cost profile at the plants. Mark McCullough and his team are doing a great job looking, as Nick had mentioned, through some of the lean processes and looking at how we do the work, what it cost to do the work and making a concerted effort to make sure that these plants, from a cost perspective, can be competitive in the market.
Certainly, we can control how we invest in these assets and how we operate them. There's opportunities to think about minimum load and how much minimum load you can run during the off-peak period. Those are important things that we're looking at in terms of how this fleet may need to operate differently in the competitive market. We're obviously focused on the fuel and consumables contracts; the energy sales opportunity; again, that portfolio approach focused on both the retail and the wholesale opportunity in the area where we do business; our service company cost; how much cost or how much service do we really need from the service company as we move into the unregulated affiliate; and of course, the financing and capitalization plan that I mentioned earlier.
So I know all of you are very interested in this business. And we certainly -- as information continues to become available, we're certainly willing to continue the dialogue and disclosure with you as we march down this path in this business.
So with that, I'll turn it back to Nick, who will wrap it up. Thank you.
Nicholas K. Akins
Thank you, Chuck. Thanks, Lisa, Brian.
Now I hope that you've heard the story today about the things we're trying to achieve from a growth perspective. But I also trust that you sense the depth of our management team. These people who are working on these major initiatives for our corporation are stellar people that can really get the job done, and they will. So to wrap up the activity this morning, certainly, we're a clear regulated business model. I think that's happening over time. We're going through the corporate separation piece now, but we've done a lot to reinforce the foundation of this company in terms of a strong balance sheet. We have a competitive path that's cleared out for us in Ohio, and we don't anticipate any equity needs associated with the capital reallocation that's occurred over time. And we also, with a 4% to 6% earnings growth, primarily driven by transmission but our regulated business as well, is clearly a positive for AEP as we go forward. This management team has been proven as battle-tested over the last year. We've been through a lot of issues, and I'm sure when we review the 2012 list of things that we've clarified, it has been a process where this management team has grown closer and are really focused on making sure that now we can reinvigorate our sales to focus on growth. And it's actually a good position for the AEP management team to be in and a good position for the AEP shareholder to be in.
So again, thank you very much for your time, and we'll entertain questions at this point. Brian, if you'd like to come up, and then obviously, we have the others here to answer any questions if they become too specific.
Nicholas K. Akins
Okay, any questions?
Just on sort of on the post -- after this year, 2014 and beyond, when we're looking at the regulated strategy -- I'm looking at Page 48 and Slide 23. And when you look at sort of where your earned ROE is and your authorized ROE is, how should we think about how you're going to be growing that business? I mean, it seems like it's a regulated growth strategy. I'm just trying to get a sense, will you guys be going in for rate cases? Will this -- will you be filling it in through O&M or something? How should we think about the 4% to 6% growth in light of sort of the ROE environment? And if you could just elaborate a little bit on that. I just wasn't completely clear. Excluding transmission, which I think you guys explained very well.
Nicholas K. Akins
Yes, so obviously, we target ROEs continuing to be north of 10%. And as well, the invested capital that we have through this -- the PP&E graph that we showed, those are legitimate investments that Brian went through that, really, in my opinion, is block-and-tackle spending with good opportunities for regulatory recovery. And historically, we've recovered those very well. The thing we have to work on, obviously, is being closer from a coincident standpoint of recovery. And that, of course, we're working on in those various jurisdictions. We have a multitude of trackers of deferred type of expenses that we can recover in the future. And the regulatory situation in each of the states is such that we're going through a repositioning exercise that keeps our O&M flat, and that's more of an opportunity to continue with capital investment, and the rate impacts are mitigated as a result. Brian, I don't know if you have anything to add to that.
So just to sort of understand this, I mean, in other words, you guys are in a regulatory environment where we're not probably going to be, at least for some of these situations where you seem to be earning above the authorized, where those are going to be reset. Or I mean, is that how we should think about it? Without going obviously into -- you guys have so many jurisdictions, it would take all day, but just sort of -- is that sort of how we should think about it in terms of...
Nicholas K. Akins
Well, that's the strength of the diversity of the system. You see the Western properties as you see a higher return on equity in those areas, but it's because of the timing of rate cases and the investment of capital. So we'll continue to invest in those jurisdictions. You'll probably see those come down a little bit. You'll see O&M and others come up as a result, and the overall return across the corporation will still be north of that 10%.
Okay. Then just in terms of the transfer, the Genco transfer into regulated, what's the sensitivity can you give us if, in fact, worst-case scenario, that just doesn't happen? Let's say, for whatever reason, they don't want them. How should we think about the sensitivity towards the ongoing earnings growth if, for some reason, that pending regulatory situation doesn't go out as planned and it isn't transferred into a regulated asset?
Nicholas K. Akins
Well, keep in mind that these companies are already paying for that capacity. They already have a call on that generation. So a distinction, I think, for AEP is, for APCO in Kentucky, since they are paying for that capacity, it's merely a transfer at net book. And we can demonstrate and have demonstrated in the cases that those transfers are positive for customers in the long term. So I don't sense a big issue when those particular jurisdictions -- the plant is located in West Virginia. And certainly, from a Kentucky perspective, they need the capacity, and they're very interested in coal. The coal comes from Kentucky and APCO-related mines. So there's more to the equation than just thinking about are we trying to transfer a plant from out of state into those various jurisdictions. So I don't even get to that second point of the premise of your question. But if that were to happen, certainly, we'd have to deal with it on the unregulated side, just be more that we have to hedge, but they're going to need capacity. So unless they want to leave themselves open to the market, which typically, those jurisdictions have not done because we're clearly still FRR in those jurisdictions, then we'd have more opportunities to sell that capacity, and it could be a PPA. But I don't see it going in that direction. Brian?
Okay. So in other words, you see it so unlikely that you don't want to give us any sense? I mean, really, this is so unusual, it's such an outlier situation that we shouldn't have to worry about it, I guess. So I'm just wondering, is there any sensitivity we should get to? I'm just wondering, you're sort of applying for this. Just wondering what the range of outcome could be. I'm not suggesting that's likely. I'm just wondering...
Nicholas K. Akins
Yes, we don't see that happening. Obviously, a part of the discussion will be what the transfer price would be for the assets and those types of things. But even the net book that we show for the transfer of those assets is a positive benefit for customers. And clearly, I mean, look at Big Sandy, for example. If we put the scrubber on Big Sandy, it'd increase rates in Kentucky Power by 30%. But by not doing that and this capacity being transferred over, it's an 8% increase. So it's those kinds of things, I think, that you're measuring against. So I'm feeling -- I continue to be confident that we'll be able to transfer those assets.
Two questions not really related to each other. First, on the earnings bridge slide, the $0.45 of rate relief, if I gross that up for taxes and then kind of just multiply it by your share count, it's about $300 million, $325 million or so on a pretax basis. Can you just walk us through what the biggest components of that $300-plus million of rate relief is? You said most of it's already been granted. I'm just looking for the big move-the-needle items.
Brian X. Tierney
Certainly getting Turk into rate base are large components of that. What we talked about in terms of I&M and the recently completed rate case there is a large component of that. In Ohio, the rate stability rider is a significant component of that. And like I said, a lot of it's associated with Turk coming into play. So it's a formula base rate extension in Louisiana. Those are primarily it. It's Louisiana, Texas, I&M and Ohio and all those components you're familiar with, Michael.
Okay. And I'll follow up off-line. The second question and this may be a Lisa one. We're seeing in other jurisdictions, like New England, like in Colorado, a regulated jurisdiction. We're seeing 206 complaints at the FERC regarding base ROEs. Just curious, haven't seen that yet in the SPP, haven't seen it yet in PJM. It's coming, right? I mean, the intervener groups all talk to each other, so it's just kind of a matter of time. Just curious for your high-level viewpoint of how that plays out over time.
Brian X. Tierney
Yes, and certainly, there's a difference in the burden of proof, a 205 versus a 206. And Lisa, you may want to comment on this question, please.
Lisa M. Barton
Sure. A lot of what you're seeing also is the fact that some utilities have entered into agreements with their states to go in annually. And I think PG&E fell into this category, so they have to go in for a 205 filing every year, which gives the commission staff an opportunity to launch a 206 to kind of get that debate going a little bit more lively. I think one of the things to just keep in mind is the fact that, anytime you hear stuff like what we heard in New England about what FERC's staff was saying, they are very much like an attorney general intervener. And so they are kind of anarchists in the midst there. And it is the commission who would ultimately decide on what is that range of reasonable. So that range of reasonable is still very broad, and you saw that in the New England proceeding. So it's really going to be up to either what the utilities decide to settle on, or it will be based on what the commission determines. But again, I think the good things are that FERC is very open to a reopener. Or alternatively, if you're hit with a 206 complaint, you can also sit there and agree not to go back and therefore, maybe settle a higher ROE. Ultimately, it's going to depend on where do long-term interest rates go because the longer that they stay at a lower level, the potential for more pressure on that. But it is very time-sensitive. If we were to go in with -- we have one that's currently before FERC right now with Transource. If we went in 6 months from now, that number would be very different. We really only have 2 interveners, for example, in that case, and that is an SPP case.
Nicholas K. Akins
I think the key for us is the focus on no-regrets transmission projects. And then secondly, if FERC continues, which they have espoused to, they want to continue with transmission investment, then regardless of what happens, they will still trade at a premium associated with the retail regulated space. So that's why we continue to be bullish on transmission.
Brian, just a couple questions on the slides to review on Page 21. Nonutility parent, the $0.24 incremental positive, can you just review again what the biggest key drivers are of that? And then I have 1 or 2 other questions.
Brian X. Tierney
Yes. it's the fact that we won't have the early redemption of the parent debt expense as we did in 2012. It's River Ops coming back to a more normal rate of earnings in 2013, and it's the Generation and Marketing increases associated with competitive retail.
Okay. My second question was on the sources and uses of cash slide on Page 26. Your target growth rate -- you haven't given an earnings guidance range for '15, but you've given a growth rate expectation. I'm just wondering how you could see earnings growth in that magnitude with CFO being relatively flat. Is there some sort of extension of depreciation rates or something else that's going on?
Brian X. Tierney
It's the fact that in 2013 and '14, we've broken out bonus depreciation. We anticipate being a taxpayer again in 2015, and that's reflected in cash flow from operations and not broken out.
But it doesn't imply a deceleration in earnings?
Brian X. Tierney
Okay. And then finally, you talked about -- I think you talked about in your comments on the slide on sales growth a significant difference in expected earnings growth from industrial in West versus East. And I see that you've got a massive amount of demand for new power gen for transmission, in particular.
Brian X. Tierney
Can you talk a little bit more about that? We see industry trends -- this is one of Paul's questions he usually asks. Sales has been -- the outlook is pretty bleak. My sense is that over time, that that's going to be very -- the regional winners and losers are going to be pretty differentiated. And with the Utica, we hope you're a winner. So can you talk about how you see sort of short, medium and long-term sales growth trends?
Brian X. Tierney
Yes, I can talk about some of that, and Nick, I'll let you fill in the blanks. So we are seeing it very much on a regional basis. As we laid out in the industrial-specific side, we are seeing a real increase in industrial load associated, in particular, with the shale gas plays, Wheeling, West Virginia, for us and in Eastern Ohio. So we are seeing expansions associated with gas compression processing in those areas. It's significant and real. We are also seeing some pretty significant increases in load in Oklahoma and Texas, also associated with gas and oil production and shale gas developments down there. A lot of that's associated with -- a lot of what that means to us is increased transmission and increased distribution spend to get new customers either expanded or hooked up as well. So those particular areas, we're seeing real spots of growth. In other components of our Eastern system, we're seeing load growth largely flat or moderately down. Indiana, the western and central parts of Ohio are somewhat challenged, as are other parts of Kentucky. So for us, this is a particular area where the diversity of our footprint really helps us diversify away from some of the decreases that we have and being able to take advantage of some of the real load increases that we're seeing associated with the shale gas developments.
Nicholas K. Akins
So Greg, my take on it is if there's an energy renaissance that includes shale gas activity, AEP's service territory sits extremely well from a fundamental perspective. I mean, as you said, you bring up the Utica Shale, you bring up the Eagle Ford Shale, we're having a substantial growth in that portion of the territory. Now you have the Cline Shale in Texas as well, in our North Texas area. And then we already have the Haynesville, Bossier, the Fayetteville, the Bakken. That's in our territories. So if there's oil and gas activity going on -- which has been our saving grace, actually, from an industrial standpoint, at this point and from a load perspective. If you continue to see that improve with an economy that's coming back, then you'll see not only those kinds of facilities pick up, piping manufacturers and so forth, but also petrochemicals along the river. Those are the kinds of things that we're looking forward to. And you're seeing some early indications of industrial output improving. But certainly, it has a ways to go, and certainly, it needs a -- I mean, it needs a federal focus that provides for the economy to fully recover. When that happens, we're going to take off.
Just a point of clarification on the environmental CapEx. You had mentioned there's about $4 billion to $5 billion to be spent between now and 2020. And in the back, in the appendix, there are some potential environmental investments to be made, about 11,000 megawatts. I'm wondering what's the timing of that -- of those 11,000 megawatts. Is it incorporated in that CapEx forecast? And also, I'd like to get your thoughts on greenhouse gases with regards to existing sources.
Nicholas K. Akins
Yes, so I'll give my thoughts on greenhouse gases, and then I'll ask Mark McCullough to pick it up, so you can hear from him a little bit on the other part of your question. I think that certainly, the greenhouse gas issue has picked up, as everyone knows. The president, in his State of the Union address, there were 3 things that we were actually looking for: cyber security, which he mentioned; and then certainly, climate change and its impacts from a greenhouse gas perspective; and the other was infrastructure development, which I saw as positive, particularly in terms of our River Ops and the things we're trying to do across our system from an electric utility perspective. But from a greenhouse gas perspective, we have -- and Gina McCarthy, who has been in discussions with a lot of people -- I mean, that's very public. She's been saying she'd talk to anybody that would talk to her. But those discussions have gone -- or seem to be going well. I think we have to be really rational about what we do relative to greenhouse gas, particularly on existing units. Now we still have to complete the new unit greenhouse gas rules. That's going to take time. And then there's no actual timing requirement to deal with the greenhouse gas issues on existing units. They're already past their settlement date. But nevertheless, when we look at the system, HAPs MACT was, I think, a surprise for the EPA. There were a multitude of issues involved. Originally, they came out and said 10,000 gigawatts would be affected. We said and we were the first out saying there would be 60,000 gigawatts affected, 6,000 on our system, and that there would be reliability implications associated with it. And indeed, both of those counts have been fortified with all the debate with the RTOs and so forth. So I'm not saying I told you so, but we tend to know something about the system that we operate. And there are other issues involved from a reliability standpoint but also from a state perspective. So if there's too dramatic a change, too quickly, on existing unit requirements, particularly on existing coal where there's no technology that's commercially available at a pricing point that could even survive, that would be a clear problem for the reliability of the grid and for customer prices going forward. Many people don't realize that changes in electric utility prices are highly regressive. The poor and middle class are impacted more by increases than anyone else because it takes a larger portion of their disposable income. And you've got to think about those impacts as well. But I tend to look at -- on the system side, sort of as an iceberg, and basically, HAPs MACT truncated the top part of the iceberg above the water level. If you get into greenhouse gas requirements too quickly on existing units, you're going to take a broad swath of the entire coal fleet in this country out, and that's not where we need to be. And certainly, from a recovery perspective, we're going to see plants retire, jobs go away in '15 -- 2014 and '15 and '16, based upon HAPs MACT, at this point. You would just further exacerbate that situation if we move too quickly with the climate -- with the greenhouse gas on existing units. So I'm hopeful that people have learned a little bit in this process about the impacts it has on the grid. There is an entire process at play now, a multiyear process at the states themselves and the commissions. The state commissioners are having to deal with price increases, having to deal with decisions about even whether you put scrubbers on or replace generation or retire generation, and that process is ongoing. If you want to disrupt that entire process and start back at ground zero from the state perspective and have an impact on prices for customers, dramatic increase in prices for customers at a time when we're trying to restart a tenuous economy, it makes absolutely no sense. So I'm hopeful that if there is greenhouse gas requirements, that there will be such a timetable that it'll support the transformation that's already occurring. We're already on target because of the advent of shale gas activities to achieve the Waxman-Markey requirements of 17% decrease by 2020. That's already occurring. So this industry is already moving that direction. And I think it's just important for people to realize we are an industry in transition. We need to take time to do it. We don't need to disrupt the process, and we certainly don't need to strand a bunch of investment that we're already making for HAPs MACT, billions of dollars of investment that would be stranded as a result of moving too quickly on this. So those are the kinds of discussions that we're having. And hopefully, this time, we'll get more response. So we'll see. Now you have -- Mark, do you want to answer the rest of his question on timing.
Mark C. McCullough
Sure. I think it's best to refer you to Slide 22, and where Brian pointed out the environmental spend is moving up to over $500 million this year. We spent a little over $200 million last year. Most of those projects you see in the slide, in the appendix, engineering -- certainly, the pre-FEED studies are complete and much of the engineering and pre-site work is completed. We're poised to move forward as regulatory processes approve moving forward in a particular direction. So much of that $530 million you see for 2013 will be commitments to equipment. We'll begin to order that equipment and prepare the sites for the arrival of that equipment.
Mark, is there anything -- Brian up here, Mark. Is there anything you can say or you'd like to focus us on, on Page 50, in the appendix there, on the left-hand side, the 11,000 megawatts of potential investments?
Mark C. McCullough
Yes, look, those are the numbers. We do have a lot in play with respect to evaluation of these technologies. As Brian mentioned earlier, we're looking for the most efficient, economically-driven technology, and we are prepared to move forward with this plan, as it shows here in the slide. DSI is a prominent player in this strategy. We've learned a lot more about that over the past several months and see it being deployed to comply in a large percentage of our fleet. Andy?
Can we just talk about the dividend policy? Obviously, you've articulated pretty well, but we didn't get a dividend increase last year as we waited for Ohio. How quickly can we kind of see the ramp-up to -- this is called midpoint of 65%. And do we get a little bit of a catch-up in 2013 and then kind of grow from there?
Nicholas K. Akins
I certainly think initially, you're going to be at the lower range of that, given -- going through corporate separation, those types of activities, and then you would see it trend up toward the midpoint. Brian?
Brian X. Tierney
And we can't speak for what the board will or won't do, but they were very mindful in terms of raising that targeted dividend payout ratio, reflecting where we were at the time. So I think the board knew what they were doing by raising it. And if they decide to make any changes, I'd expect that you'd see some of that this year.
Chuck did a great job in his presentation, but kind of the reality, competitive generation is a tough business and you look at the NRG Genon deal and a lot of that was a decision based on getting synergies out of an organization. Given the size of your Ohio fleet, how do you guys think about the long-term importance of that business to AEP? And is this something you scale up, or is it something you exit over time?
Charles E. Zebula
At least our initial thoughts about that business, we're going to build that business as if we're keeping it. Now the focus of it is not to grow it to become a larger, unregulated business. Our focus is to hedge that generation. That is our focus. And if we can make it look regulated, where it's a hedging profile and a portfolio of hedges that support that generation, that is something that's acceptable from a volatility with our shareholders, we'll look at it. But we are a regulated utility, and anything that we can do to fortify that position, we will do.
And I guess we're going to talk corporate strategy, we heard conversations, everything turning into an MLP at this point in time. The transmission business does seem to have some viability as a REIT, according to the IRS. How do you guys think about the transco fitting in the corporate structure, and is that something you guys look to explore to maybe optimize incremental value out of that opportunity?
Nicholas K. Akins
Yes. At this point, it's really focused on development of the transcos, development of the critical mass to get the transmission company moving. And then, of course, in the future, we can evaluate what it holds for transmission. My focus, though, is to make sure that we move more toward a regulated infrastructure-related business. And transmission is a big part of that. And then ultimately, we'll decide how do we continue to reinforce that for AEP shareholders, and we'll do that.
What are the steps to the corporate separation by January 1, 2014? Sort of what are the signposts for us watch along the way? And then secondly, the impairment that you took in the fourth quarter on Ohio generation, what was that?
Brian X. Tierney
It was associated with assets that are going to be part of the competitive business that we were depreciating on a retirement date to mid-2015. And we used to evaluate those assets as part of the pool. When we got the Ohio corporate separation order, it made sense for us to start evaluating them not as part of the pool, because we don't anticipate them being part of the pool through the end of -- beyond, I guess, 2014. So we started looking at those plants individually. They include Muskingum River 1 to 4, Kanawha [ph] 1 to 3, Picway 5, Beckjord, Sporn 2 and 4.
So those are all plants you're closing?
Brian X. Tierney
Plants that had been anticipated to retire by the end of -- by mid-2015. And when we started looking at them on an individualized basis, we realized we had to take an impairment on them.
Nicholas K. Akins
That was only impairment because of Ohio.
Brian X. Tierney
I wondered if you could also discuss your outlook for retail margin.
Brian X. Tierney
Yes, I made the mistake of doing that on an earnings call, and now they tell me that I shouldn't do that anymore.
Nicholas K. Akins
We can say this, though. Our focus is on margins and customers, customer mixes that provide for higher margins. We are not out there trying to get all the megawatt hours we can get. We're not out there most certainly selling below market. And our focus continues to be those higher margins.
Rich, could you give us some of those signposts that Leslie was asking?
Richard E. Munczinski
Sure. So let's take it by federal government, first. The FERC, we have filed our cases at the FERC late last year, and we would expect that we will get approval of the 6 filings at the FERC sometime midyear. I'm hoping a little bit earlier than midyear. FERC, hopefully, will not wait for the states. And then as concerned to the states, what we've done is we have filed for the transfer of those units and for the merger of Wheeling into APCo. We filed cases in West Virginia, in Virginia and in Kentucky. Each of the states have now provided us with a procedural schedule. And so there'll be procedures ongoing from now through the summertime. Each of the states and the FERC, we've asked for approval of all this effective January 1, 2014, which is also the same date the pool, the East pool that we continually talk about, will be terminated.
What do you see is the biggest issues that have been raised? I know the asset transfer and, perhaps, the price at which the assets are transferred in. But other than that, does there seem to be material pushback from interveners?
Richard E. Munczinski
There's about 25 interveners at the FERC. I'll put them in 3 buckets. One is there's a few of the parties that are trying to retry the Ohio cases, which FERC shouldn't pay much attention to. Secondly, there's a lot of questions about the language in the agreement. I know we have made this as simple as possible by eliminating the pool, the pooling agreement, and basically having each of the companies stand alone. So there's some language issues that we'll clean up and, hopefully, settle with the parties. And then the transfers themselves, really, will be up to the states. And so each of the states have a case in front of them for the transfers. And then once the transfers are approved, we'll then go in individually to the states and collect the funds for those transfers if they're not offset by the pool dollars already. Does that help?
Brian, I think this one may be for you. On your waterfall chart for '13 guidance, you have the $0.24 of nonutility and parent. If I look back to EEI and sum the kind of 3 buckets that you listed earlier of interest costs, River Operations and then to the retail within Generation and Marketing, it seems that, that has kind of increased by maybe by a $0.10 or so since EEI. Which of the buckets is driving it? Or can you give us any insight into how the $0.24 breaks down?
Brian X. Tierney
Yes. The early redemption of debt was probably about $0.12. The River Ops increase was about, I'd say, $0.09 or $0.10, and the balance is the Generation and Marketing.
Great. And Chuck gave us this disclosure on how much of the potential margin is determined in the competitive business and that you have this number of 60% for 2015. Is that a sort of -- is that the annual number adjusting for some of the midyear shift in the buckets? And is there any chance of a number on 2016?
Charles E. Zebula
Yes and no.
Nicholas K. Akins
Go ahead, Chuck.
Charles E. Zebula
The answer is yes and no. So the first question is yes. Second question, no.
Nicholas K. Akins
Any other questions? Okay, well, thank you very much, and thanks for your time.
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