Q1 2011 Earnings Call
May 03, 2011 8:15 am ET
Arthur Yuan -
Charles Jones - Senior Vice President, Principal Executive Officer of Ohio Edison Company, Principal Executive Officer of The Cleveland Electric Illuminating Company, Principal Executive Officer of The Toledo Edison Company, Principal Executive Officer of Pennsylvania Electric Company, President of The Cleveland Electric Illuminating Company, President of The Toledo Edison Company, President of Pennsylvania Electric Company and President, Firstenergy Utilities
Ronald Seeholzer - Vice President of Investor Relations
Anthony Alexander - Chief Executive Officer, President and Executive Director
William Byrd - Chief Risk Officer and Vice President of Corporate Risk
James Pearson - Vice President and Treasurer
Donald Schneider - Principal Executive Officer and President
Mark Clark - Chief Financial Officer and Executive Vice President
James Lash - Chief Nuclear Officer and President of FirstEnergy Nuclear Operating Company
Unknown Analyst -
Good morning, everyone. I'm Ron Seeholzer, Vice President of Investor Relations, and I want to thank you all for coming to FirstEnergy's Analyst meeting today.
Before I review today's agenda, I'd like to point out that in your presentation book and up in our slide today, there's a Safe Harbor statement under the Private Securities Litigation Reform Act of 1995. I would ask that each of you review this document closely as you consider the comments we will be making today.
As you can see in your books, we're going to have a full agenda today. We're going to start the meeting with Tony Alexander, our President and CEO, who will provide a corporate and strategic overview of FirstEnergy. Tony will be followed directly by Mark Clark, our Executive Vice President and CFO, who will provide our financial outlook. And after his presentation, Mark will take questions.
Since today's meeting is being webcast, I would ask everyone wishing to ask a question to wait for a microphone to be brought to you before you start asking it so that everyone in the room and on the webcast can hear it at the same time.
In our agenda, we provided for about 10 minutes of questions after each speaker, a process we will work hard to enforce in order to stay on schedule today. Also, in fairness, let's try to limit each person to just one question, instead of one question and 4 follow-ups. If we're unable to answer your question on the individual speakers, please hold them to the end of the meeting because Tony and his senior staff will come back up on stage at the close and take general questions at the end of the meeting.
After Mark Clark's presentation today, Bill Byrd, our Vice President of Risk and our Chief Risk Officer, will provide an update on Enterprise Risk Management. After Bill's presentation, he'll take questions, and then we'll take a break, hopefully, a 10- or 15-minute break, we'll see how that goes. Right after the break, Chuck Jones, our President of FirstEnergy Utilities, will provide an update on both Distribution and Transmission businesses and the assumptions behind our distribution sales forecast. Chuck will take questions before he turns it over to Jim Lash, our President of FirstEnergy Generation and our Chief Nuclear Officer, who will provide an overview of our Generation Operations. Jim will take questions, and he'll introduce Donny Schneider, our President of FirstEnergy Solutions, who will provide an update on our progress to become a leading regional competitive energy provider.
After Donny takes questions, Gary Leidich will come up on stage. He's our Executive Vice President of Merger Integration, and he's going to provide a long-awaited update on the merger integration process and the benefits we have identified to date. Gary will take the final questions and Tony will come up and do his closing remarks, and then Mark Clark, Jim, Donny will also come up onstage and open the floor to final questions.
We hope to bring this agenda to close about 11:30. That's our objective, and let's see if we can stay on time. One final housekeeping note, going forward, we're planning to move away from our traditional December Analyst Meeting and move it towards the third week of February and have it coincide with our first quarter earnings release. And we'll do them both at the same time. So kind of mark your calendars for the third week and we'll see you back together on that date. But let me turn the floor over to Tony and start the meeting today.
Thanks, Ron. Good morning, everyone, and thank you for joining us. I'm excited to be here today to talk about FirstEnergy and our plans to grow our business and increase shareholder value. It's only been about 9 weeks since we completed our merger with Allegheny Energy, and we're already making significant progress in realizing its benefits. Let me start by saying our strategy has not changed. We will continue to focus on our core businesses and on our commitment to operational excellence, retail sales growth, investment-grade credit ratings, and to delivering solid financial results, including maintaining our dividend.
I believe this focus, combined with our competitive business, our diverse generating fleet and the scale of our utility operations, will help us become one of the best-positioned companies for growth in this industry. We also offer shareholders a solid and secure dividend with an attractive yield and the potential for very attractive total shareholder returns as the economy improves and we execute our strategy.
We operate in 3 business segments and have a substantial position in each, which creates both financial stability and growth opportunities. Our Distribution business has the largest contiguous customer base in the United States, and it will continue to have that after all of the other mergers that have been announced are completed. Our Generation business is one of the largest and most diverse competitive generating fleets in the nation. And our Transmission business is the largest owner of transmission assets in PJM. And we are the only integrated company with significant, independently owned transmission assets.
We do not need to grow our business by expanding our rate base. Instead, we are focused on growth through efficiencies, cost controls and making the most of the assets we already have. We will upgrade our facilities to meet increased demand and to reduce the costs and risk in our business, and we will invest in efficiency and productivity improvements to make our assets more competitive.
This philosophy extends to our Transmission business also, where we will focus on smaller incremental projects that improve reliability or reduce congestion in our region, not on long-line projects requiring multi-year commitments outside of our footprint. And while we are still evaluating the growth potential of our Transmission business, the scale and independence of much of these operations means we have tremendous optionality, and we will carefully examine how best to maximize its value in the future.
The size and diversity of our utility service area not only provides us a solid base for financial stability, but is positioned well for growth. We are home to more than 14 million people, 108 major universities, including Penn State, Case Western Reserve and the University of Akron, which have some of the top research programs in the nation; nearly 150 hospitals, including the world-class Cleveland Clinic; the headquarters of more than 20 Fortune 500 companies; and nearly 12 million registered motor vehicles. And our location is attractive to business. We have competitive electric markets, large new natural gas finds in the Marcellus and Utica Shale fields; abundant land and water resources; a skilled workforce; and our service territory is within one day's drive of 60% of the United States population, 50% of the Canadian population and 60% of all U.S. manufacturing facilities.
From new devices in our homes and businesses to electric cars and life-saving technology at our region's hospitals, electric use will continue to grow and our assets are well positioned and fully aligned to capture the opportunities that will emerge as the economy improves.
Today, we'll talk about how we're going to achieve the non-GAAP earnings guidance we outlined yesterday and why we believe FirstEnergy's position provides a solid base to grow shareholder value.
Over the last year or so, we focused not only on meeting the challenges of the recession by driving down costs, but more importantly, on implementing our retail sales strategy and completing our merger with Allegheny Energy.
Respecting our retail sales, we have achieved considerable success in growing our business. In fact, we sell more today at retail from our generating plants than we did as a regulated company. And we are diversifying our customer base, maintaining our margins and creating a strong foundation for future growth as markets improve.
We also closed our merger in just over a year following announcement, a major achievement in our industry. We have a great regulatory team at FirstEnergy, and its experience and skill really showed during this effort. As a result, we expect the merger will be accretive to earnings beginning this year. And with our history of successful mergers, I'm confident in our ability to capture the benefits from this combination. In fact, over the first 3 years, we expect $1.3 billion in pretax cash benefits as we create operating efficiencies and share best practices across the new organization.
With the merger behind us, we will now focus on taking advantage of the opportunities it created, expanding our retail sales activities as we now have 30 billion additional kilowatt hours of product to sell and strengthening our financial position and improving shareholder value. We will also use our internally generated resources, as well as the additional cash from bonus depreciation and asset sales to strengthen our balance sheet and enhance our ability to meet the challenges of our business.
And quite frankly, as you know, there or some. One of the key challenges is that our business is still impacted by the sluggish economy. For example, while industrial sales are improving and continue to improve through the first quarter, they're still about 6% below the peak in 2007. We're also seeing limited commercial growth, although there are pockets throughout our service territory that have been robust, especially in healthcare-related facilities. But we expect more growth as the Ohio and Pennsylvania shale fields are developed. And, of course, the economy impacts market prices, primarily as a result of excess capacity, although we're starting to see higher forward prices.
While we've taken actions to address these economic challenges, we are now preparing for a host of new environmental regulations. And as we learn more about these mandates, we will be able to make decisions about the future of our smaller coal-fired facilities, which have already been written down and what may be required at our other facilities. Even so, today, we are much better positioned than many other companies to address these new requirements. In fact, more than 90% of our production is from non-emitting nuclear, low-emitting natural gas, scrub coal or renewable facilities. And we have options within our fleet to increase the output of our nuclear and supercritical coal units to help replace generation that may be retired.
We also have simple-cycle natural gas units that were designed and constructed so that they could be converted to combine cycle facilities at the appropriate time. And we own the rights, including power-siding permits, to develop an efficient and modern compressed air-generating plant that is not only well positioned to take advantage of increasing natural gas availability, but offers the ability to better manage the impact of renewable energy on the system.
As you probably know, we're also preparing to address changes in our nuclear fleet that may be required as a result of the very tragic events in Japan. Even though we believe our plants are safe, reliable and well protected, I expect lessons learned in Japan will lead to required improvements that will make our nuclear fleet even safer. And while it's too early to identify what may be required, our efforts to improve our balance sheet should put us in a position to address these new requirements and to keep these critical assets a safe and reliable part of our fleet for many, many years.
On the regulatory front, other utilities in Ohio, and I won't name them, my guess is you know who they are, would like the ability to tax Ohioans for new generation that is not needed and/or to pay for environmental retrofits that are not economic. We firmly believe, however, that the competitive model is working, and that the changes they advocate are wrong for Ohio.
Today, nearly 1.5 million Ohio customers across all of the state’s utility service territories are shopping for electric-generation savings from 38 competitive suppliers. Customers will not likely be willing to give up the advantages they now enjoy. In fact, customers want choice. And as they learn about plans that hold them hostage, increase their prices and deny them choice by creating non-bypassable charges, those arguments will likely not be well received. We obviously disagree with the other Ohio utilities. And if it's not obvious, it should be. We will work aggressively at the state level to ensure that customers throughout Ohio continue to enjoy the benefit of competitive markets.
Finally, let me reiterate that yesterday, we announced 2011 non-GAAP earnings guidance of $3.20 to $3.50 per share, and our first quarter earnings are on track with that guidance. We also expect to remain within this range for 2012 and 2013 and to have positive free cash flow during each of those years. We will drive costs and revenues and identify opportunities to deliver on these commitments. It is truly an exciting time at FirstEnergy. We are better positioned than ever to deliver on our commitments and to grow and compete to increase shareholder value. Your support has been, and continues to be, greatly appreciated. Thank you.
Now I'll turn the podium over to Mark and the rest of my senior management team. After each of the presentations, as Ron indicated earlier, we'll provide time for your questions. And I'll be back at the end to close the meeting, and we'll also be available at that time for questions.
Okay, let's get started. Mark?
Thank you, Tony. Good morning. Like Tony, I'm excited to be here today. And certainly, appreciate all of your interest in the company. Before I begin, I'd like to introduce the folks who are going to help me answer some questions later. From right to left, Ron Seeholzer, who's Vice President of Investor Relations; Bill Byrd, who is Vice President of Enterprise Risk; Jim Pearson, who is Vice President and Treasurer; and then Harvey Wagner, Vice President and Controller.
As Tony mentioned, we have accomplished a lot in a very short period of time. Today, I'm going to discuss the first quarter results and provide a financial outlook for the next 3 years, as you know, a much longer time frame than we have done historically. I will also talk to you about the initiatives that we have in place to produce consistent earnings, positive cash flow and a significantly stronger balance sheet over the next 3 years.
Let me start with the first quarter. As Tony alluded to, the first quarter was consistent with our overall expectations. GAAP earnings were $0.15 per share and non-GAAP earnings were $0.69 per share. Normalizing items totaled $0.54 per share. The vast majority of these had to deal with the merger. Either the transaction costs, the costs like legal, banking fees, the cost to achieve, which Gary will talk to a little bit later in terms of integration costs and then the regulatory charges, which are the state settlements.
On the operating side, 3 noteworthy points. Residential sales were up 2% as a result of non-normal weather, colder weather. Industrial sales continued their steady climb and were up 6%. And the strongest positive for the quarter, where FirstEnergy Solutions was up a strong 37%. Donny's going to talk a little more about that later.
Although we're ahead of our forecast after the first quarter, we are not changing our sales forecast for the total year. As you can see at the very bottom of the slide, AYE contributed $0.13 per share for the one month. They were part of FirstEnergy, and there were $0.09 related to merger-related share issuance. So as Tony said, we expect Allegheny to be fully accretive in the first full year 2011. Should you want, there is significantly more detail in the consolidated report that was posted on the web last evening.
Before I get into some of the hard numbers, I'd like to talk quickly about some of the initiatives that we have in place to produce the results that we expect. First, the merger synergies. I'm not going to steal any of Gary's thunder, he's got quite a bit of detail on that. As Tony alluded to, we will continually aggressively reduce O&M and capital over this 3-year period beyond the merger synergies. We will improve our balance sheet, we will complete the divestiture of non-core assets, and we will renew and restructure the revolving credit agreements. And I will address each one of these initiatives as I work through my presentation.
Admittedly, this is somewhat of a busy slide and probably even more busy when you split it in half and put it in your book. But as Tony alluded to, I'm pleased to state that our earnings guidance for the 3-year period is $3.20 to $3.50 per share per year. We do not expect the distribution deliveries to grow much more than 1.5%. I would just remind you that 1.5% is against a pretty big base. Our sales are essentially hedged for 2011, 65% hedged in 2012 and 35% hedged in 2013. That is very consistent with our business plan. Bill Byrd will talk about how we manage the risk associated to that and what we call the glide path. And, of course, Donny is going to discuss the strategy and how he meets those expectations. You'll see that generation production modestly increases as does fuel. Capacity revenue declines in 2012 by $275 million and 2013 by $200 million.
On the financial front, a number of positive takeaways. As I mentioned, the merger is accretive in 2011. We expect AYE to add $0.84 per share plus $0.15 per share in purchase accounting. Together, these more than offset the $0.86 per share related to the merger. Merger benefits increased significantly from '11 to '12 to '13. As I said, Gary's going to speak more to that, but this is the pretax earnings impact associated with those and you'll see that, that's in excess of $1 billion.
We're also targeting O&M reductions beyond the synergies of between $75 million and $175 million in 2012 and 2013. We expect asset sales in the range of $800 million to $900 million per year, and we expect to reduce debt by $1.5 billion to $2.2 billion over this time period. Again, as the first line states, we expect earnings to be within $3.20 to $3.50 per share per year from 2011 to 2013.
Let me just give you a little bit more color related to 2011. As Tony alluded to, we now have 3 separate business segments. You'll see that the regulated distribution company is expected to contribute 55% of this year's earnings. That's the non-utilities, plus the fully integrated West Virginia operations. FirstEnergy Transmission, which is the first time we're reporting this out. We expect it to contribute 10% of our earnings in 2011, that would be ATSI, TrAIL and PATH and our competitive business segment, which is FirstEnergy Solutions and Allegheny Energy Supply. We anticipate they will contribute 35% in the full year earnings.
A couple of technical points. Our SEC registrants will remain the same. Allegheny Energy Inc. will become a first-year subsidiary of FirstEnergy Corp. As in the past, we will provide additional guidance as we move through the year in terms of the earnings and the earnings by segment.
One final point, while the dividend is always subject to the board, our regulated companies continue to produce steady, consistent results, which help ensure the overall security of our dividend.
Let me just spend a moment on capital. We believe our capital is more than manageable over this period of time. As you'll note, from 2010 to 2011, it drops dramatically. That's because of the near-term completion of Fremont, the completion of the Sammis AQC [Air Quality Compliance] project and the near-term completion of TrAIL. The only reason 2011 is a little bit higher than '12 and '13 is that there's some integration costs associated with PJM that are reflected in the transmission dollars.
You can see that for 2012 and 2013, we figured that it's somewhere between $1.9 billion and $2 billion. 2012 and 2013, just those 2 years, include an incremental $100 million associated with potential environmental or nuclear changes. They are acting simply as a placeholder at this point, but they are included in our capital.
I will state that the numbers between the business segments may change over '12 and '13 depending on what's going on in the real world. However, the target will still stay at $2 billion.
This may be my most favorite slide. We expect to be cash flow positive over the next 3 years after capital and after the dividend. 2011 significantly benefits from the asset sales and the bonus tax depreciation. But 2012 and 2013 also have their own benefits, from lower CapEx, increased merger synergies, additional O&M reductions, the residual impact of lowering the debt, 12 months of AYE earnings versus the 10 months in 2011, and, of course, as Jim Lash is going to talk to, we have additional unit uprates through this period of time.
You'll note that the common dividend in 2011 is slightly lower than 2012 and '13 and that's because there were only 10 months of Allegheny in this period, where '12 and '13 will have 12 months. Again, to me, the most important part to this slide is that we will be cash flow positive in each of the next 3 years. Let me talk a little bit about the balance sheet.
We have a solid plan for the overall strengthening of our balance sheet, which starts with the pay down of $1.5 billion to $2.2 billion of debt over this period of time. It’s important to note that we are not targeting debt that has a high premium. We will retain cash to pay down debt when it's appropriate.
There are 3 main segments of our plan. First, we expect the utilities to align their cap structures to align to their regulatory structures. That means their debt to capitalization will be somewhere between 50% to 60%. We expect to keep ATSI and TrAIL aligned with their formula rates, which we mean their expectation is that their debt to capitalization will be somewhere between 48% to 50%. But most importantly, we plan on significantly increasing liquidity and the balance sheet at FirstEnergy Solutions. We expect to reduce FES down to around 40% by the end of 2012, and we expect FirstEnergy to be around 53% at the end of 2013. Now remember, in my numbers, this is net cash. We're not paying back debt if we have go out and pay a big premium for it. But we do think there are number of opportunities. AYE supply has a $500 million issue coming due next year. Centerior/CEI has an issue coming due in 2013. So there's a number of issues plus there's an FES debt that we can purchase off the market.
In terms of the last real financial slide, I want to talk just a minute about the revolving credit facilities. Our facility of $2.75 billion comes due on August of 2012. Our game plan is to get it finished and put together in the second quarter of this year. That will include 3 separate facilities. We plan on having a $1.5 billion facility at FirstEnergy Hold Co., a $1.5 billion facility at FirstEnergy Solutions, and a $1 billion facility at Allegheny Energy Supply. All of these facilities will be for a 5-year term.
I'm pleased to state that all of this is oversubscribed as of this morning. And I know there are a number of bankers here in the audience, so on behalf of Jim and I and the rest of the company, thank you very much for your support. We do appreciate it, and we just wish you'd lower the fees a little bit.
On a period of weak power prices, we plan to deliver strong financial results, whether that be consistent earnings, positive cash flow, significant synergies, a stronger balance sheet, reduced spend, or a strong and sustainable dividend. The end results will be a much stronger company, well positioned for the future, whatever that future may hold.
Thank you for being with us this morning and importantly, thank you for your continued support and interest in the company.
Now I'd like to open it up for questions. As Ron alluded to, this is being webcast. So we'd appreciate if you'd have a mic. Both Irene Prezelj, over here and Rey Jimenez from the Investor Relations staff, will catch up with you and give you the mic. And as Ron said, let's try and keep it to one question. And also with me are the folks up here to help answer any questions. Thank you. Ted?
Unknown Analyst -
I saw that you are making quite a large contribution for the pension program this year...
I'm sorry, the mic isn't on so I can't hear you. Okay. This is good. You're eating up all 10 minutes. Thank you.
Unknown Analyst -
No, it brings up the FirstEnergy pension to about 90%. That's in line with what we expect. If interest rates increase, the discount rate will go up and that will close the balance of that gap. Now that's FirstEnergy. Allegheny has some mandatory requirements that are little bit less. They are more around 80%, something in that range. We made the contributions on the FirstEnergy side because it's just tax efficient. We're not certain what the government's going to do in terms of some of the tax deductions and things like that. They encourage having these plans in place since the tax deductions, so we're pretty comfortable that 90% is the right number for FirstEnergy. And there are mandatory issues over the other side that we will address as appropriate.
Unknown Analyst -
Believe you mentioned that Allegheny Supply would become a first-tier sub. What plans do you have on integrating Allegheny Supply and FES at some point in the future?
Right now, that's under study from a standpoint of tax. We can't put them together. We'll look at it 12 to 18 months from now, but Jim will address the fact that both AE Supply [Allegheny Supply] and his generation is being managed as one unit, even though, legally, they may be separate, and they will be for tax purposes for at least the next 12 months. And so at this point, there's really no issue for us to spend much time studying that, and we don't plan to.
Unknown Analyst -
Mark, could you just give us some insight into what's driving the working capital? Other line is consistently positive over the 3 years.
Really, 2 items. First is we believe we have too much inventory, and we're aggressively attacking the inventory. The second is accounts receivable. It's not so much an issue out at FES. They maybe have too strict a credit limit, but we plan on working aggressively. Chuck's group has done a fabulous job in the accounts receivable and aging process, but those would be the 2 areas that we believe that we can aggressively continue to reduce.
Unknown Analyst -
In terms of the other cash flows, you've got a TBD in terms of asset sales, as you get into '12 and '13. Tony inferred in his opening comments that one of the areas that you might be looking at was transmission. You've got almost $2 billion in rate base in your 2 different transmission businesses. Do you see an appetite out there if you chose to monetize those? And is that an area where you think you could raise a significant amount of cash for debt reduction?
That's a good question. First, we continue to own a small piece of OVEC. We also have a small piece coming in from Allegheny Energy. As we've always said, OVEC does not fit our strategy. We prefer to manage our own units, the results are some peaking units, Richland/Stryker which are around 400, 448 megawatts They're not core to the business when you put them in conjunction to the Allegheny assets. There are some small fiber type assets that we have sold ours off at FirstEnergy, we plan on selling Allegheny's office. And specific answer to your question on transmission, I think we get a phone call every day on transmission, but as Tony alluded to, that's under study. There is no need to look aggressively at that. We have a plan in place that produces positive cash flow for each of the next 3 years without doing anything with the Transmission business other than study it. And at this point, we're very pleased with it. It diversifies our earnings. It helps strengthen the dividend. And it's a great asset to own, and we plan on studying it as Tony alluded to.
Unknown Analyst -
In terms of the -- can you discuss at all the compliance strategy that -- for the supercritical units that you plan on pursuing in order to comply with the EPA regs, particularly mercury and HAPs [hazardous air pollutants]?
That's a great question, because I don't have to answer it. Jim Lash has all that detail in his presentation. But thank you for getting me off the hook on that last question.
Jim has a lot of detail. He has a specific PowerPoint slide on it. So I'll leave it to Jim to discuss, and you guys are off the hook. And Bill is going to come up and discuss the issue of how we manage our risk and the glide path, and why we believe we create more margin through our retail strategy. Thank you very much.
Good morning. I'd like to talk about 3 topics with you all this morning. First, I want to talk a bit about our retail strategy and the risk profile of that retail strategy at our competitive business units. Second, I want to update you on our formal commodity risk limits that have been updated reflecting the close of the merger. And third, I want to mention briefly our collateral outlook.
First, on the risk profile of the retail strategy at our competitive business unit. And I call this chart the value proposition of the retail strategy. Looking at this stacked bar in the middle of the chart, starting at the bottom, we own power plants, we generate electricity, and we can sell that electricity to the wholesale market, and we could capture the wholesale price. And the difference between that price level and our production costs would just be the margin that accrues to a generator. And some companies, that is their business model, okay. They sell to the wholesale market and take that margin. But we are after a higher pricing level. We are after that retail price. But in order to get our product from the wholesale market down to that retail meter, we have to incur additional costs, okay.
These cost components to provide the retail service are things like RTO charges. That's network integration service, the administrative charges of the RTO. Anybody serving a retail customer typically has to provide a quota of Renewable Energy. We have to provide capacity, shaping and balancing energy and line losses, all of these additional costs are incurred in order to capture that higher retail price. Those costs are incurred, we sell our product at the retail price and capture a margin, the retail price in excess of our cost. But because we've integrated our generation activity and our retail marketing activity, we view it as one.
These additional cost components that are incurred to go from wholesale to retail provide additional margin opportunities for us. Line losses, for example, that's just additional energy. That's just margin, the value of the energy in the marketplace less our production costs produces margin. Capacity, we sell supply. We get revenue for capacity. That's margin. Now not all of these cost components are pure margin for our competitive unit. It varies in degree depending on the cost category.
RTO charges, for example, that's a pure cost. There is no feedback or margin opportunity in that. We just pay that price. But the point is, our business model, we're trying to capture the full gamut of value in this chain. The retail margin, the margin that accrues to a generator, and the margin derived from self-supplying the cost components of retail service. Now this chart portrays a conceptual picture of our risk profile and how we view our retail strategy from a risk perspective. We sell supply. Our assets hedge our risk exposure. We seek to avoid the risk exposures in the marketplace, if you will.
Block energy, for example, we own power plants called nuclear plants, and supercritical coal plants that produce block energy. Shaping and balancing energy. We own plants that follow load. We own gas-fired CTs that provide that balancing energy. When the weather conditions in July result in unexpected consumption and unexpectedly high prices, we turn on the gas CTs and they run 50 hours a year but they hedge us. They protect us against that price spike that a retail marketer sourcing from the market would get hit with.
Things like congestion and capacity. Our assets hedge that. We self-supply. Congestion, as long as our load obligations are in the areas of the grid that our plants were built to serve, what Donny will refer to as our home and close to home market areas. As long as we seek load obligation in those areas, congestion is de minimis. Yes, there is a cost, but we get FTRs, we can hedge it, and it's not a big deal. The further we go away from home, the more congestion becomes a pure expense for us.
Similarly for capacity, as long as we incur load obligations in areas of the grid that our capacity is deliverable to, we self-supply. We charge the retail customer a component of their prices for capacity and we get that revenue and margin. The further our marketing forces go away from our home and close to home territories, the less deliverable our capacity is, and the less it represents a hedge for us.
Renewable Energy. We self-supply. We have one of the largest portfolios of wind energy, for any company that doesn't own wind farms, we elected years ago to contract for Renewable Energy, and we control in excess of 600 megawatts of Renewable Energy through contracts. So effectively, our asset portfolio hedges our retail obligations.
Now alternative business models to compare what we do to perhaps some alternatives. This chart, on the first row consider a retail marketer. A marketer, furthermore, that would source from the spot market. Under that business model, they're hedging horizon is tomorrow, next hour, next day, and that's the spot market. They avoid collateral needs because it's de minimis. They would incur only collateral with an RTO, which is de minimis. No counterparty risk, but the price risk is huge. That business model, you're always exposed to the next price excursion in the marketplace.
And a retail marketer always has volume risk for the retail customer. Now that particular price model, the price risk is tremendously significant. Some of you all are aware of the conditions in Texas, the first week in February due to weather conditions and availability of generation, there was a price excursion. And I'm told numerous retail marketers disappeared from the marketplace within days of that because they were exposed to spot markets, the price spiked on them. They go out of business.
Take a generator on the flip side, a generator selling to spot. They can minimize their collateral and counterparty risk but they have huge price risk on the other side. Their revenue is always subjected to low spot prices, and could be extremely volatile. Now for us, our business model, by focusing on retail and self-supplying our hedging with our asset portfolio, we can extend our hedging horizon out to 2 years. Donny will tell you he is trying to get to 3 years, and that's the difference between Donny and me. From a risk perspective, I round down. Donny rounds up. The reality is our hedging horizon in our contract portfolio is between 2 and 3 years right now. But we're locked solid on a 2-year hedging horizon, trying to get even longer.
We do have -- our collateral is de minimis, as I'll show you later. Counterparty risk is the portfolio of 1.6 million retail customers. That's our counterparty risk. Price risk, we still do have some price risk, but we've minimized our price exposure. And volume risk, anybody serving retail has volume risk. But we feel our business model gives us a risk profile that's very manageable and very attractive.
Now to shift gears a tad bit, with the close of the merger and the increase in our portfolio, we revisited our formal risk limits for our commodity book. Right now our formal limits for 1 to 12 months out, we want to be 90% to 100% hedged. And my percent hedged metrics are always measured in dollars.
In other context, we do talk about percent hedged in terms of percent of megawatt hours hedged, and I believe Donny has some slides using that metric, but for my purposes, I always talk in terms of percent of revenue hedged. So for 1 to 12 months out, we want to be 90% to 100% hedged; months 13 through 24, 50 to 65 and so forth. That implies that we would keep up to 12 million megawatt hours using a pro forma supply number. We would keep up to 12 million megawatt hours open and exposed to spot markets. We do that intentionally. That helps cover things like unexpected unit outages, it helps cover the volume risk associated with our Retail business, and also, we are consciously preserving upside to the wholesale market.
These particular charts show our exact position right now in terms of the percent of our revenue hedged. And these charts take a tad bit of explaining, but we want to use this presentation format going forward. So I want to spend a few minutes to get you indoctrinated to them.
The chart on the left is for delivery year 2012. The horizontal axis are the months during calendar year 2011. So looking at March of 2011, the square dot represents 68%. That means for delivery year 2012, our revenue currently as of March of 2011 is 68% hedged. And by hedged, I mean, it's predictable with a very small uncertainty band.
The lines, what we call the glide path, are the range that we want to be -- maintain. We want to maintain our book within that band during the course of '11. So by the end of this year, we will go into calendar 2012 90% to 100% hedged. The bottom side of this band is derived from cash-based credit metrics. Reflecting management's commitment to maintain investment quality ratings, we've taken the cash-based credit metrics and translated into the percent hedge that we need to maintain in order to meet those particular metrics. The top band reflects management's desire to consciously reserve power, as I said in our risk policy, to reserve power to protect against unit outages and also to preserve upside to the market.
The chart on the right is the same information for calendar 2013. And as of March of this year, we're 33% hedged for our expected revenue in calendar 2013. And by the end of this year, we'll be 50% to 65% hedged.
Donny, in his presentation, will show similar slides or similar information in a similar format, except he will be using percent of megawatt hours as opposed to revenues. Finally, a word or 2 about collateral.
This chart plots our contingent collateral, the collateral that we would need if all 17 rated entities are reduced to below investment grade, that collateral that would be needed as a percent of our corporate liquidity. The bars prior to February '11 reflect FirstEnergy on a stand-alone basis. The bars for February and March reflect the consolidated company post-merger.
Currently, about 17% of our available liquidity would be needed to cover collateral requirements if we were downgraded tonight. That number puts us right in the middle of the pack of our peer group. We monitor against roughly a 25% threshold, anything below that is our target area that we're comfortable with.
Also to put hard numbers on our collateral needs, this data is as of March 31. If all 17 rated entities were reduced to below investment grade, we would need to come up with about $506 million of liquid collateral to cover our existing obligations, to collateralize our existing obligations.
What's significant about this chart is all but $69 million of that has nothing to do with commodity markets. There's a common perception that collateral is driven by price changes and commodity transactions. But the bulk of our contingent collateral is tied to us just being in business. In that row called static amount, there's about $75 million buried in there that we would have to collateralize our ownership share of the nuclear energy insurance mutual company.
There's another $50 million in the static amounts that represents collateral that would have to be posted with RTOs. It's just stuff that we incur from being in business.
The accelerated payments, there's dollars in there. We had some nuclear fuel contracts that have since settled, since March. But if we had been downgraded in March, we would have to collateralize the payment of those contracts. The important thing is very little of this number is driven by commodity markets.
In addition to the fact, the $500 million is a relatively small number for a company of our size. With that, that concludes my prepared comments. I'd be willing to take any questions that folks might have.
Unknown Analyst -
I wanted to ask about Slide 3. You have a variety of things in the retail margin that are often associated with the wholesale markets, like capacity, ancillary services. I'm just wondering whether -- what the actual additional margin that comes from retail? If you could sort of quantify just how important -- how much more you're going to be getting by sort of ramping up the retail -- if you could just give us a flavor as to what that means from a bottom line perspective? Do you follow me?
I understand completely and I will respectively refrain from providing any numbers. We view the numbers as a competitive issue. And what we're trying to do with that chart is explain the value proposition. We are not going to lay out specific numbers for each of those cost components; that would provide extremely useful information to our competitors in the marketplace in their pricing activity.
Unknown Analyst -
How about just sort of in the aggregate, though, I guess. I mean as opposed to breaking it out, as much as we all might like that. But how about just sort of just a general flavor as to just how critical, in terms of margin, this increase in retail activity is?
It's significant and it's a meaningful value proposition for us to pursue. But again, I respectfully want to refrain from quantifying.
Unknown Analyst -
Would legally combining FirstEnergy Solutions and Allegheny Supply sometime in the future be beneficial from the risk perspective; hedging, collateral posting, netting perspectives?
Limited. The merger closed February 25. As of February 25, those entities were managed as one. It was absolutely critical that we have one face in the marketplace. We've internally set up things so that, that is the fact. And that's the issue from a risk perspective. We have a consolidated position report. We manage as one. The legal structure is secondary from a risk perspective. There will be small benefits if we would consolidate, it's not a driver, it's not a high priority. As Mark mentioned, there's tax issues and all that sort of thing. But from a risk perspective, we view it as one already. The legal entities can stay separate.
Unknown Analyst -
You talked about hedging revenue. Is your approach to hedging fuel the same as approaching revenue? Are you using like the same percentages year-on-year?
Our philosophy is similar. The numbers will be different, and our metrics for our fuel book are still under development and being vetted with management.
Unknown Analyst -
I'm just wondering, I know you want to focus on the retail and signing customers up there, but if retail is going in slow, how willing are you to engage in wholesale hedges? As you're looking at the chart on Page 7, you're going along to that lower extreme, it seems like at some point, those might be easier to get. I mean is there a reason to maybe go that way in certain circumstances?
The lower bound of our glide path, if the retail portfolio does not bring in sufficient volume of contracts, or our participation in polar options does not provide a sufficient hedge percentage, then we would go to the wholesale market and hedge with pure wholesale contracts. It's not our desired mode of operation, but in order to meet our risk tolerance, we would do that. And in that activity, we would be very much cognizant of potential collateral needs and liquidity impacts, and the strength of our balance sheet.
Unknown Analyst -
And is that something that you would tell us, “Oh, of our hedges, a third of them are wholesale,” just so that we can kind of have an understanding that, that's going to have implications as to what the hedging results are going to do?
That's something we hadn't talked about. Something we'll consider soon.
With that, let's take a break and maybe if we could reconvene at 9:30, and we would like to adhere to that time, mindful of the folks listening via the Internet. We'll reconvene at 9:30 promptly. Thank you.
Okay, good morning. Welcome back. I don't know if anybody else even notices, but when they turn the lights out in the room just prior to the utility guy getting up to talk, it kind of puts a little bit of a nervous edge on things, especially here in New York City. But anyhow, good morning. Over the next 15 minutes or so, I'll be updating you on our FirstEnergy Utilities and our transmission system. I'll cover a little bit about our scale and scope, operating philosophy and key financial determinants, and I'll wrap up with a discussion of some of our energy efficiency mandates.
The merger with Allegheny has brought a broadened scope to our utility operations. We're now the largest investor-owned utility network in the United States, serving more than 6.1 million customers across 6 states. Our customer load profile is equally split between residential, commercial and industrial load, creating a well-balanced portfolio and strong stable regulated cash flow. Our footprint also provides us both geographic and regulatory diversity.
Our utility strategy is fairly simple. Operating reliably and meeting customer service expectations ensures we remain in good stead with our regulators. In the first quarter, American Customer Satisfaction Index, FirstEnergy Utilities ranked sixth out of 26 participating companies, and we increased our percentage by 4 percentage points over 2010. This helps us achieve regulatory margin, which in turn, allows us to work to maximize our utility cap structures and our earnings. And we've already launched initiatives to ensure we capture all assigned merger benefits.
As you can see from this slide, from 2006 to 2009, we have made steady improvement in distribution reliability in both the legacy FirstEnergy and the legacy Allegheny operating companies. 2010 was a little bit of an anomaly. We had 40-plus days of 90-degree temperatures last year, which brought us a significant number of late-afternoon thunderstorms and the resultant outages that go with that. But beyond that, I think we're on a steady path to continue to improve.
Our basic philosophy of hardening the system, while at the same time minimizing impact of those inevitable interruptions to our customers is serving us well. And it's put us in the position to meet or exceed all of our reliability standards in all of those states that have them.
We're in the process of implementing a changed operating philosophy at our new utility companies. We look at ourselves as a national, or at least, regional business that does business locally. We're implementing a regional management structure at West Penn, Mon Power and Potomac Edison similar to our other operations, which pushes decision-making and accountability close to the customer and with a focus on the individual operating issues that can vary from region to region. Strong presence of each operating company will have complete responsibility over all operating issues. In Pennsylvania and Ohio, where we have multiple utilities, we will have state presidents to ensure consistency in how we operate across those states. And to support that effort, we've developed support teams from existing FirstEnergy operations that we call sister companies that will assist West Penn, Mon Power and Potomac Edison with this transition. Experienced managers will work closely with their counterparts to help them adapt to new FirstEnergy policies and procedures.
Our footprint also provides us tremendous scale in responding to severe weather events across the system. Our geographic diversity usually means that the impact on our system, overall, is localized. Our outage management tools allow us to manage restoration and dispatch from any location throughout our system. And our more than 9,000 utility employees, as Tony mentioned, they're all engaged in the storm management process and they're all within a day's drive to help their sister companies. This will reduce our dependency on mutual system support from other companies, not ours, and ensure that we are not paying a premium to restore service to our own customers.
During the merger integration process, we've been very thoughtful about how to integrate the new service territory into FirstEnergy. We had more than 150 seasoned veteran utility employees from both companies working the last year, first, to identify the benefits of the merger, and now, to make sure that those benefits are captured. While there are over 100 total operating improvements identified, 9 major initiatives similar to the 2 shown on this slide will help us achieve the overall value creation.
The integration process also focused on capital spending across the utilities. Our move of FirstEnergy transmission to the PJM this year has created a one-time capital expense, which is part of the uptick you see from '10 to '11, although the '10 numbers there are just the FirstEnergy prior to the merger. Along with that, we have another of major transmission investments going on this year. Beyond that, we should settle in around $1 billion or so, which at $167 per customer, puts us in the lowest quartile as far as capital spending per customer. Smart Grid, Smart Meter and energy efficiency capital is fully recoverable through specific rate treatment outside of our formal rate cases.
Our sales forecast over the next 3 years shows steady 1.5% growth. The 2011 to 2012 growth looks a little more substantial in the chart because 2011 only includes 10 months of Allegheny. Our residential and commercial customers help offset economic swings, which occur mostly in the industrial sector. We refer to our utilities as a fixed income part of our portfolio and while 1.5% obviously isn't great, it does reflect our economy as a whole. And it provides a steady base of earnings from which the rest of our strategies can be launched.
We have some bright spots in there. In an otherwise sluggish economy, key areas of our service territory are seeing significant economic development. Banking, insurance and nearly every other industry are modernizing their data centers. In fact, probably many of the companies you work for have built new data centers just across the border in New Jersey that land into our territory. And these data centers represent solid high-load factor energy usage. We're seeing some rebound in the automotive sector, which should bode well for our economy as a whole. And in Cleveland, the Cleveland Clinic expansion, the Cleveland Medical Mart & Convention Center and a new casino are all welcome additions. These projects alone represent more than $2 billion of economic development. And the crown jewel might well be the $1 billion Calisolar plant, which is going to be located in Mansfield, Ohio. It'll be a new plant using 100 megawatts of energy to produce world-class, solar-grade silicon.
Okay, let's shift gears to a little discussion on our transmission system. Prior to the merger, FirstEnergy's transmission system had 14,900 line miles. About half of that was in American Transmission Systems Inc. or ATSI, our transmission assets in Ohio. And about half is owned by the former GP Utilities in Pennsylvania and New Jersey. Up to this point, our focus on transmission has been basically operational.
Merging in Allegheny brings us to just under 20,000 transmission line miles. And as you can see from the map, it substantially increases our West to East transmission reach, and as Tony mentioned earlier, makes us the largest transmission operator in PJM.
Reliable operation of transmission system also remains a top priority. We've consistently operated at or above the top quartile on transmission outage frequency, which is a common industry benchmark for transmission system performance. This helps ensure appropriately regulatory margin, both at the state and federal levels, and also with NERC. Speaking of regulatory environment, between FERC and NERC, the external oversight of this part of the industry has changed significantly. We've undergone 7 different readiness and compliance audits in the last several years and passed all in a successful manner.
Our friends from the nuclear side of the company have helped us develop an excellent compliance program and culture with a find-and-fix mentality. The scrutiny also extends to minor system disturbances, cyber security, physical security and has driven a continuous review and self-improvement approach throughout our utility operations. And lastly, we successfully passed the NERC readiness review for moving our ATSI assets into the PJM RTO.
As I mentioned earlier, some of our transmission system is owned outside the utilities with specific FERC rate treatments. The TrAIL 500 kv line, for example, has a 12.7% approved return, and within TrAIL Co., a number of smaller other projects average between 11.7% and 12.7% returns.
ATSI is very similar. ATSI has a FERC-approved formula rate in place, ensuring recovery of any expenses associated with operation and maintenance of this part of our transmission system and a 12.4% return on equity for new investments made in the ATSI footprint.
Our immediate transmission future is somewhat of a stable picture. TrAIL will be going in service by the end of this month. In fact, one line section is already in service, and the other two are scheduled to go in, in the next two weeks. PJM has suspended the PATH project based on their most recent comprehensive load studies. But beyond that, we do believe there are a number of smaller transmission projects that make sense. The transmission systems of Allegheny and FirstEnergy were built independently to serve native load with native generation. By strengthening the ties between these 2 systems, we can recognize significant benefits in both operations and economies. We can improve reliability by networking 2 systems that were built independently, which reduces congestion and improves economic dispatch, providing benefits to both customers and competitive markets.
In summary on transmission, transmission represents a stable block of regulated earnings, both today and into the future. There are a number of near-term projects that can bring both operational and economic benefits, and the amount of capital invested can be managed within our overall capital requirement.
Now I'd like to spend just a couple minutes on addressing new regulatory issues that are evolving. Energy efficiency, demand management, Smart Meter and Smart Grid programs are in development across our footprint. I could take all morning talking about the opportunities and challenges that these present for us, but I'd say that our strategy is really very simple. We've taken a conservative approach that is customer focused, meaning we do not believe that long term, customers will want to pay for any program where the costs exceed the benefits. So in a practical sense, that means we're complying with existing regulation, but not going beyond compliance. We're ensuring all expenses and investments are recoverable with no negative impact to our shareholders. And importantly, we're using these programs to study the true customer and grid management benefits so that we can approach investments of this type in a little more scientific manner going forward.
Just to wrap it up, simply put, our goal with Utility Operations is provide a stable base of earnings while meeting all external requirements related to reliability and customer service. We've successfully managed integrating our T&D system through 2 previous mergers and expect to do the same with this one.
And with that, I'd be happy to take couple questions.
Unknown Analyst -
How much spending are you doing on the energy efficiency program and then separately, on the ROEs for the Transmission business, you said for ATSI, it was 12.4% ROE on the new investments. Is it also that ROE on your legacy assets?
It's 12.4% return through a formula rate. So what basically works through ATSI is we look at our rate base. We earn 12.4% on that rate base that's within ATSI, which right now is a little over $600 million, and then we recover the expenses annually which drives the revenue requirement for ATSI on an annual basis. On the energy efficiency spending, that number is going to be probably for 2011 in excess of $200 million. We have a number of programs that are filed and awaiting approval. But if they all get approved, it could ramp up even as close to $250 million.
Unknown Analyst -
Yes, two things. First, on the transmission. If you look at the rate base you have and the ROEs, it would look like you'd get to about $0.25 of earnings, not $0.30 to $0.35. Are you able to lever up the transmission? Or can you actually do better than the allowed ROEs? And then the other question is on the regulated distribution businesses, can you stay out of any rate cases in all states for a pretty extended period? Do you have any commitments that have to come in or you pretty well can kind of stay out?
Okay. On the first question, I think the answer is that what I'm showing you is the allowed rate of return at the transmission company level. What Mark's talking about when he looks at earnings is how the earnings roll up to the Hold Co. level. So obviously, there are things that go on with re-leveraging, if you will, between the two, which drive that difference. On the distribution front, our allowed rate of returns vary from 9.75% to 12.9%, I think, where we tend to try to stay right around those. We might get a little above or a little below, but we manage our investments. That's one of the advantages of having the diversity that we have, is we can move our capital requirements around to kind of balance those needs almost on a real-time basis. So we try to keep them all. And I think on an aggregate basis, I think you would expect to see us kind of stay right around those allowed rate of returns, which should not drive too much in the way of new rate cases.
Unknown Analyst -
I wonder if you could elaborate a little bit on your comments on the Smart Grid. If I remember correctly, you said that the company's view is that it doesn't want to impose costs on customers in excess of what -- the benefits that they might enjoy through operational and other savings. And then I think you also said that you're not planning to roll out the Smart Grid at a rate in excess of what's required by the regulatory authorities. Is...
Well, right now, what I said is we're approaching it from a customer-focused perspective, which means that we want to ensure that long term, the benefits exceed the costs. So on Smart Grid in particular, we did apply for and received a Department of Energy grant to do a Smart Grid pilot. We're actually doing 2 Smart Grid pilots, one in Pennsylvania and one in Ohio. And we're going to use those pilots to study the benefits. And there are 2 sets of benefits. There are benefits to the customer and there are benefits to the management of the grid that we're going to study. And you put them all together, and then based on those pilots, I think we'll be in a very better-informed position to decide, do Smart Grid investments really makes sense for both the industry and the customer?
Unknown Analyst -
Where do you see the principal savings and customer benefits being realized?
Well, I think from a customer's perspective, there could be a lot of benefits. You put a Smart Meter on the house, you give them real-time information about how they're using energy and at some point, real-time pricing as to what the pricing of that energy is. We've got customers right now that have a Smart Meter on their house, and they've got a little handheld device that they can carry from room to room and it tells them in real time how much they're using at that point in time. And it's driving behavior already even without the pricing to match. So I think that's the real benefit from a customer perspective, is they can get smarter about how and when they use their energy. And then that also translates back to the grid management benefit because if you can get customers to use it smarter and to be more flexible, then you can avoid investment that's needed to drive because our whole system is built to manage at a peak-load level. So the more you can do to manage around that peak, that's where the grid management benefits can come in.
Okay. Thank you. Turn it over to my partner, Jim.
Well, good morning. First off, I'm joined on the stage by Charlie Lasky, who is our Vice President of Fossil Operations. Today, I plan to give you a short overview of the FirstEnergy's Generation fleet following the merger with Allegheny Energy. I will touch on the benefits of integrating fossil and nuclear plants, essentially managing all of our units as a single fleet. I will discuss our plans for improving performance of our generating units with the objective of operational excellence. I want to discuss briefly the important challenges that we face in terms of lessons learned from the Japanese nuclear event and the pending Environmental Protection Agency regulations. And finally, I will introduce some opportunities, noteworthy opportunities, afforded us by this new and larger generating fleet.
As you can see, we have a diverse generating fleet that is spread over most of our service territory. The capacity of this fleet is just over 23,000 megawatts. And if you consider only the competitive capacity, we will be the second largest generator in PJM. As you know, we will complete our transition to PJM in June of this year. And finally, the merger has augmented our capacity to the East, affording us better access to those markets.
Our fleet employs a balanced fuel mix. It is approximately 64% coal, 17% nuclear and 20% gas, hydro, wind and pumped storage. As a whole, the coal portion of our fleet is newer and more efficient than the national average. In fact, 3/4 of our fleet, fossil fleet, output, is provided by supercriticals, which are higher efficiency, newer and lower operating cost units.
From an environmental control standpoint, as Tony has already said, more than 80% of our fleet from a capacity standpoint, and 90% of what we actually produce is low or non-emitting and scrubbed.
Let's reflect on nuclear for just a moment. In 2003, we established a fleet structure for managing our three nuclear stations. This approach was derived from considerable benchmarking of the nuclear industry. And as a result of these efforts, today, Beaver Valley is a top industry performer. Davis-Besse is close behind, and the Perry station is steadily improving. In integrating fossil and nuclear, we will take the same approach to our entire fleet, and we will combine nuclear, FirstEnergy fossil and Allegheny fossil.
Our initial emphasis will be to focus on a common vision and approach to safety, human performance and common business practices. We have already experienced sharing resources across our fossil and nuclear fleet. We will expand on this going forward. The result of resource sharing is deferring contract resource expenses and getting higher quality work as our folks take ownership for that work. And while change always comes with challenges, I believe that our experience will serve us well in managing this transition.
We are currently finalizing an integrated business plan for this new fleet that establishes 4 key focus areas. We've established safety as our top priority, and it is key to achieving our standard of operational excellence. This encompasses both personnel, personal and environmental at all of our plants. And for the nuclear folks, it adds nuclear and radiological safety. Our operations focus refers to priorities for establishing improved plant performance and reliability, executing well-planned outages and establishing best industry standards in our operating and maintenance practices. And these areas, these focus areas, are enablers for us achieving our operational financial targets and merger benefits.
I spoke earlier of our experience and success in applying the fleet model in nuclear. A good example of this is forced loss rate, which is an indicator, the best indicator of plant reliability. We developed detailed plans that were sharply focused on improving the material condition of our plants and on addressing human performance behaviors. And as you can see by this slide, the forced loss rate has steadily improved over the last 5 years. In fact, the forced loss rate at our nuclear units in the first quarter of 2011 was 0%. We will apply the same approach to improving the forced outage rate at our fossil fleet and I fully expect we will achieve similar levels of improvement.
By improving forced outage rate and outage execution, improvements in availability and capacity factor will follow. The Allegheny fleet was focused on only availability. That has changed. Our plans are intended to improve all of these metrics. Specifically, our goals are to achieve top quartile performance in availability, forced outage rate and top decile performance in capacity factor for our competitive supercriticals by 2014. Some of the details of how we will achieve this are shown on this slide. The lines show the expected improvement in outage rates and availability for the Allegheny plants over this period. Our dispatch strategy will favor the supercriticals, our most efficient fossil units. And the programs that will be applied are similar to those that have been successful for our nuclear units. These programs will reduce single failures, allow us to better understand the causes of tube failures and put in place maintenance practices that allow us to reduce emergent failures and addressing shortfalls in equipment and human behavior, as I've already discussed. Steady investment in the supercritical units will aid us in achieving these goals.
I have referred several times to the importance of well-executed outages in achieving our goal of operational excellence. We will again use best practices, from nuclear and the industry, in properly scoping and executing those outages. We have successfully completed one of our nuclear outages this year thus far and we have outages underway at Perry Station, Fort Martin 1, Harrison 3 and Mansfield 3. These outages are on track with our plans. I would like to point your attention to an important, very important outage in the fall of this year and that is the Davis-Besse mid-cycle outage that will enable us to replace the reactor vessel head on that unit. Accomplishing this will give us greater certainty going forward in terms of outage duration and it will help us improve safety margins in vessel integrity and radiation dose.
Another way that we're looking at operational excellence is through the adoption of practices that can optimize our resources and reduce our costs; for example, in-sourcing maintenance, engineering and environmental activities and creating regionalized or mobile maintenance crews and centralized shops. Clearly, focusing on the operational performance of our units, our competitive units, creates value for us as a company. In fact, we see the potential for an additional 3 million megawatt-hours on fossil-competitive supercriticals by 2014. This output is then available to Donny Schneider and his FES staff and can be used in implementing our referred to retail strategy.
We expect our capital expenditures as a combined company to decrease in 2011 over 2010. And listed on this slide are some of the more important capital projects that we will undertake over the next 3 years. For fossil, these projects will be focused primarily on reliability and environmental issues. For nuclear, we are replacing steam generators at Davis-Besse in 2014. We are replacing the reactor vessel head and the control rod drive mechanisms in October of this year, as I referred to earlier. We will be replacing low-pressure turbine rotors at Perry and both Beaver Valley units in the years 2012 and 2013. And finally, we will be continuing our dry fuel storage projects at all of our nuclear units.
In addition, as you've heard already, we are setting aside capital to address modifications that may result from changes in NRC and Environmental Protection Agency regulations.
I am sure that everyone is following the news and is fairly current on the Japanese nuclear situation. Although months, if not years, will be -- of work lie ahead in fully addressing this situation, it does appear that the Japanese have turned the corner in addressing the event. As you might recall, these units are older General Electric boiling water reactor designs. For comparison, we look at our FirstEnergy nuclear units. Our units have larger containment structures, greater redundancy in their cooling water systems and more diversity in the back-up power supplies for those cooling water systems.
Additionally, FirstEnergy and the U.S. nuclear fleet has benefited from modifications over the last 2 decades. And we have guidelines plus portable equipment in place for dealing with beyond-design basis emergency situations. We in the industry have taken and continue to take a proactive approach to improving on these mitigation strategies. And while it is too early to project what the regulation will result from this event, we will be proactive in incorporating lessons learned to make sure that our plants are even safer in the future.
I know that all of you are aware of these pending Environmental Protection Agency regulations. I would draw your attention to two that are -- probably present the largest challenge to our industry, and they are the Transport rule and the Maximum Achievable Control Technology regulation. They're both due to become final this year and expected to be implemented in January -- to start to be implemented in January 2012 for transport, and January 2015 for MACT. We will continue to study these new regulations. And as they evolve, we are confident we are well positioned to handle the final requirements that will come from them.
While we agree with others in our industry that current timetables are really unrealistic and that the impact on prices paid by customers will be significant, it is important to remember that unscrubbed supercritical coal is not significant in the context of our overall portfolio. In fact, our preliminary estimate of Transport rule and MACT compliance costs are in the range of $2 billion to $3 billion. That's similar to our investment in environmental compliance over the last 5 to 7 years.
We are also developing for implementation, asset strategies that look at the shutdown and/or elimination of our non-economic generating units. And I'd note that similar shutdowns are likely to take place across the industry, which is likely to have an upward impact on power prices. However, we also have a number of opportunities to offset the loss of this output related to these potential plant shutdowns, and I'll talk to these next.
We already have several initiatives in our plans to increase the generation capability of our fleet. As mentioned earlier, one of the merger benefits is our ability to add as an additional 3 million megawatt-hours output from the Allegheny supercritical fleet by 2014. And 2 significant projects are in our budget at our nuclear units. In addition, we are evaluating additional opportunities for further mining our assets, such as nuclear uprates, particularly at the Perry station, uprates from turbine replacement for our competitive subcritical units and additional opportunities to repower the West Lorain facility, which would give us an up to 200 megawatts by converting it from a simple cycle to a combined-cycle facility.
And finally, as you heard earlier, we also have the option to develop the Norton Compressed Air generating plant, which has a potential of 2,700 megawatts. One of the many advantages of this project is the ability to bring it online in 138 megawatt increments, which flattens the cost of the project but also gives us the opportunity to obtain revenue from it at an earlier point.
So in closing, I look forward to leading this new and larger fleet forward towards achieving our safety and operational excellence objectives, working through the challenges of new regulation and delivering the results that support our company in achieving its financial performance objectives, and achieving our target merger benefits. Thank you.
And with that, I'll turn it over for any questions that you might have.
Unknown Analyst -
I was wondering if you could just share a little more thoughts, if you look at Slide 35, in the appendix, you show the movement in coal plant performance to first quartile, first decile for the entire fleet, which would be better than where you guys have been. Can you share a little more on how you anticipate getting to that higher level of performance out of the fleet?
Well, first off is we intend to improve those metrics to top quartile, top decile by, again, as I've said, focusing on the reliability of them; focusing on the material condition and eliminating the human performance issues that take them offline unexpectedly. And secondly, we are assuming that the market conditions will support running those units as they are available for achieving those capacity goals.
Unknown Analyst -
Okay. And just one other. On the $2 billion to $3 billion of potential EPA-related capital spending, how much of that money would be economic to spend today in the current market conditions? And how much of the capital is currently anticipated in the capital spending budget?
I couldn't hear the first part of your question, but the -- could you repeat it please?
Unknown Analyst -
Yes, how much of that $2 billion to $3 million would be economic to spend today in the current commodity price environment? So based on the current forwards, how much of that money would you actually spend where you get an economic return? And then how much of that is already in the capital spending budget?
Well, the cash flow on that $2 billion to $3 billion that I referred to, when we look at those modifications, it does enter into the 2012 and 2013 capital portfolio. Worst case scenario is the $3 billion, and that does put a little pressure on 2013. But a more reasonable scenario really falls within line on the capital portfolio that we've already presented.
Unknown Analyst -
On the 3 million extra megawatt-hours, to what extent are you using the forward curve or are you using a different set of assumptions? It sounds like based on your answer to Dan's question, that you were using something different than the forward curve. And can you also give a sense of how different from the forward curve are the assumptions that you're using and what the sensitivity is to those terawatt-hours?
Well, I don't think the assumption of the 3 million, and I'm repeating myself, I know, is that, that is what we think our capability of -- for the competitive supercritical units by dispatching them, changing the dispatch strategy, ensuring they are reliable, they're ready to run when called upon and that, again, is focused on the plant material condition and human performance, and that the market is there to place those units in service, based on it. And that dispatch strategy would reflect that.
Unknown Analyst -
So then you are assuming the forward curve when you dispatch those units, is that the right answer?
Yes, we are.
Unknown Analyst -
With regard to the last slide, growth opportunities 2011 to 2013, can you give us an idea of how much it will cost to achieve the entire package? And specifically, can you talk about the cost related to the compressed storage project if you were to go forward with that?
There's an asset team right now that is studying those options and I have seen some of the numbers for the projects. For example, the West Lorain project, there's a couple of options there, and they're in the $1,500 per kilowatt range, both of those. I do not have the cost numbers on the gas plant.
Unknown Analyst -
Just a clarification, I believe, on Dan's question from before. The $2 billion to $3 billion, are we to assume that -- how much of that is in the free cash flow, the corporate free cash flow projections for -- through 2013?
There is none of it captured specifically as projects, but as you have heard already, we have created some set-aside capital money to implement those projects. And as I've said, if we look at the $3 billion, which is the worst case scenario, the cash flow for those projects puts some pressure on that number for 2013. But again, a more reasonable rollout of that rule, and we won't know for sure until it goes final. But a more reasonable implementation of that rule does fit within our capital projections.
Okay. I think that's it. And with that, I'll turn it over to Donny Schneider. Thank you.
Thank you, Jim. Good morning. I'm Donny Schneider, and I'm President of FirstEnergy Solutions. I have responsibility for retail sales, commercial operations, fuel procurement and unit dispatch. Joining me here on the stage is my staff, starting at this side. Jim Melody is my Vice President of Fuels and Unit Dispatch; Kevin Warvell is Vice President of Commercial Operations; Arthur Yuan is Senior Vice President of Sales and Marketing; and Dena McKee is our Controller.
Here are the items that I'll be covering this morning. I'm going to start out by looking at our major initiatives. We'll then take a look at FirstEnergy Solution's strategy, the markets that we compete in, how we use a multichannel marketing approach to be successful in those markets. We'll take a look at our fuel cost, and then I'll wrap up by looking at our risk management strategy.
Let me start by highlighting who FirstEnergy Solutions is. According to KEMA's most recent report, FirstEnergy Solutions is now the second largest nonresidential, and the sixth largest residential retailer in the nation. With total sales of approximately 100 terawatt-hours, FirstEnergy Solutions has more sales than 90% of the utilities in the United States. We have 1.5 million customers and our total revenue is $5.7 billion. If you were to look at FirstEnergy Solutions as a standalone company, we would rank number 370 on the Fortune 500 list. And more importantly, today, we're generating more margin than we did as a regulated utility.
FirstEnergy Solutions is strategically located in the center of the eastern competitive markets and we use that position to offer better prices to customers and capture greater share and margin. And because our plants were designed to serve our customers, at the lowest cost, we now produce about 95% of what we sell. As a result of the merger, we now have an additional 30 billion kilowatt-hours of generation to deploy, which will help us capture even more market share as we expand our retail business.
Our major initiatives for 2011 through 2013 really boil down to maximizing our earnings contribution to FirstEnergy by capturing the highest possible revenue on our sales and minimizing our expenses. At the same time, we'll continue to operate FirstEnergy Solutions in a way that minimizes risk.
As we move forward, we are incorporating the Allegheny asset into our retail strategy, and we will capture the merger benefits. Let me take a moment to highlight a few of those benefits. As Jim mentioned earlier, we'll be enhancing some of our supercritical fossil units to generate an additional 3 terawatts-hours. My team will incorporate those terawatts-hours into our strategy of selling directly to retail customers. Another merger benefit deals with our dispatching strategy. By implementing the FirstEnergy process, we will more efficiently dispatch those units and we will increase plant performance.
And the last benefit I'll touch on relates to coal procurement. Because of our sheer size and scope, we'll become a more competitive player in the marketplace, which enables us to maintain our position as a low-cost producer.
Our strategy is straightforward. We sell the power that we produce in our power plants to our retail customers. There are four factors that influence this strategy. First, we focus on maximizing our revenue through a multi-channel marketing approach. Second, we sell the output from our plants to customers in our geographic region. Third, we focus on minimizing our expenses, especially fuel expense, through world-class procurement. Fourth, we maintain and enhance the efficiency of our plant operations. All of these efforts are supported by working very closely with Bill Byrd's risk team.
FirstEnergy Solutions chooses to sell the output of our generating facilities in geographic areas where our customers can be served at a low level of risk. Generally, we serve in areas that we can serve with our power plants. As a result, we have no customers in Texas and only a limited number of customers in Eastern Pennsylvania and New Jersey. We've been very successful with this strategy in Ohio and Western Pennsylvania. With the completion of our merger, we're expanding our footprint.
We also go deep and wide in the territories that we target. In other words, we pursue every customer class in those markets. We strongly believe that this multi-channel approach is far less risky and more profitable than simply relying on one part of the business. We're all familiar with the risk that is taken on by suppliers who only focus on POLR. To illustrate my point, let me give an example. In FE Ohio today, about 70% of the load has now shopped with a supplier. Those competitors who chose to pursue only the POLR load have watched their market share slip to about 30% of what it was prior to shopping. Meanwhile, by deploying our multi-channel marketing approach, FirstEnergy Solutions now enjoys a total market share of over 80% in FE Ohio.
Home markets include Northern Ohio, Western Maryland, North Central Virginia and Western Pennsylvania, and generally include areas where our generation was designed to serve. Therefore, there is less deliverability risk. The overall size of this market is about 110 terawatt-hours per year, with over 4.5 million customers. Close-to-home markets include Southern Ohio, Michigan and Illinois. These markets are also easily accessible with our generation and do not carry significant deliverability risk. In the market source territories, we want to maintain a presence. However, we have very limited sales. In fact, through 2013, we plan on selling no more than 10- to 12-terawatt-hours of market-sourced generation in any given year.
Now I'd like to discuss our multi-channel marketing approach. Since the first FE Ohio auction that took place in 2009, we have steadily ramped up our sales to large commercial and industrial and government aggregation customers. In 2010, we sold nearly 28 terawatts-hours through our large commercial and industrial channel. And for 2011, we have already achieved our target of securing 40 terawatts-hours under contract. With the completion of our merger, our generating portfolio has become larger. As a result, we are actively expanding our sales channels and product offerings. Those new channels include what we call our medium commercial and industrial customers, mass markets and structured sales. We've dedicated new resources to accommodate the expansion of these new channels, and we've had very promising early results. We presently have more than 27,000 medium commercial and industrial customers, with an annual load of 1.9 terawatt-hours. We believe we can grow this sales channel to over 3.4 terawatt-hours by 2013.
In the area of mass-marketing, excluding government aggregation, we now have approximately 100,000 customers with an annual load of 1 terawatt-hour. We have undertaken several new pilot programs that have proven to be successful, and we'll be rolling out these programs to expand sales in the future. We view mass marketing as both an offensive tool and a defensive tool. And we're targeting growth in this segment of our business to about 3.3 terawatts-hours by 2013. But depending on our success, it could be more.
We've also had outstanding results with our government aggregation sales channel, where we have achieved 97% of our target this year of securing 14.3 terawatt-hours under contract. Currently, we have 1.4 million customers through government aggregation throughout Ohio, and we'll continue to seek opportunities to expand. We strongly believe that government aggregation is the most cost-effective method of bringing savings to residential customers. And by 2013, we expect to increase our sales in this channel by nearly 30%. That equates to about 400,000 customers. We'll also continue to participate in POLR auctions and RFPs. But those sales will primarily be dependent in our success in our direct retail and aggregation sales.
It's interesting to note, the sales position we inherited as part of the merger looks very much like the portfolio we had 2 years ago after the first FE Ohio auction, very low on POLR and very short on retail. Because we understand how to move from POLR to retail, we're very excited about the opportunity to move the Allegheny assets into direct retail sales. We also look forward to taking advantage of Allegheny's expertise in the muni and co-op sales channel to enhance our structured sales. We expect to grow this channel to just over 3 terawatts-hours by 2013.
Finally, consistent with our past practice, we'll hold about 10% of our portfolio for wholesale sales to preserve market upside or to cover unexpected unit outages or increased retail sales.
Here you can see what we've accomplished over the last 2 years through our multichannel marketing approach. The key takeaway is that FirstEnergy Solutions has been very successful in transitioning from a company that relied heavily on regulated sales to one that can perform very well in a competitive marketplace.
Let's take a look at 2009. Our revenue was just over $4 billion on sales of 73.4 terawatt hours. A large portion of our sales came from POLR and regulated sales. In 2011, our revenue is projected to come in at over $5.7 billion on sales of 97.8 terawatt hours. However, POLR and structured sales now only make up about 1/3 of our total sales, while the vast majority of our sales are coming from direct retail channels.
In fact, today, we no longer have regulated sales that are served by FirstEnergy Solutions. Looking forward to 2013, we expect to grow our revenue to approximately $6.6 billion on sales of 112 terawatt hours with an even larger percentage of our sales coming from direct retail.
Now I'd like to point out here that our renewal rate in our home markets is over 90%. This exceptional renewal rate can be attributed to the value we offer our customers. More than just price, we form long-term relationships, we keep them informed about market movements, and offer products that match their tolerance for risk in the marketplace.
Now looking at fuel, we simply need to be the lowest-cost producer in our region. That's how we can be competitive in the retail marketplace and capture greater margins. We will accomplish this by continuing our tradition of aggressively managing this process and achieving efficiencies in our supercritical coal and nuclear fleet.
Over the past 15 years, FirstEnergy Solutions has perfected the ability to switch fuels on-the-fly, allowing us to burn a wider range of coals to keep our costs low. This fuel blending program will be implemented at the Allegheny plant to lower fuel cost across the board.
Going forward, FirstEnergy Solutions will purchase nearly 40 million tons of coal per year and our goal is to leverage our flexibility, our size and our physical position to ensure that we are the lowest-cost producer in the region.
As all of you know, nuclear fuel cost is increasing, but it isn't volatile. That is because fuel expense, in any given year, represents the weighted average of fuel purchases made over the previous 5 to 6 years. The 4 main components of nuclear fuel costs are buying the uranium and then converting, enriching and fabricating it. With each one of those components, FENOC maintains multiple contracts with varying terms and multiple counterparties and pricing mechanisms to provide price diversity. Through the combination of strategies we will deploy to manage fuel cost, we believe that we can maintain essentially flat fossil fuel expense over the period 2011 through 2013, and only a modest increase in total fleet fuel expense. Although our nuclear fuel cost is increasing slightly, we're about 15% below the national average according to the U.S. Energy Information Administration.
Bill Byrd has already covered our sales from a risk perspective, so I won't spend a lot of time here. This slide indicates our 2012 sales position. As Bill said, our plan is to have 90% to 100% of our sales under contract by December of this year. Let me simply point out that not only does this approach makes sense from a risk perspective, but it also makes sense from a long-term earnings perspective.
From a sales perspective, our strategy allows us to establish an average contract duration of 36 months and then renew those contracts at a rate of about 3% per month. The strategy works for our company, as well as for our customers who are looking for long-term price stability.
I view this strategy as very similar to dollar cost averaging when investing in the stock market. Most of the research that I have seen would indicate that the returns over the long haul associated with dollar cost averaging are better than those associated with trying to time the market. Here you can see our 2013 forward sales position. Today, we have about 1/3 of that position closed.
Let me close by saying FirstEnergy Solutions is well positioned to continue to grow our earnings contribution. We have a proven sales team that will maximize our margins as we grow sales in our region. Our seasoned fuel and unit dispatch teams have a strong track record of delivering superior value from our assets. And our close integration with Bill Byrd's risk team, combined with our conservative approach, will ensure steady, predictable results year-over-year.
Like to thank you for your time this morning. Now I'll open it up for questions.
Unknown Analyst -
It seems like one of the big opportunities with the Allegheny purchase was to essentially take their -- how they're selling their power and market it in a more efficient way. Could you maybe talk about the competitive landscape going forward? It seems like last week, we had another announcement that Constellation and Exelon are trying to achieve the same thing and how does that play into your strategy going forward and do you see risks in the competitive marketplace because of that?
That's a great question. Relative to Constellation and Exelon, two very, very good companies, obviously, they're going to be very competitive. But one thing that I look at it is that: A, it's good for the marketplace. Constellation and Exelon think very similar to us when it comes to the construct of the marketplace. And so in a lot of ways, I think that they'll be an ally in helping to push forward some of our initiatives on the way that marketplace ought to develop. So sure, they'll be a tough competitor. But in the main, I think it'll be good for us to have that help that we need to push the marketplace forward.
Unknown Analyst -
Have you guys, I guess, try to continue to expand the retail business and maybe go broaden markets, does that -- or would you guys have interest in acquiring further assets? Is that going to eventually lead to that strategy? I mean, obviously, that's at bat, so the areas where you don't have assets, it kind of leads to the conclusion that, that would be somewhere you would be going.
Yes, I think really your question is around growth. And I think initially, in the timeframe that we're talking about here, we would look at growth from our existing asset base as we mentioned, as I think Jim mentioned, we're looking at 3 terawatt hours of additional output. Obviously, within our home and close-to-home markets, there's ample opportunity to take those terawatt hours to the marketplace. In addition to that, we'll continue to work on reducing our costs to help grow our earnings contribution. So I think if there's anything from an asset procurement, it would probably be quite a ways down the line.
Unknown Analyst -
Yes, Donny, could you be a little more detailed on the coal strategies and just maybe a little more explicit on where can you source coal more effectively? And in that context, just the risk of higher transport costs given the energy environment we're in and have you encompassed that in your forecasts?
Sure. That's a great question, Steve and I'll take the 30,000-foot shot at it and then I might ask Jim to get a little more specific. Over the last 15 years, one of the things that we've really perfected at FirstEnergy Solutions is being able to take advantage of fuels that are not necessarily attractive to most of the generators. We were one of the first movers to step into Powder River Basin in a big way, and we were able to do that with much less capital investment than some of our competitors. Years ago, we were burning some distressed coals. At one point, when I was running the Mansfield plant, we even burned petroleum coke. It's very high heat. There's some downsides to it. But the bottom line is, is that we will take advantage of every opportunity we can find to reduce our fuel cost.
As Donny said, we're going to look at all of the opportunities, all the different types of fuel blends. I can't give a lot of specifics. We have an RFP on the Street right now for a very wide spec of fuels and we will evaluate those on a delivered basis. Our strategy is to say, "What is the cheapest cost fuel delivered to the boiler?" So we're going to take the transportation costs into account in finding and executing the opportunities to create the value here.
Unknown Analyst -
Yes, my question is more on retail competition. As you increase your market share and penetrate other service areas, how are they reacting from a pricing point of view? Could this lead to a price war in the industry and lose the margins?
That's a great question about a price war, and I might ask Arthur, our Senior VP of Sales and Marketing to help me on that. Generally, we're not seeing that today. I don't know what the future would hold, but today, in a lot of cases where we've established long-term relationships, sometimes we'll go head-to-head against the competitor. Other times the customer, as long as the customer feels like we're treating them fairly and that our price is kind of in the range that they want to see, we're not seeing a lot of competition. So with that, maybe, Arthur, would you like to add anything?
I would just say that it depends on the marketplace. I mean we're -- we see a lot of competition maybe in -- out east, for example, you'll see in PJM territories, specifically like in PT&L you may have 10 competitors, whereas in Duquesne you might have 3 or 4 competitors going after one RFP or one particular customer. So it really depends on the marketplace. Even in Illinois, for example, you'll see many competitors in ComEd territory. But you'll see quite a few less in Amory. So it really depends on the marketplace. And yes, we do expect to see more competition, but we've actually been holding our own pretty well without a lot of price compression in the marketplace, in the markets that we consider home.
Unknown Analyst -
Donny, two quick questions. The incremental 3 terawatt hours from running the Allegheny plants more efficiently, that's on top of the 110, so 113 ultimately? Or is that baked into that 110?
Jim's numbers and my numbers are consistent. So when you look at the slide, I think the 3 terawatt hours are burnt into the slides in 2013.
Unknown Analyst -
Got you. And then the second part is, relative to your revenue slide, it looks like the 110 terawatt hours and $6.6 billion of revenue somewhere in the neighborhood of $60, which looks like that $59 that you're expecting. How do you maintain those revenues flat over time from '11, '12 and '13 with capacity prices falling somewhere near $450 million, $470 million.
Yes, so that's a great question. And I would have been surprised if I didn't get that question. I think you're probably referring to Slide 38 in the appendix, Slide 37 in the appendix. So on Slide 37 of our appendix, we provided more detail than we have in the past. You can see by year, by sales channel, what our volumes are, what our rates are expected to be and, of course, then the resulting revenue. And so the real question comes down to this: What is my level of confidence of being able to achieve those sales rates at those prices? And it's a very high. If you look at those glide paths that I showed earlier, and that Bill Byrd showed earlier, for 2012, today we have about 66% of the volume locked down. We didn't show the corresponding revenue, but I look at it every week, and today we have about 66% of the revenue locked down. For 2013, we have about 1/3 of our volume locked down. We have about 1/3 of our revenue. So right now, we're right on glide path for both volume and revenue. So confidence is very high.
Unknown Analyst -
On the government aggregation, you have your projected volumes growing by 30%. It's my understanding, some of the states are not, like Pennsylvania, are not in favor of aggregation. So is this primarily in Ohio, outside of your existing territory?
Well, let me address the Pennsylvania piece first. Pennsylvania is obviously working through a process. I think their objective is to figure out how to bring savings to retail customers. And we look forward to working with the state. I think our interests are aligned there. We would like to serve more customers and bring savings to those customers in Pennsylvania. But we'll just have to see how that plays out. State of Ohio, obviously, we've had good penetration. There's still quite a bit that we can do in the state of Ohio. In our Southern Ohio, what we refer to as close to home, we've made penetration in all but one EDC. From a government aggregation perspective, we're going to continue to push in those EDCs. And of course, Illinois has a government aggregation.
And with that, I think I'll turn it over to Gary Leidich. Thank you.
Okay. Well, thank you very much, Donny, and good morning, everybody. It's delightful to see you all today. What I'd like to do is talk a little bit about kind of where we are with the Allegheny Energy and FirstEnergy integration process. Little bit of review on the process and kind of what we said we were going to do last May and what we are doing. Quite a bit on projected merger benefits and costs to achieve and how we measure those. Try to give you some very specific examples on some opportunities across the enterprise, probably you've already heard from a number of speakers on what we're doing in, particularly in the operating side of the business. I want to spend a little bit of time in tracking the merger benefits. Most companies go through these grand announcements, and as they're end of the merger, they declare victory about how well they're doing, but they really have a hard time trying to figure out if they're really getting what they said they were going to do. And I want to talk about the process that we have in place to ensure that we do what we say we're going to do and that the merger benefits are very real and they're tangible, and they're highly transparent within the organization. And then finally, what I'm going to do is a little bit of translation because most of my presentation is in cash. And then, of course, you're all interested in earnings, so we'll do a little bit of translation from how we look at it from a team perspective with cash, and then translating that to the earnings benefit.
Talk a little bit about the process. So let me start with that. A number of us have been involved in several mergers, and I was talking during the break, I won't mention any industry veteran’s name in public to embarrass you guys, but it's hard to believe that we put Cleveland Electric and Toledo Edison together 25 years ago this month. And that was kind of the beginning of many, many mergers that happened in our business. It was a rough and wild ride. I recall it very vividly. But the point is, a number of us have been through many transactions, and a number of folks on our core team that worked on this particular merger have been involved in all 4 of FirstEnergy's mergers. So we bring a tremendous amount of experience to bear. And from that perspective, this merger was really fairly straightforward for us. We had about 100 core team members, about 50-50 split between Allegheny and FirstEnergy. Again, tremendous experience. We spent 7 months full time in Akron. We also had a team of folks dedicated to the retail side of the business, and because of the competitive situation, they were FirstEnergy-only individuals. So Donny and his team started working on what we would do from a retail strategy long before day one. We had about a dozen teams that were on the ground, and I think we did a fairly efficient process. We were well positioned going into day one, really ahead of the regulatory process. We had a lot of executive oversight. The executives that are here today comprised that oversight, in addition to the Allegheny folks. We had about 10 executives on a steering committee that provided continuous oversight of the process. So the same people that run the company were those that were involved in inventing the combined company to begin with.
And then finally, we had a standalone financial team rather than burden all the teams with all the number crunchings. We've been through that in the past. We had a financial team that was really sharply focused on tracking what we call the most important thing in the merger benefits, which are the cash. And it's very straightforward, for operating types and individuals in the organization not familiar with financials to make sure that we stay sharply focused on something that is very simple. So as we went through the entire integration process, we stayed very focused on cash. And at the end, we converted that to earnings, for noncash items and it just gets away from a lot of confusion and a lot of challenges.
So as I talk to you today, the bulk of my discussion will be on cash, focused on the first 3 years of the transaction. Obviously, the company's kind of morphed together after year 2 and 3, so we get into year 3, 4 and 5 and we will sort of lose track of this, and that's fine. The most important thing is the first year or 2, to make sure that we implement the strategies that we said we were going to implement.
Now those strategies include O&M opportunities, revenue uplift, savings associated with capital as well. So we have all of different slices of cash in our approach here. So let's look at the big picture. This is 2 pie charts, first of all the gross and the gross cost to achieve. The total net is $1.3 billion over the 3-year period. This is the first 3 years on the merger. The first 3 years of the merger, I will get to translating that to '11, '12 and '13 when I get to the end. Given that the merger didn't close until March 25.
Those first 3 years, that benefit is $1.6 billion in terms of cash savings. Most of that as you can see is in retail market operations, fuel and generation side of the business. When we announced this transaction to begin with, we said this is a great opportunity to bring the generation footprint together and to implement a retail strategy, which we've talked about in the last couple hours in Allegheny service territories. So that what we're doing and lo and behold, that's where the benefits come out.
We also had a fair amount at the corporate center and Utility Operations. And I'll talk more about those. In terms of costs to achieve, like all mergers, there's a pretty significant IT or information technology cost to achieve. That's about $100 million for us, pretty substantial portion of the total and, of course, there's also employee costs in terms of severances and relocations and so forth.
Our generation operations costs to achieve, Jim referred to that generally when he was talking about the money that we have to invest in the Allegheny facilities to improve reliability. So there is an investment there that we need to make over the first few years of this to get that additional 3 million megawatt hours that both Jim and Donny talked about.
So breaking this down a little bit, let's first talk about the retail fuels and generation fleet operations, about 60% of the total over the 3-year period. Donny mentioned, deploying the Allegheny competitive fleet into the retail sales channels comprises a pretty significant portion of this. We also have a number of capital projects that we've deferred on the generation footprint. In fact, when I get to utility ops, it's the same issue. We defer a lot of capital, cancel a lot of capital. Our approach on capital expenditures was different from Allegheny's. So we took FirstEnergy's approach and said, "Hey let's implement that approach in the combined fleet," and that resulted in a fair amount of savings in both energy delivery and in this particular piece with the generation fleet.
Economies of scale across 35 to 40 million tons of coal. You've heard from Jim and Donny just a bit ago on coal procurement and we have a lot going on there. But we also have significant synergies in Transportation.
Last May, we talked about, we probably have barges passing in the Ohio River between the Allegheny procurement of coal and FirstEnergy and we sort of quipped about that as a humorous example, while the reality is we do have that. And what we've found is significant synergies in transportation, both in the barge side of it, in river transportation and also on rail transportation. Allegheny brings us some expertise there and we have substantial expertise in rail transportation. So we have a number of opportunities there that we're exploiting, and the team's doing a very good job there. They also mentioned coal blending. We will be implementing blending at our fossil plants, reduces overall costs, we're getting synergies and improved performance at the facilities as a result of that.
Jim mentioned the centralized maintenance operations. I'll give you a number there. Over a 3-year period, it's a $40 million to $50 million savings and what we're really doing there is trading contractors for our own people. And we expect the quality of the work to improve in the shop floor, and we also expect to be able to reduce our costs accordingly. If you think about the map that Jim showed you earlier in terms of where these plants are located, not unlike our 10 utilities on the generation side of the business, our 44 power plants, they're all in the same neighborhood. So Jim's going to be able to put a maintenance facility, a centralized shop and provide common resources that heretofore contractors provided at our facilities. And then finally, we've got dispatch opportunities in terms of our philosophy on the shop floor, and how we dispatch the unit into the grid. In terms of costs to achieve, it's not going to be free to get after this. We've got about $40 million to $45 million of investment in the generation fleet over the 3-year period. Jim showed you the outage schedule and what we need to do at some of their facilities, 1 or 2 modifications. All of those things, very sharply focused on improving reliability. So we're trading off some lesser important capital expenditures for reliability improvement capital expenditures.
In utility ops side of the picture, about 22% of the total over the 3-year period and Chuck talked about a few of these things. Capital philosophy. We have a planning criteria. Allegheny has a planning criteria. Naturally, they're different. All utilities are different. And we apply our planning criteria to the Allegheny distribution fleet and we get savings. We get the ability to defer projects and cancel capital projects. We also talk about the asset management side of the business and being able to control those capital projects with a simple asset management group, our ability to improve storm response, vegetation management, obviously, the call centers, our customer service. And again, if you look at the map, these 10 utilities are all in the same neighborhood, so we have a tremendous opportunity there. I didn't mention supply chain and generation, but we also have supply chain savings in utility operations as well. In fact, our total cash supply chain savings over the 3-year period is approaching $200 million of that $1.3 billion. In terms of costs to achieve, we have gone to a decentralized maintenance approach. That cost is under $10 million and that's been well implemented already. So we're well along on that. So you can see here significant benefits with really a very modest cost to achieve.
And finally, on the corporate center, this is really sort of the normal routine kinds of issues that you would see in a merger. Let me give you a couple specific examples. Probably, the best one, the easiest one for us to talk about certainly is the IT support. In the case of information technology, a few years ago, Allegheny made the decision to outsource their IT function. Well, we can bring that back in-house, which we're doing as a result of the integration that's already being implemented and the savings for that is $30 million to $40 million over the 3-year period.
Just to give you a couple of metrics there, there's about 250 contractors that we will displace with literally a handful of FirstEnergy employees because the synergies are very real in terms of IT programming, both applications and mainframe SAP-kind of projects. On the SAP front, we will need the first year to fully integrate the 2 platforms. Both companies had SAP, so we were delighted at the beginning that was going to work out very well and naturally they were different versions and different revisions, so we still have about $100 million expense there to go through. And that first year, as you could see in the cost to achieve is most of that.
And then also in this category is elimination of a lot of duplicative corporate functions; a long list of issues. Insurance is a good example, about $15 million of savings over the 3 years. So we could go through a long list, a laundry list of items that's really very typical when you put 2 companies together here.
Other than the IT, I would characterize this as a very normal kind of transaction. We have been very focused on ensuring that we minimize the job loss in the communities we serve. Of course, that was part of our regulatory process to achieve the approval necessary on the merger. So we're very sensitive to that.
So a lot of this is contracting costs, capital costs, out-of-pocket costs, supply chains, suppliers, vendors and so forth, as opposed to sort of the employees. Like many utilities, our demographics are such that we will achieve significant reductions just through attrition itself over the next several years. So we expect that to happen. And we're working now to try to find the sweet spot, if you will, in terms of headcount for the overall corporation.
So again, you have all these ideas, you have all this savings, you have all this sort of advertisement about how well you've done, and that's on the drawing board. And the real challenge is making sure that gets fully executed day-to-day on the shop floor.
So what we've done as we've taken the entire merger process which is about 289 initiatives, we've combined those, we've restructured those, we've repackaged those. And each of -- I was going to introduce my team earlier here on the stage. I have my own personal panel, but actually that panel is sitting in the room. And that panel is the executives within the company that are accountable and responsible for achieving their 3-year targets. We sliced the first year of that up into a KPI, so we have a KPI for the executives for merger synergies for 2011. Again, we took the first year, we took 10 months of that and said here is the target. So part of our variable pay is focused on how well we do in 2011 in terms of getting these synergy savings off to a good start. So we've boiled the entire process down to the 65 initiatives that you see here across the different business units that you also see here.
So there's tremendous amount of transparency on these initiatives, there's a high level of accountability and responsibility. And as we go through the process, particularly this year and into next year, we will hold ourselves accountable for achieving what we said we were going to do. And we'll provide periodic updates to you in the investment community as well.
Finally then, to translate this to earnings, there's a couple of things going on here. First of all, this is a 3-year look but we've now put it in terms of calendar year. So this is the earnings impact in 2011, '12 and '13. So what you saw before was a 3-year look, which starts as of day one. This is a 3-year calendar look. And then we've also translated all that cash into earnings, so this synchronizes with what Mark showed you earlier in terms of the pretax earnings uplift as a result of the combination of these companies. You can see here the pretax commodity margin portion of it and the O&M portion of it. And again, the corporate center takes a little bit of a bigger slice here because there's noncash earning items that come into the picture. But you can also see that the generation footprint, the retail fuels and fleet operations is still a substantial portion of the value for this transaction. So the fundamental strategy for this transaction remains unchanged.
So the bottom line is a lot of learnings from the past. You can't be successful without a very structured process. We had a very structured process throughout the summer into the fall and through the winter with the integration teams, and now we have a very structured process particularly in 2011 to ensure that we achieve what we said we were going to do.
The strategic values are really across the enterprise, a number of pleasant surprises in what I discussed in my commentary. The fuel guys are particularly modest. But if you think about fuel, and we've got about $2-plus billion annual expense in fuel, the fuel savings in this merger are in the range of $100 million over the 3-year period, and that includes transportation and everything. So a tremendous opportunity in fuel.
And just when you look at transportation, I'll give you an anecdote on fuel. At any given day, we've got $50 million worth of coal in transit somewhere either on a barge, a rail set, on a way to a power plant, from a mine to a storage location. So the transportation opportunities alone are tremendous, and the team is going after that.
The complementary assets, the geography, the footprint, the neighborhood, makes all of this very achievable. We've also found that the cultures are very similar. Western Pennsylvania's a place we know how to do business in; we know the people, we know the employees. The plants are very similar to ours; some are identical. Tremendous amount of interchangeability among the various pieces parts in our power plants and in utility operation. Again, we've got a high level of discipline and are tracking to ensure that we achieve the results, and the earnings benefit really give us a great bridge through these challenging economic times. Timing for this transaction is absolutely perfect.
When we announced this deal last February, we said is a great opportunity to put 2 solid companies together. And you know what? That's what's happening. We are achieving this great opportunity to put these solid companies together.
So with that, take any questions anybody has and then I'll turn it over to Tony. Do we have any questions? I knew they were all answered already. All right, well I'm not foolish. I'm not going to ask twice. I'll turn it back over to Tony. Thank you very much.
Well, thanks again for joining us today. I'd also like to thank my team, not only for their presentations today but for their diligence in executing our strategy. This team has a track record of doing what they say it's going to do. We said we'd separate our generating assets and we did, and we're the only utility in Ohio to do so. We said we'd successfully transition to competitive electric markets in Ohio. We did and now the others in the state are scrambling to catch up.
When the economy dropped in 2009, we said we'd achieve $350 million in O&M savings. We did, and those savings are still benefiting our company because they produced a lower cost structure. And we said we'd complete our merger even when the regulatory environment seemed unreceptive to M&A activity. We did, and the merger will be accretive this year ahead of our initial expectations.
Today, we've described our plans for achieving strong financial results with consistent earnings, positive cash flow and a strong balance sheet. We've described how we'll grow our competitive business, accomplish steady improvement in our distribution business and achieve the benefits of the merger. And I'm very confident that this team will, in fact, deliver on these commitments. It is an exciting time for FirstEnergy, and we're looking forward to taking advantage of the opportunities this market, this new organization, this business and our industry will bring to us.
Thank you very much. Now I'll take some questions, if you have any.
Unknown Analyst -
Tony, just one clarification I wanted. To what extent are those merger benefits on the commodity side based upon current forwards?
There's been a lot of confusion with respect to forwards and how they look at our commodity margin that we're showing as merger savings. The fact of the matter is, the way we look at it is where the margin opportunity is, and the forward prices are not impacting the margin expectations that we laid out initially, or the margin expectations that we're using today with respect to our ability to capture those as part of the merger benefits. So it's really a margin analysis difference between what Allegheny could achieve given their strategy versus our strategy of going to retail.
Unknown Analyst -
So that $59 of expected revenue is good at the current curve?
Yes, it is. As Donny said, he's already locked down about 33%-or-more of it. Well, while I'm waiting for another question, there's one thing I'd like to clarify for everyone. There was a question asked earlier, I think to Jim about the timing associated with capital expenditures for environmental expenditures that we might anticipate as the result of the new rules. Obviously, the 2012 and 2013 capital budgets have a line item that say it could be up to $100 million, and that is burned into the numbers that you've seen today. What we're looking at from the standpoint of additional cost to cover the $2 billion to $3 billion that we may have to spend depending on how the rules work out. The way we're looking at those is basically, we're not likely to see those in this time frame in any significant or substantial amount above what we've already identified. We probably wouldn't start construction on any of those types of facilities until very late in 2013, if then. So it's more likely a 2014 and '15 type of event or beyond. So I hope that clarifies how we're looking at it at this point in time. Right now, we think the $100 million that we have in the budgets for '12 and '13 will help us get through probably the initial kinds of engineering work that's going to be necessary before you can decide what you're going to do at each specific site.
Unknown Analyst -
And Tony, just to further clarify on the $2 billion to $3 billion of environmental. How much of that would potentially be in the merchant business as opposed to regulated generation?
Well, at this point, almost all of that would be in the competitive side of the business. It's all dealing with supercritical plants. We would not anticipate expenditures on the non-supercritical facilities.
Unknown Analyst -
Okay. Is there -- would you care to speculate on sort of where that money would be spent? Would it be on scrubbers or bag houses, and sort of what units?
I don't -- every unit's going to have to be looked at individually. We only have one supercritical unit that is not scrubbed at this point. Every other supercritical unit we have is scrubbed. Many of them have SCRs on them. Many of them have advanced precipitation equipment on them. Some of our facilities already have bag houses on them. So much of what's going to take place over the next year or so is to understand how all the rules work at a specific site because there's site averaging allowed in some of the rules and how you apply them. So as we look at each facility, each unit, then we'll decide what's the best compliance strategy to meet the requirements that may be in existence for that facility. So again, it's very, very site-specific in the main. You're probably talking about bag houses in many areas and that type of retrofit. But the rest of the basic equipment on our supercritical fleet is in pretty good shape in terms of having scrubbers on, having SCRs on many of the units, having cooling towers on many of the facilities. I mean, we're -- our fleet itself is fairly modern with respect to pollution control equipment at this point.
Unknown Analyst -
I was wondering if you could discuss the funds from operation forecast. It trails down between '11 through '13. And I want to make sure that the roll down is basically, I think, a loss of depreciation like regulatory mechanics, is that right?
I'll have Mark get into that, but I think the largest component of that drop off in cash is the bonus depreciation going away. So you're seeing increased federal income taxes at that point, which are not otherwise offset in '11 and '12.
Unknown Analyst -
Okay. So the 3 to 3.2, that would be barring any material changes in market prices, et cetera. That is kind of a good steady state number to think about?
Unknown Analyst -
Okay. With your asset sale proceeds of $800 million to $900 million, does that incorporate -- is that just true cash or does that incorporate like if you had debt on Signal Peak that, that debt may be retired? Like how do I think about that number?
Well, that is the cash component of it. The Signal Peak, as you know, we do consolidate the debt at Signal Peak even though we don't own 100% of that asset. That debt on sale would be deconsolidated. So it would no longer be part of the debt structure of the company.
Unknown Analyst -
But then that would be in your debt reduction target of like $1.5 billion to $2.2 billion?
Unknown Analyst -
Okay. And then you didn't -- I see debt-to-cap targets but I didn't see any FFO-to-debt numbers, and I was wondering if you could talk to where you expect FFO-to-debt to trend towards at the different, like at the unregulated, the corp and maybe the utility generally.
I'm going to turn that over to Mark. I think they're all going to be with inside the credit rating metrics. So Mark, if you want to add any more color than that, go ahead.
You did so well on the first 2 questions. We are targeting investment grade, our desire is to move it to the middle of the B range across the board, and the FFO targets that we have would align to that.
Unknown Analyst -
Tony, you talked in the generation discussion about deferring certain Allegheny capital projects. Could you, a, maybe quantify how much of that is a benefit? And secondly, are they deferred or a combination of deferred and canceled? And in what sort of time frame for the deferred would that come back to you?
That's why I asked Gary to be up here. I'm not -- again, I look at the company from the standpoint of overall processes. Obviously, things get deferred, they get pushed back, they might be added in at a later point. Things have, in fact, been canceled. And I think it's a balance overall every year as we look at the capital budgets. Gary, do you have anything else you want to add on that or have some examples?
Yes, it's a combination of deferred and canceled projects. And the range is about $200 million to $250 million over the 3-year period. A number of different things, not any one big thing sticks out. But I will tell you in the early years, particularly in '12, there were some environmental projects that Allegheny was going to do that we're not going to do. We're going to see how the game gets played. And so consistent with our environmental strategy, which is let's see how this plays out, as Tony alluded to, those expenditures are more likely to come in, in the '14, '15 time frame. So we're not going to do anything we don't need to do. It's that simple.
Unknown Analyst -
Tony, Mark had mentioned earlier that the debt paydown would -- may or may not happen depending on how big a premium it would be to pay down some of the debt and it would be a net-type number where you kind of keep cash on the balance sheet. How can you help us mitigate the potential temptation to deploy that cash while it's on the balance sheet? And how long would you expect to kind of keep that cash there to maintain that net number that Mark was talking about?
I'll like, lay it out for you, that is our expectation, that is in fact how we're going to manage this business. So whether or not we have opportunities to take out longer-term debt with high premiums, that's just a function of what's the best use of your cash. We clearly have opportunities to take out pollution-control notes that can also be issued at a later date when it becomes more advantageous, if you will, to take and pay additional call premiums on longer-term debt. So there are ways to balance it. We'll hold the debt. We know what we need to accomplish over the next several years. We've laid out a game plan for you, and that's the game plan we're going to follow.
Unknown Analyst -
Just some clarification on your unscrubbed coal plants. Are you -- am I interpreting you correctly that you're still trying to ascertain how many of those plants you might scrub or shut depending on how the final rules come out? Or do you have an idea in your mind of how many megawatts do you might ultimately shut? And then additionally, about your competitors sort of around you, as you look at the competitive market, how many megawatts do you think will be shutting around you based on HAP/MACT?
I think somebody already earlier today talked about how many megawatts they think people will shut down potentially in PJM. I'm more focused on what we need to do as a company. And as I look at our options right now, many of the smaller older coal fire fleet just simply would not be economic to put on additional environmental equipment. It's far more economic for us to use that capital that we would have otherwise deployed in a 50-year-old plant to either modernize the fleet someplace else along the mining of the asset strategy that we've laid out, to spend more dollars in terms of making the plants that we already have more efficient, the ones that will in fact survive or to add to the fleet by either expanding at the compressed air facility or expanding our gas facility at West Lorain. So I think those are the trade-offs you make. The best part about FirstEnergy portfolio at this point is that, in fact, it has options within its fleet to replace the generation that might otherwise be lost as a result of these new environmental requirements. And that loss, I think, is identified as about 9 million megawatt hours a year, so not a significant part of the overall fleet generation and well within our capability of increasing the performance of our other facilities to cover.
Unknown Analyst -
Just a follow-up on the debt reduction and having this net debt number. Have you considered actually defeasing some of the debt because that would actually accomplish the same thing?
We've looked at all the different options. We also think interest rates are going to go up, premiums will come down. There are some issues that we can get today. There's $500 million due at Allegheny Energy Supply next year, $300 million due at CEI. So there's a lot of debt already coming due, not significant, but still out there. And we have looked at that specifically.
Okay. Again, thank you very much for your support. We truly do appreciate it at FirstEnergy. And we are working to make this company a very special place to work and a very special place for our shareholders. Thank you for your interest.
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