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Dominion Resources, Inc. (NYSE:D)

Analyst Meeting

March 04, 2013 10:00 am ET

Executives

Thomas Hamlin

Thomas F. Farrell - Executive Chairman, Chief Executive Officer, President, Chairman of Virginia Electric & Power Company, Chief Executive Officer of Dominion Energy and Chief Executive Officer of Virginia Electric

Mark F. McGettrick - Chief Financial Officer and Executive Vice President

Gary L. Sypolt - Executive Vice President and President of DTI

Analysts

Greg Gordon - ISI Group Inc., Research Division

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Brian Chin - Citigroup Inc, Research Division

Dan Eggers - Crédit Suisse AG, Research Division

Thomas Hamlin

If everybody could take their seats, we'll get started. Good morning, morning, welcome. Thank you all for coming. Thanks those of you who are listening on our webcast to our analyst meeting. Before we get started, obligatory safe harbor statement that many of the statements we'll make today constitute forward-looking statements and suggest you consult our SEC documents for a list of the risks and factors that might cause our projections to differ from our current estimates.

We have a pretty full 2 hours for you today. First, we'll have Tom Farrell just going over our strategic plan and our outlook, followed by Mark McGettrick, who will go over the financial side of things, and hopefully, we'll have 30 minutes or more for questions. So at this time, I'll turn it over to our CEO, Tom Farrell.

Thomas F. Farrell

Good morning, everyone. Is there anybody out there? Good morning. Oh, good. Okay. Glad to have you all here. At Dominion, we don't start any meeting without talking about safety. It's our underlying value that drives all the rest of them. You can see here, this is the OSHA recordable rate, which means injuries that -- or accidents that happen in the workplace. It means that for every 200,000 man hours, there's less than 1 incident, which -- so you can see we've cut it down by 2/3 over that period. For your purposes, you may need to think about this or you should be thinking about this as a leading indicator of operational performance, not just across our company but across any utility company. So it's a fact that we think it's important for the safety of our employees. You should be thinking about it, I think, as an indication of operational excellence. Our company is the safest company in the southeast exchange, which is all the southeastern utilities. We ranked #1 in 2012, which is an indication that we're proud of this, we have a long way to go, our people work hard to pull this off.

Okay. Dominion strategy. Before we took you -- take you through the growth plan, we thought it would be useful to show you how we got where we are, talk about why we got where we are, and maybe give you some insight into where we're going from here. So we started 2006 with this story and -- because this is when we started changing our business model.

At this point, you can see here we were about 55% unregulated, and that was going to drive itself closer to 70% unregulated over the next couple of years. We were sitting looking forward. And remember, this was post-Katrina, near the heights of the post-Katrina commodity markets. Gas prices were high, electric prices were high in our merchant business, we had a very large and growing E&P segment. We had some big finds in the Gulf of Mexico. Remember -- may remember the name Devil's Tower, that we're going to be coming online in the near future and that looked good. This was at the height of our merchant power business, over 10,000 megawatts spread from New England through the Midwest. Prices were at high and they were growing. And our earnings from the unregulated businesses are -- we're going to continue to grow, and that's where all of our growth was going to come from. Our regulated businesses were not growing very much at all.

And as we looked at this, we said, "Is this really the right mix for heading forward?" One of the things was, it puts strains on our credit ratings, our liquidity needs were high. We hadn't been able to raise our dividend in, literally, a decade. So we look out [ph], and the next thing we were looking at is by 2010, even our Virginia Power generation would be considered unregulated. We had the deregulation in Virginia at this point and we had a price cap until 2010 and then we would've gone to market, and there had been a lot of political froth going on about deregulation, it was beginning to push back, it was beginning to come. In the mid part of that -- of the last decade, you may remember Constellation, that problem where gas' and electric's rates went up 70% in 1 day. Note -- nothing they've done, it was their price cap came out and we still had post-Katrina levels. So our stock was growing, I mean, our earnings were growing in the unregulated space and we weren't sure that's where we wanted to be.

This is how the market viewed our earnings. We had about a 12% discount on our P/E ratio to our peer group. So we looked at this, we decided we can either stick with the status quo, we can double down and try to get more unregulated earnings, buy another E&P business or more merchant power plants. Some people decided to go further into deregulation at this stage. Or we could go in -- exactly the opposite direction, which is to go far more regulated. And to do that, there's a couple ways to do that, you can either grow your regulated businesses or you can shrink your unregulated businesses or you can do both. We chose the latter, we chose to do both and to go in a far more regulated direction.

So as you fast forward -- picked 2010 here, because the last time we were here for an analyst day was in May of 2010. And sort of here's the progress report. So you can see where we were in 2006, that was going to head up closer to 70% deregulated by the time we would have gotten to 2008 or '09. And what happened is in 2007, we started the strategic moves. We sold all of our non-Appalachian E&P businesses. In 2007, early part of '08, our policymakers in Virginia got engaged in a debate over reregulation of Virginia Power. That law was enacted in 2007. Its fifth anniversary was this session and I'll talk about that -- of our legislature, and I'll talk about that in a minute.

The first big proceeding under that new law was the Virginia City Hybrid Energy Center. Would there really be rider treatment? Would it really be for cash earnings as you build the plant? Will it really get the premiums? Lots of questions around the first applications of the law. All of that went as expected as the law has gone as expected over the course of that time. We finished the Cove Point expansion. You can see our target, our earnings mix has gotten to 75-25-ish. By the time we got to 2009, Bear Garden was the next power plant in Virginia that was approved. So people -- and then at the -- as we entered '10, 2010, I think in April, we sold the Appalachian E&P assets. And that was the earnings mix in 2010 actual at the end of the year. And you can see that we had closed the gap with our peers on our P/E, a slight premium at 2010.

So as we entered into '11 and started looking at the landscape then. We saw what you all see, shale gas explosion. We're there in the heart of it. Utica was just beginning to come into people's discussions in 2010 and 2011. And we knew that, that was going to do 2 things. It was going to present us a lot of opportunities in our gas infrastructure business and it was going to continue to put pressure on our merchant business, particularly merchant coal business. So we undertook steps. We started working immediately on the midstream and on Cove Point, and we started taking a hard look at the rest of our merchant fleet.

So to bring us up to date, you see 2011 actuals, they're 75,76, 24. Salem Harbor and State Line were closed and sold. Kewaunee, we tried very hard to come up with a solution for Kewaunee for the employees there, for that region of Wisconsin. These are great jobs and that region of Wisconsin needs great jobs, and it's a great plant. We couldn't figure out a way to make the economics of it work. We couldn't sell it, we couldn't do a power purchase agreement. Led us to the unfortunate conclusion that it had to be decommissioned, and it will be starting in May.

We announced, in the fall, the sale of Brayton Point, Kincaid and Elwood, exiting the merchant coal business entirely, and the Midwest merchant fleet leaving us Millstone, Kincaid -- excuse me, Millstone, Manchester Street and Fairless Works, and we announced this targeted mix of 80% to 90% and a 65% to 70% dividend payout ratio.

So where does that bring us now is we're at a premium to the rest of our sister companies in our peer group. And where are we going from here? And that's what we're going to talk about today. But we view our job as twofold. We need to continue to enhance that premium we have to our peers and we need to deliver the E in the P/E. We need to deliver the earnings growth in the P/E, and we need to increase that premium to our peers.

I've read -- some of you have written that as growth returns to the economy and some money begins to leave this sector when people are less concerned about safety of the utilities in -- which the utility sector provides, that there will be more differentiation in P/Es and those with the most transparent, visible, dependable earnings growth plan will prosper. We'll see if that develops.

So our growth plan review. This is what we're going to do for the next 5 years, 2013 through '17. We're going to build on our strategy of reducing our commodity risk. I think you should consider that part of our plan to be largely finished. We -- we're content with our merchant fleet, at this point, there are no more E&P assets to dispose of. And we have been building all along, and we're going to continue to build and that's where you're going to see our concentration of effort.

Now we showed these plans even a few weeks ago, you would have seen $2 billion on this slide for CapEx per year. We are raising that today to $3 billion, that's attributable to Cove Point, which I'll talk about in a little more detail in a minute.

We have growth in all of our business units. Our local gas distribution company, Dominion East Ohio, we have a $160 million a year PIR program. We have it in Dominion Transmission, we have it in midstream, we have it in Virginia Power in its electric transmission business, distribution business and its generation business. And even in merchant power, there is a little growth this year compared to the significant declines we've seen over the years in that business. And as you all know, I think we're well situated in the Marcellus and Utica shale.

Now just a little more granularity about what we did over the last 5 years, because it's a precursor to what you're going to see us do over the next 5. Okay. Utility generation, over the 5 years, we added Ladysmith, we did uprates, Bear Garden came online and VCHEC, just this summer, became -- went commercial. It's -- we're supposed to put -- our lawyers make us put one of the cleanest coal plants in the United States on here. I'm confident it is the cleanest coal plant in the United States, but there might be someone somewhere. We added 1,900 megawatts of capacity during that period of time, $4 billion in regulated CapEx growth capital attributed to our generation business.

Okay, we're stuck. Can we advance the slide back there? I can remember them.

Next one is about our electric transmission business. It's $3.6 billion worth of investment over this period, a lot of -- 4 big 500 kV projects have been completed. The lights did not go out in Virginia. Okay. It's about $3.6 billion, as I said well, things to remember is we have a 500 kV loop that we built in Virginia in the '60s, it all needs to be reconstructed. Here's the slide. You can see $3.6 billion of total investment.

And in our distribution business, you need to think about the fact that during the height of the recession, at 2007 through 2012, we had 200,000 new connects in Virginia. We had lower growth in Virginia, we're going to see more low growth this year and I'll talk about that in a little -- in a minute. Data centers grew by 425 megawatts themselves over that 5-year period and they'll be growing even more rapidly over the next 5 years. And a 15% reduction in average customer minutes out, a huge amount of capital spent to increase our reliability. Now 15% may not seem like a lot to you all, but you need to remember we have 2.5 million customers and there are 526,000 minutes in a year. So to shrink the minutes out by 15% over that period of time takes a tremendous amount of effort.

Dominion Energy, another $3.6 billion of investment. The first 5 are your Cove Point expansion, USA Storage, you know all these projects, the Dominion Hub projects, Rural Valley, Appalachian Gateway. Remember, those are all conventional gas infrastructure expansions. Ellisburg to Craigs, Northeast Expansion which came in at the very end of last year, those are all -- those are shale gas plays, infrastructure improvements. And Natrium, which will come online very shortly, is a $500 million -- $550 million fractionation and processing facility that we're building on the Ohio River. And our Pipeline Infrastructure Program, I mentioned to you. So all that spending brings us to a 75% increase in our net plant over that 5-year period, $11 billion, successfully done on time and on budget all across these business units.

Now what you should be thinking about for the future is that over the next 5 years, we're going to more than double this. We're going to drive this to 160% growth over the 10-year period, and now we'll take you through how we're going to do that.

For us, the path is prologue to the future. What we have been doing is what we're going to continue to do. We've done it successfully, and we see a very straight path to completing it, that same plan. All right. This is a slide we started showing about 2008, a bar chart that looked just like this, only it didn't start with 2013, it started with 2008 and it went out 5 years. And it showed you the build of growth capital we were going to be spending in our regulated business units, yellow being for Dominion Energy, blue for Virginia Power, the non-generation piece, and then green, the generation piece, all 100% being spent in regulated businesses, and as we go into each fall session -- season for -- in analyst meetings, we would update it. So all right, now we'll start with 2009 and take it through 2013, et cetera.

You have to earn your way under this chart inside our company. You have to -- we have to believe -- we have to be highly confident that the project is going to show up in the 5-year period, or we don't put it in here. We may tell you about it, like for example we did with Cove Point in the fall. You see Cove Point's listed on the top here, additional CapEx of $2.5 billion to $3.5 billion. And if that went ahead, we'd have $13.5 billion to $14.5 billion over the 5-year period instead of $11 billion. And we still -- we don't -- we're not far enough along with Cove Point to put it into this chart and the range there is because we haven't finished our FEED studies and we're not exactly sure in negotiating with our partners, TSA partners, terminal service agreements, the shippers. If they're going to want ownership. So we're in that range, we'll have to see how the project develops.

So today, we are at the point where we are highly confident Cove Point is going forward. We are in the final stages of the TSA agreements and dealing with our EPC contractors. We have our FEED study, it's complete. We have our final bids in and we're in negotiations with the EPC bidders. All of these important contracts, I'll talk about them again in a minute, will be completed, we believe completed very soon, soon enough that we're now confident enough to put this in our plan.

Other thing to notice here is 2 other elements. There's some -- and we've told you this before when we announced Blue Racer. Because of Blue Racer, the midstream growth program we have in that joint venture, we can remove $450 million of capital from the plan and get at least that amount of earnings that we were looking for, or more, we expect more out of the joint venture than we would've gotten by making those investments ourselves. And we now have real clarity on the final cost and ownership structures that we're going to have at Cove Point. $3.4 billion to $3.8 billion, bringing our total spend over the period on regulated businesses growth CapEx of $14.1 billion to $14.5 billion.

All right. Now I'm going to talk about each one of these in turn. Utility growth. This is the generation component. You see the green from the earlier slide, $4 billion over this period. This is our capacity growth projections that we have. Now we're -- the most recent PJM demand forecast showed 1.8% growth in the Dominion zone over the next 10-year period. This is updated every year by PJM. We have been, for years, the fastest-growing. They're expanding the PJM zone. There will be 21 starting this fall. We are the fastest major utility, fastest-growing major zone in that whole PJM area. Penelec, in Pennsylvania, has slightly faster growth than we do, expected growth to PJM obviously our independent RTO provider. Our own internal projections on our IRP that we filed with the State Corporation Commission shows slightly higher than this, 1.9% growth. It shows you where we're starting when our existing resources goes back to 2007, the projects I showed you a few minutes ago, Ladysmith, the uprates, Bear Garden, VCHEC are finished. Warren County is under construction and will come online next year about 1,300 megawatts. Brunswick County, we have filed for approval. The hearing on that is next month, and we're hoping to have an approval sometime during the summer. And the one that will follow that will be the -- what we're calling in this program a generic CC, which will be the same vintage -- we expect it to be the same vintage as Warren County and Brunswick, 3 on 1, 1,300 megawatt combined cycle plant.

Okay. Frozen again. Can you advance the slide, please? Thank you. Okay. Well, the next one is our electric transmission business. We'll get it in just a second. Here we go. These are the projects that fall into that plan. VCHEC, I mentioned the uprates. And biomass conversions, they're under construction, they'll be done later this year. Bremo conversion has been fully presented to the commissioners. We're waiting an order, seemed very noncontroversial. Warren County, as I mentioned, is under construction and Brunswick, $4 billion.

Okay. Virginia Power, up to $4.5 billion in transmission growth. These are the projects that you've seen there, Mt. Storm to Doubs is one we have been working on for a number of years. This one, we are doing an existing right-of-way by growing the towers and increasing the capacity. This Cloverhill to Liberty, Dooms to Bremo, these are all part of this -- the loop that we're trying to complete that I showed you a few minutes earlier.

Fentress to Yadkin, Skiffes Creek is necessary to help with -- because of the closing of Chesapeake and the other facilities on the peninsula in Virginia we need to get more power down there. They were closed because of the EPA regulations. Lexington-Dooms is part of the 500 kV loop. The only other thing I would add here that you haven't really seen before is the focus on cyber security requirements that are coming. Obviously, all utilities are going to have those, and this is going to support $400 billion, $500 billion, even some years, $600 billion in growth capital in our FERC formula rates that are passed through automatically by our Virginia law.

Distribution. 2013 to '17, we expect this year to have -- and over the course of this plan, on average about 2% load growth. This year, about half of that will come from data center growth, which you see here on the right-hand side of the screen. We started with that 455 megawatts I mentioned to you that grew from '07 to '12, and that'll grow out into the future, and I'll comment on that in just a minute.

Average annual new connects over this period of time, we expect to be between 35,000 and 40,000. Virginia's unemployment is quite low, and I know may be questions about what the sequester is going to do. I don't think anybody has a clue what the sequester is going to do, including all the people in Washington. But -- and I don't think anybody expected to last so long. But we're going to monitor that. We see no reason at all to change our forecast here. Virginia's overall economy is quite strong and you'll see it strong in all parts of our service territory, not just in the Washington, D.C. area. But we do not expect any change in our load forecast because of that.

Virginia is ranked #2 -- 1 or 2 every year as the best place to do business. Those rankings will come out here shortly. Last year, the thing that dinged us to #2 is our -- we didn't have an adequate transportation plan and our legislature passed a transportation plan a few weeks ago.

Let me just -- one comment on data centers. How come data centers come here to Virginia, and I'll show you that in a minute, but how do you know -- where are these projections coming from? These are long lead items. We need to build infrastructure for these data centers. They use a lot of power and it needs to be highly reliable, which is why they come to Virginia, to our service territory, it's highly reliable. And their biggest variable cost is their electric rates. We have low rates, and they come to Virginia because of that combination and because there's a lot of other fiber there and a lot of technology employees there. That combination of factors draws them to Virginia. They sign contracts with us, minimum take contracts, but we don't build the infrastructure.

So just to give you an example, the 2014 projections here, 85% of that is already under contract, 75% of 2015 is under contract, 75% of 2016 is under contract and just under 70% of 2017 is under contract. So we have a very -- we have a long history with this and these companies. These are very good and reliable indicators to us that they will be there in the future.

One of the other things I wanted -- we wanted to point out to you is it's not all concentrated in one place. A lot of it is in northern Virginia, half of the Internet traffic in the United States goes through the Virginia Power service territory, half. Now one of the reasons, as mentioned, we have the highest concentration of technology workers per capita in the nation in our state, a lot of fiber optic cable. But you can see the data centers are spread through the state. Actually, this one down here in the central part of the south -- central part of Virginia is the largest Microsoft data center in the United States. You see them in the far eastern part and then there's more around Richmond. The yellow dots are economic development activities that we do in conjunction with local governments and I won't get into the details because we don't want all our friends in other states to learn exactly what we're doing. But we do a lot to make it attractive for data centers to come to Virginia.

Dominion Energy's growth. This is the first bottom yellow mustard color. That $2.2 billion, if you'd seen it a couple years ago -- a couple months ago, it was $2.6 billion before we announced Blue Racer. We've removed the $450 million from the plan, it was necessary for us to get the earnings growth that we were anticipating out of Dominion Energy. Of this $2.2 billion, about $1 billion of that is at Dominion East Ohio and 80% of the Dominion East Ohio bill is the PIR program, the bare steel pipe replacement program, which is a rider program with formula rates automatically passed through as you true up at the end of the year. The other, about a little over $1 billion, much of that is identified. Some of it is in development that will either take place at Dominion Transmission, at Dominion East Ohio, we may send it to Blue Racer or we may send it to another joint venture or other partnership or some combination of those. The Blue Racer joint venture is a tremendous opportunity for us. We have not spoken about it with you at length. It was closed at the end of last year, and we deferred speaking about it at our earnings call until today. It's a tremendous, strategic development for us that insures transparent midstream growth for the -- for at least the first 3 years and well beyond, we believe.

This is why we are able to do what we're able to do in the midstream. Our pipeline goes right up the spine of the Utica and Marcellus shale regions. Those orange -- those red ovals are the gas storage business we have. You see Natrium, which is the bigger blue cylinder, I guess that is, which is on the Ohio River on the West Virginia side. Hastings is a processing plant that's been there for a very time. We enlarged it about 5, 6 years ago. And then Cove Point, which I'll talk about in just a minute.

These are Dominion Energy's projects. You've seen most of these, not all of these. The ethane project, were not -- it's not a cracker, it's moving ethane from -- to a different pipe, for delivery elsewhere. Tioga Area Expansion is a project we're working on, it won't come online until '14, the same as Allegheny Storage. And then Rural Valley II, we've mentioned before, the pipeline infrastructure replacement program I've said a few minutes ago, that's Dominion East Ohio. The Blue Racer Midstream joint venture and now we're adding Cove Point to these slides. Cove Point has not been on this slide before. And you can see that the growth now being spent at Dominion Energy, the CapEx is $5.6 billion to $6 billion, in CapEx growth there.

So this is the growth plan summary. We believe we have a track record of successful execution of this plan. We have done this plan the last 5 years. Most of the elements or almost all of the elements are identified to continue this plan for the next 5 years. We'll increase the capital spending to $3 billion a year, because of the -- because we're bringing in Cove Point. The real spend will start later this year and next. We'll be well positioned in Marcellus and Utica. We have constructive regulatory environments across our landscape and, like I said, Cove Point. So what does all that bring you? That brings you 160% increase in our net plant over a 10-year period, more than doubling what we were able to accomplish over the last 5 years.

Okay. Key developments. Blue Racer, Cove Point and regulatory. Now one of the themes we heard through 2012 and it was -- they were very well-justified questions. What is your midstream growth? You announced Natrium and a couple other projects, where is your midstream gas infrastructure growth? We haven't seen an announcement. And that was true. And one of the reasons was we were working on Blue Racer, which is where we wanted to send a lot of this project -- these projects, and we'll talk about that in a minute.

What's going on with Cove Point? When are you going to -- what's the schedule? How much is it going to cost? What are your earnings going to be out of that? Mark will talk about the earnings, both Blue Racer and Cove Point, in a few minutes. And what about your biannual review that's coming up next year? You were found to overearn in 2009 and 2010. All very good questions, and we'll now provide you the answers to those questions.

Okay. Blue Racer Midstream. It's a joint venture with Caiman Energy out of Dallas. And here's what we are looking at last summer. The Natrium project was under construction. That project had captured 15% of all the contracted acreage in the Utica Shale by itself. So it was a very big start, a very early gain by us. And -- but there's 2.5 million acres of wet gas in the Utica Shale. About 1.5 million of it was uncontracted for at the time. You can see where the concentration of permitting is in wells.

Natrium, as I said, had captured 15% of what was contracted but there was still a lot out there to do. And Ohio passed a law that made it very supportive of companies like ours taking underutilized assets that were part of our LDC, Dominion East Ohio and taking them out of regulation without having to go through a complicated regulatory process. It's notice-driven, we give the notice and the pipe or structure, gathering system, whatever is removed from the rates and is then able to be contributed to a program like this. Particularly valuable for us at Dominion East Ohio, because if you think back, the history of Eastern Ohio, Cleveland, Toledo, Akron area, heavy industrial. Steel, tires, automobile, shipbuilding, Cleveland. And Dominion East Ohio had built up a big infrastructure system over many years to support that. And over the years, those businesses have reduced their scope and those pipes have become underutilized and some of the pipes not used at all, depreciated down to near 0, but still sitting in our rate base, not earning on them. So we were looking at a way to take those assets and increase our earnings flow from them.

Now one of the things you need to really notice about what's going on in the Utica Shale is the top chart there above all the little dots. That's the permitted drilled and producing wells in the Utica Shale region. And if you look, you'll see that each one of those categories tripled between February of '12 and February of '13, tripled. That is a huge amount of activity. Some wells are waiting, sitting to produce. They're drilled and ready to produce, they can't be processed. There's not enough processing in this region and that's the race that's on, is to provide that processing.

One of the reasons we were able to do Natrium early, we announced Natrium in the summer of 2011. It's almost finished, takes a long time to build big ones. It doesn't take very long to import smaller ones. It's -- we knew -- we've been in the Appalachian region for 75 years with pipelines, producing gas, et cetera. All the players there knew us well. Shale gas, they didn't know much about how to do shale gas, those drillers. A lot of new players came to a region that we had no relationship with, folks that had been in the Barnett Shale and all these -- and all the other shales around the country. They came with their own set of relationships, their own experience with people in the processing business. Caiman is one of those.

Caiman was in the region, some others came to the region, a lot of new producers that we didn't have much of a relationship with. So they were -- we were not getting -- we didn't think we were going to get our share of this business, so we decided it made more sense to combine, create a joint venture that operates in many ways -- but it's not an MLP, but it operates in many ways like an MLP. The way the earnings flow to us operates like an MLP. We don't get the advantaged tax structure, for example, we don't have the distribution requirements, but it has many elements of an MLP.

So what that joint venture has allowed us to do is take those assets, what we had -- we had gathering assets, some processing. Caiman has expertise, a lot of processing, a lot of relationships and they had a lot of cash. We're contributing assets over a set schedule, year by year, and I'll show you part of that in a minute, and Mark will take you out into the future. From there, we get earnings as we contribute these assets, and then we get -- and then we, of course, we own 50% of the joint venture, which will be -- we'll get the earnings from those. That's why we're able to relieve our CapEx plan of $450 million and what we believe has increased the earnings flow that wouldn't have otherwise come. It very -- it supports the 5% to 6% earnings growth. Question, where is your midstream growth coming from? It's going to come from Blue Racer and as we look at other possibilities in other regions.

As I said, it's a 50-50 joint venture. Caiman funds all the CapEx in this enterprise until there's equalization, our assets and their cash meet 50-50.

It's also important to remember that it is only in a defined area. It is literally a list of counties in Ohio and Pennsylvania. That's the blue area you see here is literally a list of counties. Outside, where we have assets, we're free to do whatever we want to do, there's no restrictions. But inside there, we're going to focus on gathering, processing, fractionation and moving the natural gas liquids. The joint venture is free to pursue outside, as are we. So it's just this limited area. You can see that's the state of Ohio up there in the top left. So it's the eastern part of Ohio and the far northwestern part of Pennsylvania.

Okay. Contributions that are already defined in our agreements. The East Ohio system, gathering system, wet gas gathering system, these dark blue lines you see here, that's what we contributed at the end of 2012. This year we'll contribute the TL-404 wet gas system, that's the yellowish, orange-ish small pipe south there. And the Natrium facility, which we'll also contribute along with a natural gas pipeline that's coming off the Natrium facility. Those -- all those assets will be contributed at different points during the course of 2013. And then we have others that are identified. You see the -- all these red lines. These will be contributed, it's not maybe we'll contribute them. We don't know what the value it is. They will be contributed and we'll know the value as we go forward with the joint venture, and that's what supports the earnings growth that Mark will show you in a few minutes. And we have flexibility as to exactly when they're contributed.

One of the other things to remember about Blue Racer is that it is about 10% of our gathering assets were contributed to the joint venture partnership, that territory. That leaves, of course, 90%. Now is all 90% of our gathering system good for shale gas gathering? No, not by any stretch. There's -- a lot of it is just suitable to conventional gas, it doesn't have the pressure capability. But my point -- our point here is there's a lot of other assets available to us. We have a lot of right-of-way outside of Eastern Ohio. We have all of West Virginia, we have great pieces of Pennsylvania, and we're one of the few players in Western New York state. You all can tell me, I guess, as well I can when Governor Cuomo is going to allow frac-ing in Western New York. It may never happen, but if it does, and it doesn't. But if it does happen, we're well situated to play an important role in that region.

So Blue Racer has opened a new world of possibilities for us, of what to do with our midstream business and our whole Dominion Energy business. It supports our 5% to 6% annual earnings per share growth, as I've said. It gives clarity in the midterm on our earnings stream, where it's going to come from in our midstream business.

Cove Point. The question was what's going to happen with Cove Point? What's your schedule? And can you really build this thing? What about the Sierra Club? Et cetera. All very legitimate questions. So this is the Cove Point story. This is looking at it from the west, the entranceway where you drive in, is off to your right, where you see the red-roof building there. And you can see the pier, which is out about a mile into the Chesapeake Bay. Some of you, I know, have been there. You get out to that terminal by riding a bike in a tunnel. So actually you don't go on top, you go down, okay? Is anybody alive out there?

Okay. So Cove Point is about -- we finished that expansion of that pier in 2011. It's already big enough for supertankers. You all know the Panama Canal is being expanded in 2014. This is a very valuable asset. As you know, we have import contracts and we've been pursuing terminal service agreements they call them, TSAs, for exports that will basically mirror the import contracts, take or pay, long-term contracts.

And this is the proposal, about 750,000 a day on the input side and 4.5 million to 5 million tons on the output side.

This is the footprint where the liquefaction facility will be built. Now you're looking at obviously straight down. The western side is off to your left that you -- when you had that earlier bird's-eye view. That's the area where the liquefier will be built. We have -- our final EPC bids are in. As I've mentioned to you earlier, we're in the final negotiations over those. But we're prepared to move forward with that. We now know -- we have a good feel for the range of costs.

This map shows you why people are interested in Cove Point, we think. It's interconnected to every major pipeline in the Mid-Atlantic and in the East, for that matter. It goes to all the markets, and that's why people wanted to pre-import, and now we can backflow the -- what is called the Cove Point pipeline that runs from Leidy down to this belt. To run up to Leidy it's now going to be reversed. And the pipe -- and the gas will come down from the Marcellus and Utica Shale region, there's lots of ways to get gas to Cove Point. That's the reason why the shippers are very interested in it. And the other thing to remember about Cove Point, this map is -- there's no other terminal on the East Coast that's going to get built, that's going to -- that can compete economically with Cove Point because of where it's located.

Here's the timeline. These are the various things that we have to get done to get Cove Point built. First thing is we needed an export permit to free trade agreement countries. We got that obviously last year in '11. Two, you need a FERC environmental permit. We do this all the time. We do it with our pipelines, there's a process, what they call the prefiling process, where you give notice to FERC that you will be filing for an environmental permit for the facility. You do that well in advance of when you actually file the permit itself -- the application itself so that you can have an opportunity to have dialogue with staff and all the other people involved and who will be involved in the proceeding, to find out where the issues are, so that you can solve them in advance of making your filing, and it makes the filing go much more quickly. We've been doing that for years with our pipeline projects. We've done that with Cove Point. We filed that last June. That's one of the reasons why we're near the top of the DOE queue. And that's almost finished, and we will be filing, as you can see a little bit further down, next quarter for the FERC permit, which we expect to get in 2014.

When people seek free-trade -- non-free trade agreement permits to export natural gas, the Department of Energy has to do an economic impact study on its -- what the potential impacts are on the economy of the United States. A lot of issues around that were discussed last fall. People are wondering what's going to happen with that. But you all know that the DOE came out with its report in December and it was extremely positive. I shouldn't say DOE, it's consultants. Extremely positive on exporting natural gas, and consistent, by the way, with almost another half dozen reports that have done the same studies.

The comment period, there's a comment period ahead to follow this, it's now closed, closed last week. And that means the regulatory process, as far as the DOE is concerned, is now complete and they are now free to start issuing permits. We expect to receive one of those permits a little bit later this year. We had -- there's a particular issue with us and the Sierra Club at this site. It's unfortunate. We've always worked with the Sierra Club very well in many aspects of our businesses, but in particular Cove Point, over the years. We had a disagreement over an interpretation of the agreements there. We filed a declaratory judgment suit, the judge agreed with us, Sierra Club has appealed it. But you're all free to read the statute. I think it's 8 or 9 pages and pretty straightforward, that we can export gas from the site, says it actually in the agreement, like says it.

EPC contract, as I mentioned, we had the final bids in. We're near -- we're just about to conclude the negotiations there. And then I've mentioned the FERC filing. The terminal services agreements, as I mentioned, are in their very final stages, and we expect to be able to announce them very soon. So that is what's given us confidence to put them into our 5-year plan, highly confident that we're going forward.

Now a few minutes on our regulatory situation. I mentioned to you that the re-reg law was passed in 2007. In that law, in 2007, they called for a study on the fifth anniversary of the law. It's typically done in many different instances in Virginia where a regulation is involved. So that, of course, was -- the fifth anniversary was the 2012 session. It was the end of 2012 going into the 2013 session. 2012 study was done by State Corporation Commission staff and a very lengthy study was done by the Office of Consumer Counsel, which is located in Virginia inside the Attorney General's office. And that study called for an elimination of the RPS adder, that you get if you hit the voluntary requirements. Attorney General's position, he's quite capable of speaking for himself as many of you may have seen him on television, the -- and I wouldn't seek to try to speak for him, but it's -- the study says -- Dominion is not doing anything wrong here, but the way the legislation was set up, it's too easy to get to these targets and earn this enhanced return. So first, what was not changed? Remember, there's a big transformation in 2007 in Virginia regulatory law. There've been many proceedings since then, carrying out different elements of that law. All of the elements have now been carried out in various ways.

So what was not changed is probably more important than what was changed. All -- still, all forward-looking rate making. We still have the mandatory ROE peer floor is still there in the law. Timely and current cash return on all our -- of our approved rider projects, all still in the law. Incentive ROEs were changed. The law allowed you 100 basis point adder for clean coal. There's not going to be anymore coal built in the United State anyways under the EPA's regulated -- it becomes final. And then we had also got a 100 basis-point premium adder on combined cycle plants. That has been eliminated going forward. That does not apply to any existing facilities that are -- have the riders nor one that's already filed, in this case, Brunswick County. We'll still enjoy the 100 basis-point premium.

The nuclear and offshore wind was reduced from 200-basis-point adder to 100-basis-point adder. Earning-sharing mechanism was maintained and slightly modified. It was 60-40, if you overearn, you give refunds, 60% went to our customers, 40% retained by the company. It's now 70% goes to customers, 30% retained by the company. And then there, we have this feature where it's an automatic pass-through of the FERC transmission rate.

So what was changed? The earnings collar was changed. There was -- the old law, had an earnings collar. Whatever your target ROE was, you can earn up to 50 basis points above that and if not found to have been over-earned, you could earn 50 basis points below that and not -- you couldn't seek a rate increase, classic collar. The collar was modified, it's not a collar anymore. If you earn below the established ROE, you can seek a rate increase. There's no -- you don't have the 50 basis point down to the collar. And it went from 50 up to 70 up. So the collar is not really a collar anymore. You can earn up to 70 basis points above your allowed return without being found to have over-earned.

I mentioned the elimination of the ROEs except for the nuclear and the existing projects. And the 50 basis-point incentive for hitting our voluntary RPS targets was eliminated. Now very importantly, I think, for you all to take into account is the next question that we had in 2012. We had questions about midstream growth, Blue Racer and what Blue Racer gives us, is our answer to that. Cove Point is on target and moving ahead very rapidly actually.

And then what about your biannual review? The law offer has some accounting language in it and provides clarity to what we believe would have been the rulings by the State Corporation Commission on a variety of topics, but it did change the law and now mandates how certain accounting is going to be treated in biannual reviews and for rate-making purposes. In particular, the language says if you wrote all -- if you had an accounting -- had to account for a plant closure prior to December 2012, that will be included in the biannual review for 2011, 2012 earnings. In our case, that's the closing of the Yorktown and Chesapeake power stations, must be accounted for in the 2011-'12 biannual review, can't be amortized, for example.

And any catastrophic damage that happens from windstorms, hurricanes, tornadoes, earthquakes, et cetera, has to be accounted for in the period. So what does that means for the biannual review? Top of the range for us is 11.4% -- is the -- what the earnings that will be applied to for what we earned in 2011, '12. We'll be filing the case, by the way, at the end of this month, as required to do, and a ruling must come out of the commission by December 1. The ROE -- earned ROE we will file will be right at 10, right around 10 for that period, if you average the 2 years. It includes the filing impact that can't be amortized. Mild weather -- there's no -- it never has been in Virginia, of any kind, any accounting for weather, up or down. Voluntary separation plan is something we did in 2009 or I guess, 2010. 2010, in the '09-'10 biannual review that the commission split that and carried part of it into this biannual review, so that must be accounted for. Now because of the statute that passed a few weeks ago, and by the way it's already a law in Virginia, normally, laws don't -- in Virginia don't become enacted effective until July 1. There's a couple of exceptions. This law fit that exception and it became law when the governor signed the bill a few weeks ago. So this is the existing law in Virginia today. There's no veto session that's sitting out there for all the other bills that have been adopted. And normally you have to wait until July 1. It is the Virginia law today.

Hurricane Irene, which happened in 2011, the earthquake that also happened in 2011, the derecho and Hurricane Sandy effects all must be accounted for in 2011, '12, that can't be amortized across future periods. Now what does that mean? If you remember, the -- our law says that if you overearn in 2 consecutive biannual reviews, 2 consecutive biannual reviews, then your rates can be reviewed up or down. We did overearn in 2009 and '10, can't overearn in 2011 and '12, can't see a way to have that happen. I guess there's lots of creative imaginations out there, but this is pretty clear and straightforward. What that means is if we do not or have not found to have overearned in 2011 and '12, our rates cannot be reduced effectively until December of 2017 because of the way the law works. Okay. That's the third question. What about the biannual review?

Okay. Key investment advantages, we think we offer. 2013 to '17, we have a $3 billion plan. 80% to 90% of our operating earnings come from our regulated businesses. We believe we have a constructive regulatory environment. 5% to 6% earnings growth, and over the next few years at least, you will have a little bit higher dividend growth to go along with that earnings growth.

And with that, I'll turn it over to Mark for the financial overview.

Mark F. McGettrick

Okay. Mic work, let's hope this works, let's see what happens. First, I wanted to thank everybody for coming today. It's a great crowd here. We know we have a lot of folks on the phone, a lot of people have busy lives and different things to do and we appreciate your time -- coming and listening to the Dominion update today. Hopefully, you'll find it informative.

Tom has outlined for you the strategy, both the historical strategy and the future strategy for the company, in fair amount of detail. I'd like to go through our -- some of the key items on the financial side to give you a grounding for that. I'll spend a lot of time on Blue Racer and Cove Point again, because I think those are new frac sets that most people want a little bit better understanding for, but also I have some basic information I think that would be important to understand how we're going to reach our earnings targets as we move forward.

First, let's talk again, what we talked about on the call, and that's how do we get from 2012's actual earnings to 2013's range of $3.20 to $3.50 a share. We're hoping never to talk about weather again, except that it's normal, hot or very cold because after last year's $0.22 impact on us, that was quite extraordinary year. If you weather-normalize 2012, we would've earned $3.27, which would have been 7% growth off a normalized 2011. But let's assume we're going to have normal weather going forward. We have some significant growth engines in 2013 over 2012, the biggest of which is our gas transmission business. From the projects they bring online -- they brought online, I should say, in 2012, those projects alone will increase our earnings by $0.03 a share per quarter, as it annualize over 2013. In addition, we'll have Natrium brought online, we'll have Blue Racer earnings as well, so you have a very strong gas transmission growth of at least $0.17 year-over-year.

As we complete the sale of our merchant fleet, we've talked before that we had a drag of $0.10 to $0.15 based on these legacy coal assets, that drag will be eliminated as we move into '13 when we finalize that auction process, which we'll talk more about here in a few minutes. We have very strong rider growth, which you will see. We've almost had strong rider growth in Virginia, both on the electric transmission side and generation side. We also have strong rider growth in East Ohio. And we'll talk in more detail on that as we go forward.

Electric sales, I'll touch on that again. Tom has already talked about that. And the usual service territory, we feel good about where we are and I'll talk about a few of the items we see in the first 2 months anyway. And then we have some headwinds that you would expect when you're spending $4 billion a year, you're going to have higher interest expense, you're going to have higher depreciation. Our O&M expenses are under very tight controls, we'll talk about that, and have been since 2010, although you'll see some modest growth in the O&M over the next several years.

And finally, on tax rate, year-over-year, we have been a beneficiary, the last 2 years, of favorable tax positions as we resolved legacy audits with the IRS. We are almost through with that process, so we would expect that our tax rate would go back to a more normal 35% to 36% in 2013 going forward, and will be a little bit of a headwind versus 2012. But we feel very good about where we are. We feel very good about the range that we've put out there, and we need to execute this year to meet that range.

Want to ground you just for a second and how these earnings will flow quarter by quarter, because there's a lot of significant events that occur -- will occur in '13, more timing events than anything else, and we had some onetime event in 2012 that will distort, potentially, quarter-over-quarter earnings, but on annualized basis it will all come together. So for the first quarter, you should expect our actual earnings in the first quarter, where we have a range of $0.80 to $0.95, on the weather normalized basis, last year, we've earned $0.96.

So for quarter-over-quarter, we'll be slightly below where we were last year for a couple of reasons. One is we are $0.05 mark-to-market gain in our retail business in the first quarter of last year, which we will not have this year. We also had some earnings from our merchant generation business for the only quarter that we had in the earnings in that business, I should say, in a Fossil merchant generation business of about $0.03, and we had a favorable tax item in the first quarter of about $0.02. So those onetime items we'll have to overcome this year, but the first quarter will be down on an actual basis versus weather-normalized first quarter of last year.

Every other quarter, we will show good growth, AOB adjusted by nuclear outages. If you look at the second quarter here, it shows growth in the second quarter of '13 over second quarter of '12, but that's mashed somewhat because we have a Millstone refueling outage in '13 but we didn't have any refueling outage in '12. So we actually have very strong growth in the quarter absent that outage. In the third and fourth quarter, you'll see very strong growth from all of our lines of business. And if you recall last year, we had an extended outage at our Millstone unit due to water temperature in the third quarter. We will not have that this year. And in the fourth quarter this year, we will have not had the Millstone outage that we had last year, and we will not have the refueling outage, we also had an unplanned outage at Millstone. So in the fourth quarter alone, because of the Millstone data point, we will pick up $0.10 a share year-over-year. So if you add this up, it gives us comfort that by quarter, it'll be a little bit different quarter-over-quarter, but in aggregate, we feel good about the range we have out there.

Moving to the 5-year outlook, and, again, I'll touch on some of these as we go forward. But we wanted to give you the whole flowchart. And as you look at it, it gives you all thoughts on a 5-year 5% to 6% growth target. Again, it's not at the end of the period on average, it's every year we expect to grow 5% to 6%. Some of the drags on earnings will be DD&A. Again, that will cost us about $0.04 to $0.05 a year as our CapEx program continues to be in high gear. O&M will be a very modest drag announced, we expect to grow 1% to 2% over the -- annually over the period, a very modest growth for a company that has a $3 billion operating budget.

And then interest and taxes, I touched on before, again, with a very large CapEx program, we're going to have additional debt financing out there, and interest expense is all that we hedge aggressively, as we go out, we would expect in out years a plainly rising interest rate environment.

In terms of growth, it will be the first year in 3 years, beginning in 2013, that we actually have merchant growth year-over-year. We expect to have that in every year in the plan as we go out. We'll talk about our position, our hedge position, on that in a moment. We'll have good sales growth in Virginia. We expect 2% sales growth annually through the period. We have a good historical basis for that. We have very strong data center growth, as Tom's outlined, and we feel good about economic growth in general in Virginia over the 5 years. We'll talk about the riders at Virginia Power. They're very clear generation riders, transmission riders. We've talked about them for a number of years. Tom's outlined them again. All regulated growth will grow between 7% and 8% annually in the period.

And then finally, on gas transmission, we'll talk about the various pieces of the growth in transmission, whether it be Blue Racer, whether it be Natrium, whether it be other pipeline investments as we go forward to give you clarity on how that business is going to support our growth rate as we move forward.

These areas we're going to touch on: sales growth, Rider projects, Blue Racer, pension, bonus depreciation, O&M, and then we'll talk about Cove Point following that. My focus on Blue Racer is financial, not strategic like Tom's. I want to make sure you understand how we're going to grow this business from a financial standpoint to give you clarity that we have thought this out long-term. It's a terrific opportunity for us, not only from a capital reduction standpoint but in terms of a strategic long-term growth plan in the Utica Shale, which we need to take advantage of now.

But let's talk about sales. 2% sales growth on average over the period. A lot of people talk about sales. Some companies do not have sales growth or have very modest sales growth. To remind everybody in the end, we have virtually no industrial load in our state. About 8% of our total sales come from industrial, so industrial has never been a mover for us up or down. We have a very unusual customer base and data centers. Data centers in 2013 will approach 1% based on signed contracts we already have of the sales growth that we currently project. And as Tom outlined, it will be a continual growth engine for us as we go out in the 5-year outlook, although not probably 1% but a smaller percentage as we go out, but definitely, it's clarity and growth that most people don't have.

If you look at the last 2 years, we've grown on a weather-normalized basis, 1.5% or 1.6%. If you look at a historical basis prior to the recession, we have consistent sales growth of 2% to 2.5% Virginia for a decade. So going back to a 2% growth, of which half is driven by data centers, we think is very reasonable. We have also taken a conservative approach on governmental sales as we went into the year, not knowing what was going to happen with the sequester or budget cuts, in general. And we have assumed our governmental sales will actually be down year-over-year. So we'll see what happens on the residential side, but, again, I think our view right now is it's far too premature to really determine what a sequester might do, what it might actually turn out to be. And we feel comfortable with both January and February results that our economic growth supports a 2% sales outlook based on actual results for those 2 months.

We referenced the new connects on this slide. We hit bottom a couple of years ago. We have very strong uplift in 2012. We expect that to continue in 2013. We'll connect 35,000 to 40,000 new connects. Our growth engine is Northern Virginia, but we are seeing good growth in Richmond area and to the East.

And, again, our data centers, in general, we keep -- we hate to keep harping on this point, but it is something that differentiates us. So with a lack of industrial load and a strong data center load, we think a growth rate of 2% Virginia is something that's quite achievable.

These are our rider projects, and I'm showing them to you a little different way than we've shown them in the past. Typically, we showed you generation riders by themselves in Virginia, but there's really no reason to do that. They all have the same type of structure where we get good cash treatment from these riders. They're outside the rate base. They have special handling by the regulators. So on this slide, I'll start with electric transmission at the bottom. Remember, we have formula-based rates in Virginia. We get our rates approved by FERC at the first of the year and then go into customer rates in September of every year. We're going to spend $400 million to $500 million in Electric Transmission growth throughout this 5-year outlook.

East Ohio gas, we don't talk much about, but we have a PIR program, which commission has approved about $150 million a year to replace their steel pipe. It's handled separately. This gives us a return north of 10%. It is a growth engine for a regulated distribution company, which otherwise has fairly slow growth in Ohio.

And then the other projects here, all the generation projects. Some are down on this slide like Bear Garden and VCHEC. Others are under construction, Warren County, Brunswick in the approval process now and we have a generic CC post-2016. Again, as Tom mentioned, everything through Brunswick is not affected by legislation at all. We will get 100 basis-point premium. And in all new projects, we get forward-looking cash returns, so the drag on us versus a traditional regulated project is quite minimal. The impressive part of this slide again is we will grow 13% on average annually on an EBIT basis from these rider projects. And as I mentioned earlier, we expect our regulated businesses in general to grow 7-plus percent over the 5 years annually.

Blue Racer, I'm going to show this slide twice, so I'll make sure we get focused on it. We've talked before that in 2012, 2013 and 2014, the majority of these earnings from our joint venture will be asset contributions to the joint venture. That's what allows us to eliminate $450 million of capital to the period. We will also get JV earnings coming from Natrium, which will drop down, and other capacity improvements on our initial drop-down infrastructures and projects in the first 3 years that the JV pursues. And we'll talk in more detail about the JV plans in a moment to give you comfort that beyond '14, that there's a very strong growth plan to continue to grow this business and really make sure you understand what the opportunities are in the Utica Shale. But for '12, '13 and '14, we're going to get $44 million -- we did get $44 million in 2012 in terms of the center of contribution of drop-down assets. We will get $33 million in '13 and '14 for the same type of drop-downs that Tom outlined. And then we'll have JV earnings on top of that. So these 3 years are very visible. In a moment, I'll talk to you about how I think you should get comfortable as we've gotten comfortable with '15 and beyond for the opportunities in this area.

In terms of merchant power, I love this slide. We showed growing margins as we move through time here. If you go back to our last disclosure, these hedge positions were up significantly. In 2013, we've increased our hedge position from 82% to 89%; in 2014, from 59% to 73%; in 2015, from about 37% to 48%. The important part of that is we can hedge very quickly Millstone, and we saw a huge runoff in the month of February based on basis differential in the Northeast that really drove power prices in not only '13 but more importantly in '14 and '15. Power prices moved in 1 month 10% from the end of January to the end of February, and it moved about 7.5% in '15. So we took advantage of this. We hedged in these volumes to help support our long-term earnings growth for merchant. These -- we always average in hedges. We've talked about that for years. We're right on schedule to do that, but we are very optimistic on how we do it. And this is a good example. So you see growth over the years, growth of about 2% '12 to '13. There's a slight amount of growth in '14, with very nice growth in '15. So we feel good about the merchant business. We'd like the assets on the merchant side that we're keeping to give us upside optionality, and we're going to take advantage of the power curve to go ahead and lock in to support our 5% to 6% growth going forward.

I want to touch on 3 items that I haven't heard a lot of people talk about there but they're significant, not only for our industry but for anybody that is the beneficiary of bonus depreciation or that has a pension fund. So let's start with pension first. The pension discount rate, as most of you know, is established as a point in time on 12/31 of every year. Because of the historically low interest rates, we adjusted our pension discount rate from 5.5% to 4.4% this year. The impact of that was the increase in a liability that we have to recognize in 2013 and, actually, for the next 12 years because you smooth this pension liability plus or minus over that period of time. This $52 million is a pretax number but it's after capitalization. So that's a headwind that all companies that have pension plans are going to have some type of headwind on their pension. Now we anticipated this when we gave guidance in September. We didn't know exactly what it was going to be, but we knew it was going to be significantly lower than the 5.5% that we had in 2012. And we built plans around that to incorporate that into our guidance.

The key takeaway for us on the pension is we're one of the best funded pension plans in the country. The most recent evaluation was done last year on this. So the top 100 pension funds of Fortune 500 companies, we were ranked seventh in terms of best funding. We continue to have extraordinarily well funded plans. We have no cash contribution requirements for a number of years. So we really like our position. We think we had a historical low for discount rates, and it will normalize over time but no impact on our guidance range because of a pension change this year.

Bonus depreciation. This is a double-edged sword for us. We have been a huge beneficiary of bonus depreciation. If you recall, over the last 2 years, in the last program, we were the beneficiary up to $2 billion in cash benefit from bonus depreciation. But there is a downside of bonus depreciation for regulated companies because it reduces your rate base on major projects. And because we have significant rider projects in Virginia, our rate base was reduced, which we'll recover over time. But the rate base was reduced, and that's an earnings drag. So if you recall, last year, what we announced was we're committed to 5% to 6% earnings growth, but that $2 billion of bonus depreciation benefit, we needed to cover that. And we elected to buy back stock to ensure we could meet our 5% to 6% earnings growth going forward. This year, we're the beneficiary of $600 million between 2013 and 2014, a far smaller number, about $250 million in '13, about $350 million in '14. And we have developed plans to offset the drag on earnings and our rider projects through lower interest expense because of the cash benefit we have and lower O&M. So, again, in terms of bonus depreciation, there is no impact on our guidance range, but you should not expect, and I mentioned this on our last call, you should not expect any stock buyback to offset any of the downside of bonus depreciation.

And then finally, let's talk about O&M expense. If you go back to 2010 where we met with this group in our last analyst meeting, our O&M expenditures have dropped from 2010 to 2012 dramatically. And if you looked at that compounded annual rate from 2010 to the end of 2016, we will be flat. Expense control is a key component of our business. We've used it to offset significant headwinds in merchant margins and others over the last several years, as well as weather. We are going to continue to use O&M and have to be very prudent in terms of control. The 1% to 2% annual growth, we think, is quite modest. It will change a little bit year-to-year based on the number of nuclear outages that we have, but it's not going to change much. We are going to have tight controls over O&M, and we will use it to cover shortfalls in case they come up over time. Again, we have a very good track record of this. I encourage you to go back and see what we said in 2010, track our O&M spending and you will see very good discipline.

So let me update you on a few things. I want to talk about the asset sale that we have pending. I want to talk a little about Blue Racer, and I want to talk about Cove Point. And then we'll wrap it up and take some questions.

First, to remind everybody of our merchant business, Kewaunee at the top, Tom referenced the ISO in the Midwest and said that Kewaunee is not needed from a liability, so we have announced we will shut that facility down on the 7th of May this year. After the second quarter, you should see virtually all expenses from Kewaunee handled through the decommissioning trust fund. Our trust fund is fully funded, and we've anticipated going into safe store and ultimately a full decommissioning. But May 7 will be the day that unit comes offline.

We've elected to keep 3 units. We've referenced those in the past. We really like the optionality of Manchester, Millstone and Brayton -- excuse me, and Fairless, 2 very strong gas units and good locational value for us. Manchester is a very good hedge value for us, and Millstone has terrific upside opportunity for us. It is the only unit that we hedge at any depth at all.

So that left us our 3 remaining units that we announced in September that we're going to sell Brayton Point, Kincaid and Elwood. And let me give you a progress report. Again, we announced those in September, that as our continual repositioning, that we would sell those assets. We received preliminary bids in November. We narrowed our group down in December to a final bid group. And about 10 days ago, we received our final bids in. There were a number of them. We're evaluating those now. We're in final stages of discussion with a number of bidders. We fully expect to announce a final bidder in this auction in the very near future, and we expect these assets to be completely sold by the end of the second quarter. They will require Hart-Scott and FERC approval, but we see no issues with any of the buyers that we're in discussions with on that. And these assets will move off our books in June of this year.

In terms of proceeds, I'd like to give you a point, but again, we're negotiating with different parties so that's not possible today. But we are comfortable with the range. Our range of after-tax proceeds will be between $600 million and $700 million. We've announced previously that we're using these proceeds to eliminate market equity needs this year, to reduce debt, to support our capital plan. And [indiscernible] that we haven't talked about in the past, but just keep in mind, as we have gone through this de-risking with the company, our liquidity position has gotten better and better. These assets, as they roll off, Millstone is almost currently open now, so that requires liquidity the way we hedge. We hedge over 3 years. Kincaid is coming out of the contract. It will require credit support if we kept that unit over time. It's a big unit, it's 1,100 megawatts. Elwood, the contracts are starting to roll off. They require liquidity support. So in terms of liquidity needs, it will drop our needs significantly. But importantly to note, we have $3.5 billion of credit lines. We are not going to adjust that credit support level. What it gives us though is flexibility in our CP market that more flexibility than we had before. So as we look at these assets, we look at them from a number of fronts. We feel very comfortable with the process. The proceeds will go toward the areas we've talked about and look for announcement here, as I say, very soon with completion by the end of the second quarter.

Blue Racer, the slide I warned you we'd show you twice. So on this slide, I talked through before the '12, '13, and '14 earnings. They should be pretty clear to everybody, that those earnings are pretty much in the bank based on cash drop-downs. So the key question really is, how are we going to grow after those cash drop-downs '15, '16, '17? And I'm going to show you on the next slide how we plan to do that, but one caveat I will tell you is that there may well be additional drop down of assets into this JV going forward. We have many other assets that are complementary. If the structure is optimal for us, we may well drop those down if we see that's the greatest value. If not, DEO, Dominion East Ohio, could go ahead and build out somebody's or Dominion transmission could. But we have that flexibility, and we have evaluated a number of assets that could add value to us to eliminate future capital, give us an earnings stream and support a long-term Utica growth strategy. So watch for that as we go forward. It's a flexibility that we have in the JV. A group will decide if that's best for them, and we'll decide if that's best for us.

So how are we going to grow? When we announced this in December, it was over the holiday. We talked a little bit about it with some folks in the room that were interested, but I really had to feel that most people did not understand the strategic value and the flexibility that this gave us, particularly as we pursued Cove Point. The Utica area is hugely competitive. And if you don't move right now, you are not going to have a major position out there. That was a driving decision for us, along with how do we fund Cove Point and eliminate dilution during the period. Tom's gone through who we elected to participate with, why we like the attributes they bring to the table, why they're position and their relationships make sense in Ohio, but this is what you should be looking for to support that '15 and beyond.

First of all, let me start at the bottom on processing. There's a huge void in Utica and Marcellus on processing. If you go back to Tom's slide on the drills well just in Utica -- excuse me, drills that are -- wells that are drilled in Utica, it showed 223 and it showed 50 producing. If you go to Marcellus, you see exactly the same thing, and that is going to be exacerbated over time because there is not the infrastructure on the gathering and on the processing in these big shale plays to move the gas as quickly as producers want to move it. Somebody's going to fill that void. We will be one of several in Ohio to do that. We see an opportunity of 2 Bcf a day through Blue Racer to add processing in Ohio. We've already identified 4 incremental processing locations. Natrium 2 will probably be the first. These processing units will be moderately built. They'll be able to be brought online very quickly. And you should think about from planning purposes starting in 2013 a processing unit a year at least over the next 4 years. So if you look for that '15 and beyond, you're going to start building processing 3 years before that. And as it ramps up, you're going to have a very, very strong revenue stream coming from processing in this region. There could be 6 to 8 more facilities long-term for processing in the region, the reason to go now.

In addition, the assets we have dropped so far and the majority of the assets we're going to drop down in the JV are gathering assets that are significantly underutilized. We get very little revenue out of these. So dropping them down only to get a cash commitment, but we have a significant revenue stream as the volumes start to be produced here and we optimize not only the existing drop-down assets we have on gathering in terms of future revenues, but on this slide, I know incremental gathering that the JV has already identified in the green and black past lines, both in the North and in the South. So you're going to see incremental revenues as these pipes fill up beginning in 2013 and have growth over time.

We took a look here and said we don't want to invest capital early here. The production is not ready, so we want somebody else to do it. But by 2015, what we've seen in this basin is there's going to be huge production. And so we've allowed other people to invest their capital, we've taken contributions to earnings and we have a 3-year window for a build-out. We feel very optimistic that this case is deliverable, but you need to watch, watch for processing units to be announced this year, watch for 1 or 2 next year, watch for build-outs. This will move very quickly. We're in after discussions with a number of producers, and we are aggressively going after the remaining 1.5 million acres that are available here because if we didn't, we wouldn't have the opportunity to do it.

After we reach equalization, that being when we both invested the same amount of money, our assets that we'll contribute and their cash contributions -- now if they're going to be our partners, not only are they going to pay us $300 million over the next 3 years as incentives to drop our assets down, they're going to invest the next $500 million in processing and gathering expenditures. So for the next 2 to 3 years, we have no CapEx as we build this earnings flow beginning in '15 and beyond.

So now we're at equalization, '14 to '16. The other thing that we really like about this venture, it gives us optimal optionality long-term. It's a perfect MLP. So as we go to equalization, we can start our own MLP, we can join others, we could acquire, the funding mechanism will be there and it gives us 3 years to build it without spending any money. We could IPO it. We have to take a look at what the future market is going to look like, what the value of the assets might be. But if you have watched Caiman and what they have done over their careers, they have found value for their investors, and we are closely aligned with them on how we do that in this venture. And then finally, if we like it, the partners like it, we can continue in joint venture mode. If we did, we would probably debt finance it at the JV, off Dominion's balance sheet and continue to grow it at a fast and large scale. So as we got into it, it served all the features we needed. It allowed us to optimize our midstream business without capital, it gave us long-term optionality and for investors, it gave everybody clear earnings for 3 years, with a plan to grow that '15 and beyond. If we invest more money in this, we watch our capital reduce that Tom showed in terms of our traditional business. If it doesn't grow as fast, we'll invest money in other areas, whether it be West Virginia, New York or Pennsylvania and other JVs. The structure is optimal for us, and I hope you appreciate the value for investors long-term. And see it in the vein that we do as it's something we just couldn't let pass by.

Cove Point. I know everybody's finished in Cove Point, and Tom has outlined where we are in that process. But we feel good enough today to give you an earnings range in Cove Point. But before we do that, I want to make sure everybody understands Cove Point because as I've talked to many of you, there's a misconception with some about what this project is, what the existing project is. So we want to ground everybody if I can for a minute. So this timeline shows the Cove Point import project. When we brought the project back in 2002, we reactivated Phase 1, and that's the first group that we sold. That's the BP shale standalone. That's about half the facility as it stands today. Back then, it was a full facility. That's a 20-year contract. This contract expire in 2023. Then we expanded it, doubled the size, 2009, I call that Phase 2, and we contracted that with Statoil. We elected in 2011 to amend the Phase 2 contracts, and I'm going to show you that in a moment. When we amended those, that gave us an export opportunity. We looked at the shale gas. We saw where we were. We looked at the life of Cove Point because once the import contracts are over, you're liable to have an idle plant there, unless you did something else. So in 2017, we'll have a significant reduction in the Phase 2 contracted levels that we have with Statoil. And now, all of our contracts and import will expire in 2022 and 2023. So as you look at Cove Point, what the export opportunity gives us is the opportunity to extend this plant life at least 13 years, 14 years from where it stands today through 2037 and maybe well beyond that. If we hadn't done this, our revenue stream would go to 0 in 2023. So it was a decision that was made in 2011. We were lucky enough to get export opportunities as we go out, but this is a key item in terms of long-term longevity for Cove Point. Keep that in mind as we see these slides.

First, how are we going to finance this? We've mentioned $3.4 billion to $3.8 billion. That is our best estimate at this point based on where we are with our EPC contractor. It is a range, and we will fine tune the range as we go through time here. And I will give you 1 small caveat, that based on our off-takers or shippers, that it is possible that some would want a very small amount of equity of this project. Don't know the answer to that yet, so again, one reason -- another reason we want to give you a range.

But we look at all potential options on it. And remember, what our -- we have a number of principal goals. One is how to optimize value for shareholders. Second is, how do you build Cove Point and meet our 5% to 6% growth target during construction. This is not a rate-based project. You do not get earnings during construction, so you have to bear that dilution or have some other mechanism until it comes online. And so, what we've elected to do on Cove Point is to build Cove Point with a combination of mandatory converts and debt. Now because it's not a rate-based project, you can capitalize the interest on this project, which we plan to do. But by using mandatory converts, we do not have to bear that equity influence on this project until it comes online.

So let's look at the bottom and talk about 2013 to 2017. You should look for us to put mandatory converts in place to support this project starting in 2013 and support it with corporate debt.

Depending on the structure of the mandatory convert, you're going to get 100 basis points of credit support from S&P and Fitch and from 50 to 100 from Moody's. So in terms of metrics, it actually strengthens our metrics doing constructions until these mandatories are converted.

So equity credit for the mandatories avoids equity and eliminates dilution during construction. The interest component can be capitalized. So now we've built a plan during the 2016-2020 period, and the mandatory is going to start to convert. They'll convert one at a time because this will be a 3-year mandatory window. So as you're issuing the convert over time, we want them to convert over time to not burden our earnings all in 1 year. So look for those as I'll show you on the slide in a moment to mature in the '16 to '20 timeframe. But the important part of that is that our facility will be online in '17. So the earnings that are thrown off in this facility more than offset any dilution from these additional shares. The structure is optimal for a 3- or 4-year project, which Cove Point falls in nicely. And then, after the mandatory is mature, because of the cash flow of this project, unlike a regulated project, that the earnings will increase over time because using that cash flow we'll be able to avoid equity, buy back equity, avoid debt in the company going forward. It is a huge cash flow machine because, remember, this is a take or pay for us. No commodity risk, fixed price and we will process our gas and put it on their shifts, but that's all we're going to do.

Optimal structure. I think it solves all the areas that we were focused on. I think it answers a lot of the investors' questions of how you could you build a project like this without dilution, and I hope it answers today that we can make a 5% to 6% growth and still spend $3.4 billion to $3.8 billion on what we think is a very, very good supporting long-term growth project.

Okay. This is an important slide. I want to make sure everybody understands it. So I've practiced on this slide a lot. Now I'll walk you through it. Let's start at the bottom, which is a light turquoise line. It says "amended import contracts." And let's look at the middle where it says, "original import contracts." So as I told you, starting in '17, that big drop in the turquoise line is because one of our contracts drops off significantly, and all of our contracts end by 2023. Everybody with me on that?

So the first thing, as an export [ph], we have to apply some of those earnings to the earnings that we're losing. And so up in the corner, in that yellow box or orange box, in any given year from 2017 to 2023, that earnings loss is $0.09 to $0.15, just as contracts mature. And we are making the assumption that they would not be recontracted with current world economics on LNG imports.

So we made up for that between $0.09 and $0.15 during the period. Then on top of the purple line, I show you 2 lines, $3.4 billion and $3.8 billion, to give you a range what that capital is going to be. And the blue box in the middle shows the incremental earnings on top of what we're earning today with the import contracts of $0.18 to $0.25. Now I give you the range of -- it's a 10-year average, and the reason I give you an average is this. If you look at 2018, you'll see a big jump. In the first year, it's on an annualized basis. But then, you'll see it dip down for 2 years. And the reason for that is the mandatories are maturing. So your earnings are actually going to go down a little bit from the initial jump you get in 2018. But the most important point is if you look towards 2020, look at the slope of the curve. Because of the cash flows, these projects earnings per share grow over time. So as you think about the Cove Point project, to make sure we have clarity on this, this Cove Point project is worth $0.27 to $0.40 a share on average in a 10-year earnings window.

Now the first question I'm going to get in the session for Q&A is going to be well what's the steady growth rate, so I'm going to answer it right now. Obviously, in 2018, as this comes into the full year of value, that assuming the rest of our plan is achieved as outlined, that you're going to have a significantly higher growth rate than 5% to 6%. But going forward, you're going to lose some of that growth as mandatories convert and should normalize back to a more normal 5% to 6% growth rate. We've always talked about Cove Point as being a complementary project for our 5% to 6% level. It will have a year or 2 of very strong growth over and above that. But over time, it's a complementary project that helps us going forward. We feel confident enough today to show you the range. We will tighten the range as we move through time. But we really like the project. We think it works very nicely for us in terms of our long-term focus for the company, and we hope you like it as well. And as we finish some of the evolution as Tom's talked about, we'll be able to disclose those in the near future. But $0.27 to $0.40 is the value of this project. It overcomes any drag or loss of earnings from our imports and incrementally gives you $0.18 to $0.25.

So if you missed any of that, I'm going to just mention again I put it on the slide because, again, I think this is very important for everybody to walk away with, no dilution during construction. Equity dilution is going to occur in the first 3 years, maybe first 3.5 years of operation. Or if the cash flow is fantastic and it will grow EPS on this project going forward, it extends the life of a project that would be dormant in less than 10 years. It supports and in some years exceeds a 5% to 6% growth, and it gives us a beautiful MLP funding mechanism once it comes online. You're going to have a $3.5 billion, $3.8 billion project out there that as we look at our midstream opportunities, where we may want to go on MLP, you'll have a huge drop-down opportunity with Cove Point. We've thought about that. We'll factor it in to our plans going forward, but there's not many people out there that have that type of single asset opportunity that we're going to have.

Quickly, I want to finish up these slides so we can have a chance for some questions. In terms of financing, we've said before $300 million in terms of DRIP. That's all we're going to have this year. But look for $500 million to $1 billion in mandatory converts. Again, as we start Cove Point, we'll need that level. And our debt on the side, we show the range because we're waiting to see what our final CapEx projections are and what we will need in terms of proceeds from aversion [ph] assets but we feel real good with the range.

In terms of review, 3 20 to 3 50, most of the growth in the third and fourth quarter, long-term earnings drivers are in place. And now with Cove Point, we believe the long-term earnings drivers are being put in place 2018 and beyond. Again, the assumptions for Cove Point, I think we've outlined it pretty clearly for you. It's a great project for us, and we think we've structured it so we can have the capital investment on other lines of business, while at the same time building a terrific export project.

I want to finish up on the slide that we haven't talked about until the very end, and that's dividends. We have grown our dividend by 7% on an average over the last 4 years. We currently have a payout ratio of about 67% based on the midpoint of our 2013 earnings. We have dividend growth opportunities because we believe our growth plan is clear and deliverable, and we've given ourselves some room between 65% and 70%. Tom mentioned earlier, he sees a dividend growth of 6% to 7% over the next several years. And we believe, with that and our 5% to 6% EPS growth that we've outlined today, our visible project growth, our diverse business lines in a very construction regulatory environment, I should say legislative environment as well in Virginia and in Ohio where we operate, that we have the opportunity to provide investors with a 10% total return potential with projects and clarity that most other companies don't have that. We thank you for that consideration. We're opening up for questions.

Question-and-Answer Session

Thomas Hamlin

Thanks, Mark. Let's get my microphone on here. We have several people with mics. And joining Tom and Mark are the heads of our 3 business units. Dave Christian from Generation, Gary Sypolt from Energy and Paul Koonce from DVP. Let's go ahead with -- I ask you please one question and a follow-up. And if there's room, we'll get back to you. Paula?

Unknown Attendee

My first question is in terms of convertible needs, if I side that to Cove Point, what percent of Cove Point should we assume is going to be financed with convertibles? And are there convertibles, sort of, beyond Cove Point for the growth?

Mark F. McGettrick

We showed 60-40 debt to cap for Cove Point. We really like, Paula, the convertible instrument today. We may use convertibles to support other equity needs if we have those now [indiscernible] plan. But right now, we've just shown 13 equity needs. But you should think about 40% for Cove Point.

Unknown Attendee

And then, for drop-downs other than Natrium into Blue Racer, should we assume all of that is essentially coming out of DEO?

Mark F. McGettrick

After Natrium and TL-404, the other outlined -- the others that were outlined by Tom are coming out of DEO.

Thomas Hamlin

Greg?

Greg Gordon - ISI Group Inc., Research Division

Greg Gordon, ISI. So you spent a lot of time talking about your comfort level with short-, medium- and long-term sales growth trends at Virginia. But there's just an awful lot of stuff coming out in the press about how the sequester is going to be -- have a concentrated impact in certain regions. And rightly or wrongly, they focus on Virginia. I'm sure you've run into some sensitivities on it. Thank God you're comfortable with making the statement you made today. Can you give us some sort of sensitivities on what your sort of the range of outcomes are and whether or not if you really got it wrong in the short run and we saw a, let's say, flat growth or 1%, would we still be within the earnings guidance range?

Thomas F. Farrell

Yes. The -- just to give you an order of magnitude, if you -- if the growth rate was cut in half, let's say, we had 0 and the only thing we had was our data centers, we know they're coming, they're under contract. That's $0.04. So you cut it in half, that's $0.04. That's the sensitivity. Our government, as Mark mentioned -- in our budget for this year, reflected in the guidance range is we don't know what's going to happen. We assumed flat -- actually, lower governmental sales in our -- in this forecast. So now, that's just the government paying us. Now -- and the federal government is an important customer for us, our state government, local government in our governmental component is much larger than the federal government. And of course, then you have impacts from the state's economy and things like that. And so, taking all of those things into account, we're confident that we're going to end up in our 5% to 6% growth range.

Thomas Hamlin

Paul?

Unknown Attendee

On the mandatory converts, when this year do you guys think you might be actually issuing them? And it seems like it's a better range. It's a pretty substantial range. Just how should we think about what might be driving the $500 million to $1 billion range?

Mark F. McGettrick

What's going to drive it, to some extent, is how much we plan to spend on Cove Point this year. And as we finalize our EPC contracts, which will be in the near term, we can probably tighten that range for you. I would guide you more towards the top.

Unknown Attendee

Okay. And then, in terms of the pension discount, you mentioned that in 2014, you expect the discount rate to change. I was wondering if that is in your long-term guidance? Or if it is in guidance, and if so, can you give us a feel for that? And in terms of justifying the Blue Racer, you mentioned sort of the options, one of which is being an MLP. Could you just give us a feeling as to the MLP versus the joint venture versus -- sort of your thought process as to why you're not going for -- why is the joint venture now as opposed to an MLP? Just a little bit more flavor in terms of that [indiscernible]?

Thomas F. Farrell

Mark, you answer it first, and I'll...

Mark F. McGettrick

In terms of discount rate, we do have an assumption beyond 2013. So at this point in time, it will be December 31, 2013 is that we will go back to a low to mid-5 range in terms of discount rate.

Thomas F. Farrell

First, we've really worked very hard to get the structure we have on this joint venture. It took us a few months to get it all set correctly and take into account the assets that we wanted to drop down into it. And we think it's -- but it has worked. It's working very well. Caiman is a great partner for us. They have a lot of experience in this business, and they know all of these players. We're not announcing today that we're going to do an MLP, okay? Nobody should take that out of here, out of the room. What we are telling you is though is that this structure, when we -- when you get the equalization just the Blue Racer, when we get to that point, when our cap -- and their capital meets our capital some time in '14 or '15, when that's achieved, then there's a variety of options that the joint venture will have. One is doing an IPO, one is forming an MLP with our jointly owned company or we'll just continue along with the thing. We're going to see how it's going, and -- but what we're after here is trying to maximize value for our shareholders out of these assets. So however we're interested [ph] in looking at the landscape as we get toward equalization, that's when we'll figure out what we're going to do.

Unknown Attendee

Is there a mic?

Unknown Executive

There's one here.

Thomas Hamlin

I guess we'll get Andy next. Go ahead, Michael. And then, we'll get Andy.

Unknown Attendee

Okay, 2 questions, one Cove Point, one at the Dominion Virginia Power. On Cove Point, why do the convertibles this year if your construction really doesn't start until next year? That's the first item. And then, on the rate case, given the legislation, and that's very promising for you guys in terms of thinking about the Virginia utility, what do you think the main focus points of this year's GRC are going to be?

Thomas F. Farrell

Well, first, there will be prolonged lead items, which you have to start purchasing in order -- you can't just -- that's why there will be some capital -- significant capital spend on Cove Point this year, and there'll be some mandatory converts issued to match that. As far as the GRC, as you call the general rate case, there's actually going to be 2 parallel cases going on. We will file the biannual review, which is -- it's not a rate case. It's an earnings test. What did you earn during the period? What adjustments can be made, et cetera? What the legislation does is the legislature recognizes. And as I said before, this would probably expect -- this is the Virginia law. We expected these outcomes. But there is clarity around it in this legislation that if our shareholders bear an expense in a period, that's when the expense is borne, as far as the earnings test is concerned. So that's an important element of the biannual review. The rate case will also be filed because we overearned in '09 and '10. So as a result of that -- we were found to have over earned in '09 and '10. As a result of that, the -- we were ordered to file a rate case in -- just in the event we were found to overearn in '11 and '12, we would have the data available to them to make a determination. So that data will show that we need a rate increase, obviously, if we're earning at or around 10. So those will go along and ROE was always an issue. Assuming we don't overearn, it's more of an issue for what the next earnings test will be set on, as opposed -- because there won't be any change in rates. So the ROE will obviously be an issue. I'm not sure what somebody I'm sure will have something to say. Lots of people will have lots of things to say, I'm confident.

Unknown Attendee

I'm just a little slow, you guys know that. On the contribution for Cove Point, are you guys saying that after you back out for the imports, it's $0.27 to $0.40 upside?

Thomas F. Farrell

No.

Unknown Attendee

Okay. Can you just clear...

Thomas F. Farrell

Ask it again? Just after we back out the...

Unknown Attendee

After you back out the LNG import earnings, what's the ongoing range for it?

Thomas F. Farrell

It's the middle column.

Unknown Attendee

Middle one? Got it.

Thomas F. Farrell

So you have to use the first column to cover the import earnings of $0.09 to $0.15 depending on what year you look at it, the middle column of $0.18 to $0.25, right? Whatever it was, that's what the incremental earnings on top of that is going to be.

Thomas Hamlin

Jonathan?

Jonathan P. Arnold - Deutsche Bank AG, Research Division

I read in the 10-K and we talked about the TSA agreements that there's, kind of, a condition around customer contracting. Can you just elaborate any further on that? And is there a condition that will, kind of, outlive the eventual signing of the TSA?

Thomas F. Farrell

The answer to the second part of the question is, no, it will not outlive the signing of TSA. I'm not -- I don't want to elaborate more than I have. It's a confidential relationship with these shippers. Or elaborate more than we did in the 10-K. It's just we're very -- I think you tend to be cautious about claiming that we're going to go forward with them until we're highly confident of where we are in the stages of the negotiations. We are at that point now with -- there's going to be more than 1 shipper. I won't say how many, but there will be more than 1. And the state of negotiations are in their final stages, and we're in the same situation with the EPC contractors. They're in their final stages. We're -- we think we'll get the DOE license. We think we're very high in the queue. I actually think those who finished the commercial aspects of their proposals will do things more quickly at DOE. I think you'll be the first -- maybe you go from third to first. I'm not -- I don't know exactly where all the others are. But I don't want to elaborate more than what we said about the 10-K, and we're just -- we feel very good about where it is. Anything can -- until they're signed, they're not fine, but we believe we're very close.

Jonathan P. Arnold - Deutsche Bank AG, Research Division

Once it's signed, this condition is just not a factor?

Thomas F. Farrell

Correct.

Thomas Hamlin

Brian?

Brian Chin - Citigroup Inc, Research Division

You gave a fair amount of data on the hedges for the data centers that you've got out there with regards to your power demand. In the event that the sequester ends up having an effect on those entities that have hedged out with you in those data center power demands, do you have any sort of material adverse clauses or any other recourse should something unforeseen happen?

Thomas F. Farrell

Well, I wouldn't call -- I'm not sure we used the term hedged. They are minimum-take contracts, which give us the confidence to go build the various stages [ph]. So they're not government-owned data centers, okay. And that Internet traffic itself is not much of it comes from Virginia-based companies. Facebook is one of the customers, for example. So I wouldn't think -- I don't think it's accurate to -- and I'm not sure if this is what you're suggesting, but it's -- I don't think it's accurate to think that because the data center's sitting in Virginia that if there's an impact on the Virginia economy, that the activities in the data center will somehow be -- the growth will be retarded somehow. The customers are -- most of them are not Virginia-based companies, and the activity is not necessarily taking place in Virginia that drives through the data center. If that -- I hope that answers your question.

Thomas Hamlin

There's one here. Yes, Dan?

Dan Eggers - Crédit Suisse AG, Research Division

I guess, if we could just talk a little about, kind of, the natural gas market and the idea of adding the processing facilities in the Blue Stream joint venture. With so much gas behind the pipe and low gas prices on top [ph] slowing in drilling activity, what kind of interest are you seeing from prospective customers for signing long-term contracts right now to build these facilities? And if you think about the design of the big scale Natrium project or smaller add-ons, how do you see this business evolving out of the JV structure?

Thomas F. Farrell

Well, Gary, why don't you talk about the size of the structure. Natrium is a very large one, and these add-ons will be smaller. But as Mark said, we'd be up to 2 Bs [ph]. Eventually, it could be run through these facilities.

Gary L. Sypolt

The Natrium facility itself $200 million a day of processing, 36,000 barrels a day of fractionation. That's a big facility. But it also is the first in the area. So it was appropriate for it to be a big facility. I think some of the others are going to be staged and build as they go. I think Tom showed 4 different locations around for Blue Racer to build additional processing. We think those will come in as smaller units and then be added to as the gas continues to flow in the future.

Dan Eggers - Crédit Suisse AG, Research Division

What are you guys seeing as far as receptivity from the producers to sign long-term contracts right now? Are they willing to sign deals to get these things moving forward as from the hold up, I guess, previously if you guys are to put capital up on your own? Is there a change going on? Or is this just the effect of kind of the Caiman's money going up in front of yours, that it feels more comfortable starting to build these things early?

Gary L. Sypolt

It's a great question.

Thomas F. Farrell

Go ahead.

Gary L. Sypolt

Yes. The -- what you really see here, I think, is we're donating assets into this JV, which essentially -- it keeps us from actually spending a little bit of our own capital until equalization occurs. Caiman's coming with a lot of investment in capital of its own. If you ask about what happens with regard to the producers and their willingness to enter into a long-term contracts, they're very willing to dedicate acreage behind these processing plants and that's pretty much the typical way that business is being done now going forward.

Dan Eggers - Crédit Suisse AG, Research Division

And I guess one last question. It didn't come up today, but just talk about the retail market for Dominion Retail, what you guys are seeing there, the competitiveness on margins and can that sustain the 5% to 6% earnings growth for that business...

Thomas F. Farrell

Sure.

Gary L. Sypolt

Well, the retail business remains to be very competitive. I just looked at some numbers last week. If you look at the number of registered retail competitors in Ohio, Pennsylvania and Illinois since 2010, the number of registered retailers has tripled. So you have a lot of new entrants trying to get into that market. I think, as with any market, that's going to have to sort itself out. If you look at gas margins, interestingly enough, to a large extent, they've stabilized somewhat since the post-Katrina/Rita [ph] period where they were quite large. They have stabilized. We think that's good. If you look at the Texas market over time, what we see is some stabilizing of the margins, although a lot of volatility. And of course, I think a lot of that has to do with the ERCOT market design and the energy-only aspect of that. If we look in the mid-Atlantic and Northeast, you still see a lot of competition. You still see a market that's sort of looking to stabilize around margins. We've not seen that yet. But I think that's a result of a lot of the competition that's come in.

Thomas Hamlin

We have time for 1 or 2 more. Carl [ph]? And then...

Unknown Attendee

While I recognize that the Cove Point -- you only signed contract with shippers, shippers obviously have to have somebody buying from them. And I wonder what the -- I've seen pricing as to where it might get shipped. But what's the shipper anticipation now, and how does that affect their willingness to sign a contract and the kind of contract that you write?

Thomas F. Farrell

Well, if I would tell you who they were, you could ask them. And I'm not trying to be cute. I'm not trying to be cute, well just have to leave that to them. And you'll know who they are soon.

And there's one in the back. Rebecca?

Unknown Attendee

Two questions, one on Blue Racer. You guys typically [ph] operate like an MLP. Can you talk about the contract structure on the processing plants and then how that income flows through? Is it the distribution that's coming from that JV? Or how does commodity sensitivity factor in?

Thomas F. Farrell

Well, for the first processing plant we have in there is Natrium. This is a 50-50 partnership between Caiman and ourselves. So in the Natrium example and in future examples that the revenue stream and earnings stream will be shared 50-50 between the 2 partners.

Unknown Attendee

And the contract structure, is it fee-based or PLP [ph]?

Thomas F. Farrell

Well, the Natrium structure is fee-based. There's a little volume outside of that, but mainly fee-based. We'll have to see what the contact structure is in the future for the other processing plants.

Unknown Attendee

So there may be some commodity sensitivity depending on how contracts are structured on the processing plants?

Thomas F. Farrell

There may be.

Unknown Attendee

And then, second, you talked about potentially that Blue Racer would be -- would fit as an MLP and that Cove Point would be a beautiful candidate for an MLP. But you didn't talk about the transmission -- existing transmission assets, where do they fit in the mix -- gas transmission?

Thomas F. Farrell

They fit at Dominion Resources.

Unknown Attendee

That is a potential for...

Thomas F. Farrell

Unlikely, but potential.

Thomas Hamlin

Okay. I think we're right at 12 noon. Thank you, all, again, for coming, and our IR team will be happy to follow up with any questions that come up. Thank you again.

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