Good morning, everyone. Welcome to the Third Annual Investment Community Conference for Enbridge Energy Partners. My name is Sanjay Lad, and I'm the Director of Investor Relations at Enbridge. In the spirit of safety, let's pause for a moment quickly for a quick safety message. In the event of a fire alarm, please exit through the doors at the back, go down the stairs, and there you'll be met by hotel personnel who'll direct you to the street level exit.
As a reminder, this presentation is being webcast. If you have any questions, please wait for the microphone, state your name to identify yourself and which institution you're with so that people listening to the webcast can follow along.
Our legal notice. This presentation will include forward-looking statements. The risks associated with forward-looking statements have been outlined on the slide and in the partnership's most recent SEC filings, and we incorporate those by reference today.
And with those opening remarks, it is my pleasure to introduce Mark Maki, President.
Mark Andrew Maki
Good morning, everybody. My name is Mark Maki. I'm President of EEP. And I want to take just a minute before I start my prepared comments and talk briefly on the status of filing of our 10-K for the year and then go into the introductory comments. As you know, we did announce back in January that we would be -- we had an accounting matter we were looking into one of our subsidiaries, and that process is being worked through. Nothing really new to update from any of our previous disclosures. We expect to be able to file our 10-K next week. And when we do so, we will release results at that time. If there was by way of restatement required and we knew that, we would have to provide that information to you at this time, and so nothing has changed with regard to that.
So I'm going to provide the strategic overview, and I do want to thank everyone for taking the time this morning to invest a part of your day with us. We as a management team very much enjoy the opportunity to come in and speak to the investors here in New York on the equity side and the debt side. We think this is a great way for us to tell our story in a lot more detail, a lot more carefully in a lot more wholesome fashion than we can any other time. So the analyst calls, of course, at the end of the quarters or we talk about our outlook for the year coming up is a relatively compressed period of time. We don't get a chance to really address things in the fashion that we'd like to, and this forum really presents us that chance.
The one thing we ask from you as an audience is please do give us some feedback at the end. Sanjay will be seeking that from you, and certainly, that helps us to tailor this in the future to make the materials more useful. I want to introduce the management team that's going to be here today to speak, and I introduced myself already, but I want to introduce Steve Wuori, John Loiacono and Steve Neyland. If you 3 could please stand up quickly. Steve heads up our Liquids Pipeline group. All these folks are folks you've seen before. John Loiacono heads up our natural gas pipeline group inside the partnership, and Steve Neyland is the CFO for the partnership. As well, in the audience today, we've got Dave Wudrick, the Treasurer for the partnership. He's at the back. And Jody Balko, Jonathan Gould from our Investor Relations function up in Calgary. And outside, you met Margaret Liu and Claudette Dionne, and they are there to help you with anything you might need today.
One other special introduction I want to make today is Leon Zupan, and Leon is here. Leon will be assuming a new role within Enbridge in connection with Pat Daniel. His retirement was announced here recently. He'll be retiring in 2012 after a great run at Enbridge. And certainly, he will be missed. Replacing him, in those very, very large shoes will be Al Monaco, and with Al moving on, Leon will be stepping into Al's role as President of Gas Pipelines inside of Enbridge. And that responsibility also includes looking after Enbridge Energy Partners. So for Terry McGill and Doug Krenz and myself, Steve, we look to Leon as our leader inside of Enbridge.
Leon, do you want to go up and just give a couple of quick words? We wanted to introduce Leon to the group because you'll be seeing a lot more of him in the future.
Leon A. Zupan
And I welcome you as well. I certainly do look forward to having a chance to spend more time with you over the next year as well. We do take our Investor Relations business very seriously. We do want to make sure that our story is clear and that we've got answers to everything that you have as questions in order for you guys to continue to invest in the partnership. I am looking forward to my new role. We've got a very strong management team in Enbridge Energy Partners. We've got a lot of great opportunities both on the liquids side and on the gas side. I've been on the liquids side for almost 25 years now in various roles within Enbridge, from operations to managing our customers, business development and for the last number of years here as the senior leader of our operations group on liquids for both Canada and the United States. Over the last 7 or 8 years, I worked very closely with the team in Houston on our liquids issues, and I look very much forward to relocating from my home in Alberta to Houston, Texas here this spring and have an opportunity to work on a day-to-day basis with our leadership team. We've got a great story this morning on both the liquids and the gas side. We've got a lot of opportunities that we are not just looking at but actively managing and pursuing. And I'm not going to take any more time and stand between you, Mark, and the story, so I'll turn it back to you, and I look forward to seeing more of you guys in the future. Thank you.
Mark Andrew Maki
Well, you can certainly ascertain from Leon's comments one of the reasons he's going to be a big part of the partnership in the coming years is his deep involvement in the liquids side of the business. One of the key themes we're going to come back to over and over again today is the robust amount of growth around our liquids systems that we have. Whether you're looking at the crude oil systems, the old Lakehead System around the Great Lakes region, our pipeline in the Bakken shale, our storage position in Cushing, we've got a great story around the liquids side over the next several years. But all of it starts with a focus on operations and integrity and safety. And certainly, you're going to hear that theme again and again in Steve Wuori's comments and those of John Loiacono. It all starts there. If you don't do that first thing right, the next objective, which investors are certainly interested in, is tough to attain. And so that is where this company focuses a substantial amount of its resources and time. That is job one, whether in terms of capital that we invest, what our people focus on day in day out just to make sure that we are a safe operator.
In terms of investment thesis, one of the key things about safety and integrity, it also applies to how we handle we our bondholders and our equity holders. And we want our investment to be a safe, stable, secure investment for our investors. We are targeting distribution growth in the 2% to 5% range. In our history, we've been around since 1991, we've never cut our distribution. We've been in a number of down cycles in that period of time, and we have never cut. Whether it was the financial crisis in '08 or '09, crude oil price crash in the '99 time frame, this company has never cut its distribution.
We have a great growth story in the liquids side, and we'll get into that in more detail a little bit later on today. And it's that suite of organic growth opportunities that we think really makes Enbridge Energy Partners unique, that and the close relationship that we have with our general partner, Enbridge Inc., and we'll touch on the entities in the family here in a minute. And then for our bondholders, do understand, and we always say this, but we mean it, and we've conducted our business in this fashion as long as I've been associated with the partnership, and that is we will maintain an investment-grade credit rating, very important to us.
As far as the members of the family go, the chart here shows you the various members of the Enbridge family. They're easily invested in, in the U.S. We got the parent company, Enbridge Inc., at the top of the ladder here. And the 2 entities we're going to focus on today are those that are at the bottom. In the magenta, Enbridge Energy Management, and in the olive green, Enbridge Energy Partners LP. EEP and EEQ are their ticker symbols. Enbridge Energy Partners, of course, your traditional master limited partnership, a vehicle that pays a big cash distribution every quarter. You get an allocation of taxable income at the end of the year rather than a 1099-DIV, and you get a form that you use to prepare your income tax return, K-1. And EEQ is a little bit different way of investing in Enbridge Energy Partners. So if you don't want the complexities that occasionally come with a partnership, it's not that hard for those who've got Turbo Tax, or go to your tax professional, but it is a little bit different than investing your traditional C corp. EEQ presents a different way to invest in Enbridge Energy Partners.
Instead of getting a cash distribution and a K-1, you get a dividend of additional shares. There are only 2 structures like this in the MLP space, ours and Kinder Morgan has the other. But this is a way for you to invest in EEP, and provided you meet the holding period requirements, you can cash in those dividends and receive capital gains treatment for them as you monetize your shares. So it's another way of investing in EEP. Both methods, the advantage of the partnership structure and the EEQ is a tax-effective way to get a good yield.
I want take a moment and talk about Enbridge Inc, because it is one of the key things that differentiates Enbridge Energy Partners from most other folks in the MLP space. Enbridge Inc., by itself, is a very large company, many times the size of Enbridge Energy Partners, very substantial equity market cap, as the slide shows, $30 billion-plus. And for the investors on the bond side, a very high credit rating, A-low from Standard & Poor's and Dominion Bond Rating Service, Baa1 from the folks at Moody's.
And one of key -- and I was mentioning this to one of the other fellows here today, we were talking before the discussion, Enbridge's track record on the dividend side and the growing of earnings per share is just about unmatched in the space. No matter what history you look at this company over, from its inception, the last 10 years, the last 5 years, the last couple of years, and then what the outlook is going forward, Enbridge Inc. has driven and provided tremendous growth and shareholder value through growth in earnings per share and dividends per share. The outlook for the company looking forward the next several years is growth in earnings per share of double digits, and it's a reasonable expectation you'd see growth in dividends per share in a similar fashion.
EEP's investment thesis is a little bit different than that of the parent company. And the way we look at EEP in the family is that it is more of a yield vehicle, so the yield here is in the 6.5% range. At yesterday's closing, it's a little bit more than that. But the key thing is yield with tax deferral makes this a very attractive investment opportunity for investors. Our history, again, is very stable distributions and proven growth in distributions over time. We have, by and large, what we think to be low-risk business assets or assets in our business mix inside the partnership, and again, I want to hit on this because it's a very important distinguishing characteristic for our partnership, that very strong general partner.
I'm going to change gears a little bit here for a minute and talk about long-term fundamentals. And the reason really for this is we inside Enbridge, for as long as I've been with the company, have always taken a very careful approach to long-range planning, strategic planning, long-range planning, whatever term you want to use. This company is always very much focused on long-term fundamentals in North America, around the world, what does that mean to supply and demand inside the continent, regionally, what does that mean for transportation opportunities, very much focused on where our pipeline solution is going to be required now and in the future. And that's how we plan for the business. And so we look at long-term fundamentals like U.S. energy consumption, as shown here, from the EIA. And what is certainly clear from this chart is oil, no surprise to anybody in this room, oil and natural gas are a big part of the U.S. energy picture going into the future. And so these 2 areas are the centerpiece businesses inside of Enbridge Energy Partners.
If you look a little closer at oil supply, and this -- just to understand what the chart on the left is, it's showing crude imports and crude production. It doesn't pick up NGL production or refined products imports. And what you see here is an interesting development, and we'll talk about what this means in terms of our assets and the investment opportunities that we have in front of us in Steve Wuori's section in a little while. But certainly, you see growth in domestic supply. A few years ago, you would've thought I was crazy if I put that up there, but certainly, with the growth in the Bakken, the Eagle Ford, the Niobrara, especially Utica, certainly the Marcellus, other areas where you've got either crude oil windows or wet gas windows, you see growth in the United States and in oil production. Imports, though, are going to remain a very important part of the U.S. oil picture in the future. And we couldn't ask as a country for a better trading partner than Canada. And the oil sands resource that Canada has been blessed with is a tremendous source of oil for United States. We can't lose sight of that relative to other regions of the globe.
The other key fundamental on this slide is electricity generation and the sources for that. You see, of course, coal, gas, nuclear power and renewables. And what I want to focus on here just for a moment is natural gas. We get asked a lot, but we're heavily an oil business. We have a large natural gas component as well. Sometimes people ask us, why do you have the gas component inside of EEP? And it's because we are truly a long-term believer that natural gas is the critical bridging fuel and a long-term fuel for North America. Whether it's for power generation, maybe for transportation down the road, it is an important energy source for the Enbridge Energy Partners to be a part of. And so that's why we have the gas business inside of EEP.
As far as the assets go, just to give you a quick overview here on each, Steve Wuori and John Loiacono will give you a much more detailed presentation, but you can understand the positioning of our assets. This map does simplify the complexity of our systems a great deal. But certainly, the pipelines around the Great Lakes region, this is part of the system out of Canada, which is part of the world's longest, largest crude oil pipeline. Today, this system is moving somewhere in the U.S. between 1.7 million, 1.8 million barrels of oil a day. The system serves refining centers in Minneapolis/St. Paul, Superior, Wisconsin, Chicago, Detroit, Toledo, Sarnia, Toronto, the refining market in Western Pennsylvania and then through other carriers, other refining centers throughout the Mid-Continent in the U.S.
Our gas business is centered in around Texas and 3 of the very prolific areas in Texas. The Granite Wash in the Anadarko Basin, the North Texas Barnett Shale resource and the East Texas Basin, including the Texas side of Haynesville. The other 2 key liquids systems in our family are our North Dakota system and the Ozark system along with our Cushing storage position. These are great assets located in very strategic areas of North America.
Our company's basic growth strategy is to take that asset platform we just talked about and, considering the fundamentals in both the oil and natural gas space, provide infrastructure solutions to our customers. And when you look at our asset position, whether it's the oil pipeline out of Canada or the position that we have in the Bakken, these assets are in critical locations. Our G&P footprint is very large, centered in Texas, an area we're going see increasing population growth over time, increased consumption of natural gas or power generation, and because of the resource that Texas has been blessed with, it's the starting point for a lot of the natural gas infrastructure within the U.S.
Now we've talked about Enbridge Inc. a couple of times in the presentation, and certainly, you're all aware of some of the initiatives Enbridge Inc. has recently announced, including the Seaway reversal together with Enterprise from Cushing down to the U.S. Gulf Coast. The partnership's close relationship with Enbridge Inc. is going to lead to a number of very exciting growth opportunities for EEP, and Steve Wuori will touch on some of those in more detail. But again, that close relationship with Enbridge Inc. is going to spawn, in our view, some very substantial and meaningful investment opportunities for EEP in the coming years.
We are, as partnerships go, very much an organic growth story. We are not a partnership that depends on drop-downs from the parent or depends on acquisitions from the outside in order for us to grow our business. Those are really bonuses. And certainly, long run, the opportunity to drop asset down from Enbridge Inc. is definitely something we think about as a management team and certainly the Enbridge Inc. leadership thinks about -- as it thinks about the health of the partnership down below. Today, our partnership is basically a mix of oil and gas. Roughly 2/3 of our operating income comes from the oil side, about 1/3 is natural gas. But we expect over the next few years as we develop out some of the oil opportunities that we have to see our operating income evolve to more of a 75-25 split between oil and gas. And some of those secured opportunities in the box above are examples of projects we have announced that will help us with that migration.
And what I really want to focus on is what's down below, which is potential growth projects, and these are going to come from some of these initiatives by the parent to expand the market access of oil from Canada and Bakken and other locations to Eastern Continental markets in the United States and Canada and southern markets through projects like the Seaway reversal. They're going to lead to investment opportunities around our Great Lakes area, Lakehead pipeline system.
In addition, we all know the Bakken story. It's a great story, and Steve will give us a lot more color on that momentarily. There's a lot more opportunity there as well.
So to come back to this, we do -- and we get quizzed on this a lot. 2% to 5% growth, shouldn't it be higher or couldn't it be higher? We certainly -- as a management team goes, we are a very conservative group. We firmly believe we can deliver 2% to 5% growth rate over the long run, and that's the way we tend to look at the world, is in the long run. And certainly, with some of the opportunities that are in front of us and potential around the oil side, we can do -- certainly target the higher end of this range as an objective inside of the partnership.
So I'm going leave you with the key takeaways here, because you're going to hear about these several times throughout the day, and I'm not going to read this off to you. But I'm just going to ask you to keep these in mind as Steve Wuori speaks, as John Loiacono speaks and Steve Neyland speaks about their respective areas. Both Steve and John, they're going to bring a passion up here to their respective businesses that is very exciting. Very, very blessed to be working with these folks and helping to execute the company strategies.
The basic format today is we'll take questions after each major section. We'll take questions at the breaks and certainly over lunch. With the number of management folks here, we can do that. But happy to take some high-level questions now and then return the podium over to Steve. Anything on anybody's mind?
Mark Andrew Maki
It's early. I know. Yes, sir?
[indiscernible], and you said that was reasonable to expect that the distributions would be not exactly your [indiscernible] of 2% to 5%.
Mark Andrew Maki
Yes, let me explain. That was a comment directed towards the parent company, Enbridge Inc. We've got basically 3 kind of vehicles inside the Enbridge family: the parent, Enbridge Inc.; Enbridge Energy Partners; Enbridge Energy Management. Enbridge Partners, Enbridge Management are 2% to 5% growth in distribution. The parent company, though, double-digit growth earnings per share, likely double-digit growth in dividends. Yes, sir?
John D. Edwards - Morgan Keegan & Company, Inc., Research Division
[indiscernible] comment there for management. John Edwards, Morgan Keegan. Mark, I thought I heard you then make a comment with regards to potential drop-downs from Enbridge to the partnership. And I don't really remember you suggesting that, that was something that would be a focus, at least in the past, and so maybe if you could expand a little bit upon that.
Mark Andrew Maki
Yes, we've done drop-downs on that. Yes, we've done drop-downs in the past, John. An example of that, the North Dakota system was a drop-down back in 2001. It was the best drop-down deal ever done, as far as I'm concerned. But I get grief over that, because I was in the Canadian system at the time and helped sell it down to EEP. But we do them when it makes sense, when there's a strategic objective that we're trying to accomplish, John. And the thing that the partnership has been uniquely blessed with is a great suite of organic growth opportunities, really for as long as I've been associated with it. The guys that have the drop-down stories, they may not have much in terms of organic growth, really, to look to. And so as long as you've got this good diet of organic projects, that's where we're going to focus. The drop-downs become something to look at in the future. When you asked me the meeting of the minds on this, the parent needs capital, and it looks like it makes sense to them to drop an asset down to EEP. And EEP is a willing buyer of those assets. They fit in with our map. It makes for a great strategy, but it's not something, John, that, today, we're in a kind of big hurry to do. We've got lots of organic stuff on the plate.
Mark Andrew Maki
Our history has basically been we've had these big capital programs. What you'll typically see is slowdown in terms of the amount of the distribution increases. And I think it's reasonable to expect that as you go into one of these heavier capital programs, your capital raise will be higher. But what you'll see is when we come out of them, then our distributions do tend to increase. And I think that would be a reasonable expectation. So with the opportunity suite, that's the potential here. That would provide us the, I think, the necessary momentum to see us go into the higher end of the range. And again, we speak of the 2% to 5% as really being a good long-term objective. We've got a pretty good history last several years of being 3.5%, a high 3s kind of range, and that feels certainly like a good target for us, long run.
Mark, as you become even more oily and more fee-based, does that have any impact for your distribution coverage?
Mark Andrew Maki
With the oil business, that business will tend to take or allow for you to take your distribution coverage to more of the 1:1 kind of range. Now historically, what we've talked about inside of Enbridge Energy Partners is -- if you go back before we had the gas business, like a 110 was our typical target. When we got into the gas business, it was a 115-plus. And as we become more oily again, I think the 110 feels like a reasonable target for us.
Suzanne M. Hannigan - Janney Montgomery Scott LLC, Research Division
Suzanne Hannigan, Janney Montgomery Scott. Mark, you have a couple of slides here showing EIA projection, long-term projections for consumption and supply, realizing that no very long-term projection will be accurate. Are these what you use in your long-term planning?
Mark Andrew Maki
It's part of what we look at, Suzanne. In addition, we have our own internal studies, as you know, we develop on the supply side. We look at studies by the NEB, the CAPP on crude oil. We have got other third-party providers that we look to on the gas side and the NGL side, so there's a whole bunch of information that we pull in. Some of it is a little proprietary, and there's other things associated with it. So we tend to rely on these presentations, things that are public.
Compared with the EIA, what is EEP's view on the potential penetration by natural gas of the automotive market, especially trucking market?
Mark Andrew Maki
That's probably the area we see the most potential for natural gas consumption as far as transportation fuel would be on the over-the-road trucks. And on the Canadian side of the company, there's been some work done, really, out of the distribution utility in Toronto with [indiscernible] and some research along with some of the natural gas companies in Canada into potential installation of fueling stations along some of the major corridors. But that is an area we do see potential, in fact. I think General Motors just recently announced a natural gas option for their pickup trucks, which I think is a pretty interesting development. So given the cost of natural gas, it's something we think has potential.
I'm getting a little short on time, it looks like here. So a couple more, and then we'll get Steve up. Okay. All right, Steve, you want to -- thank you very much, everybody.
Stephen John Wuori
Thanks, Mark. Good morning, everyone. I actually hadn't got the memo about bringing all that passion, and so J Lo has got about an hour to work some up. I thought I was just supposed to wear a tie.
Just before we surrender to this slide deck, and I guess it advances like that? I just thought it'd be worth talking a little bit about things that have happened since last year, since we were together at the Second Annual EEP Day, because it really is remarkable, especially as we look at the Liquids Pipelines system. First of all, there have been 3 key market developments that you have heard about and you've seen announced by Enbridge Inc. that all will bring more volume through the EEP system. The first, of course, as Mark mentioned, is Seaway. That's the most recent, the acquisition of the 50% interest from ConocoPhillips of the Seaway system, and we're now with Enterprise actively reversing that to unlock the Cushing bottleneck, make it possible for more Canadian and Bakken barrels to move through Cushing and also Permian and other barrels that are bottlenecking at Cushing to get down to the Gulf Coast. So that's an important development, because that, in turn, led to 2 open seasons that we've just held as Enbridge, ex Flanagan or Chicago, Illinois, to move crude all the way down to the Gulf Coast. The second open season concluded just recently. We're not ready to release results of those, but we have long-term commitments in the hundreds of thousands of barrels between those 2 open seasons, starting in 2014, ex Flanagan. So that is going to pull a lot of Canadian heavy barrels, primarily some Bakken light barrels as well, through the EEP mainline system.
The second one, going back in time, was the Detroit-Toledo agreement that we made with Marathon for their Detroit refinery conversion and BP for Toledo for increased supply through this Toledo pipeline, Line 17, that comes off of our Line 6B. That, we announced and are working on. That is going to pull more volume through as that refinery in Detroit converts to heavy crude. Again, more Canadian heavy threading all the way through the system and getting down to those areas.
And then the third one was the Line 9A, as it's now being called, reversal and the expansion of Line 5 in the partnership. And that is to move 50,000 barrels a day of incremental light crude to the Ontario market. The Exxon-Imperial refinery at Nanticoke, Ontario is the one that is going to feed off of that. And so that's resulting in a reversal of the western portion of Line 9. And again, it's all moving more volumes through the system. Those will be primarily light Canadian and Bakken barrels that comes through there. So 3 things on the market side that have evolved in the last year.
And the other thing that I find interesting is that it wasn't that many years ago when on analyst calls and I guess it was prior to us having EEP Days, we would say, "Well --" and Mark, I remember saying, "Well, we're not likely, really, to expand the mainline a lot more." This was after Clipper and Southern Access, and Mark would say, "Now it's basically going to be volume growth on the system that's going to drive the EEP story," that after the mass construction of $5 billion worth of Alberta Clipper and Southern Access in the 2008 time frame, '07 and '08 time frame, that, that was really going to be it for a while. And here we are now, as we sit in March of 2012, talking about expanding Alberta Clipper and expanding the Southern Access line with horsepower. So it really has been a remarkable change. And I think it's all been driven by a number of factors: the oil sands growth, the Bakken growth that we'll talk about and also the need to get these into new markets. And that is a continuing fascination of ours, is to examine the fundamentals with almost a slavish devotion to understanding exactly what's going to happen in the market and where the rising production needs to go and then trying to be ahead of that curve, maybe in a way that no individual producer could be in terms of saying here is the infrastructure piece that's needed to get to market x or market y.
So it really is a situation where we're excited about expanding the mainline and more volume moving through the mainline, but we don't want the mainline to become market-limited. And when that happens, when there just is not enough places for the crude to go, Cushing is a market-limited market, right, and it's an infrastructure-limited market primarily. But when you have no place for the crude to go as it rises in production, price becomes the victim. And that is -- our firm intent is to make sure that price discounting is less for producers over time. It's a double-edged sword, because the refiners are all feasting on that differential. But I think generally, we want to see more equilibrium in the pricing for the rising production.
It's an amazing time in North America. I mean, who would have thought, really, that crude would stay up around $100 a barrel? We sit here now with virtually every forecaster projecting crude prices for the longer-term higher than what is needed for shale production in the Bakken, the Eagle Ford, the Niobrara and other places, that being around $60 a barrel. Why is it staying so high after several years of U.S. recession? And of course, the answer is elsewhere in the world. But I think there's only one caution about all of that, and that is, is there anything that could interrupt the oil price picture? I think we're good down to $60 a barrels, certainly, for healthy economics in the oil sands and the oil shales. Below that, it starts getting pretty project-specific.
So just a few reflections as we start looking into this overall picture. Just in terms of key messages, and you'll see this again at the end, we certainly have, as Mark mentioned, a continuing focus on operational excellence, pipeline integrity and safety. Since Marshall, Michigan -- which was a shock to us, we're a company that had not had that happen in that scale. The largest thing that was even close was over 20 years before, in Grand Rapids, Michigan. That shook us, because we're not a company that operates kind of on the edge on a shoestring. We're a company that operates with a very powerful operating philosophy and maintenance program. Marshall was a shock, and we are absolutely determined to not see that happen again. The asset basis is very well positioned. The crude supply-demand fundamentals are outstanding, especially in the areas where our pipelines run. We have lots of opportunity for increased throughput and for capital investment.
Just looking at the system, a couple of things to point out. You're very familiar with it, I know, so I won't spend a lot of time on the physical part of it, but the new line, of course, is the Seaway connection. And we really needed a way to get to the Gulf Coast. And if you think back about our announcements and our ruminations in presentations over the last 5 years, we have talked about a whole number of ways of getting to the Gulf Coast. We talked about Texas Access, then we talked about the Vantage project. We were joint with BP on a project to reverse BP 1 and build the link from Cushing to Houston or Port Arthur. Then we had a thing called Monarch, and that was what was enduring when we got involved with Enterprise, and that association, which is also true, as you'll hear on the natural gas liquids side, really, frankly, was what unlocked the opportunity to get into Seaway and to now have the joint project that we have to the Gulf Coast.
But the mainline itself is a 2.5 million barrel a day capacity system. We have somewhere around 600,000 to 800,000 barrels a day of capacity, or it's about 600,000 barrels a day of capacity that is not being utilized, depending on how and where you measure it. We can increase the capacity crossing the border by anywhere from 800,000 barrels a day to 1 million barrels a day without the need for a presidential permit, and I think that's very important in the politically charged environment in which we find ourselves.
The other important thing is that the mainline is now underpinned by a 10-year tolling deal that has less effect on EEP other than positive, other than to guarantee better the future of EEP's throughput. The battle we were fighting up until last year was the fear that somehow, the Enbridge system was going to vacate of crude oil when systems like Keystone XL get built and so on, and the result would be a spiraling upward toll. And there was some fear-mongering in the community a few years ago that the Enbridge toll was going to go to $6 a barrel, the combined Enbridge EEP toll to Chicago for a heavy barrel. Now with the CTS, we have fixed that at $3.85. That will escalate a little bit with inflation as time goes along. Where EEP fits into that is that, that helps to ensure that the volumes stay on the system, and yet EEP is not taking the volume risk. And so really, it is a sweet spot for EEP, specifically. Generally, the capital that EEP invests in the mainline will be covered under a facility support mechanism at an attractive return. The risk is largely, of course, being borne on the Canadian side by Enbridge Inc. But that deal has really unlocked a lot more discussions. And I have seen in the years since we announced that deal the business development discussions with people who want to go to new markets off of the mainline absolutely ratchet upward, because now they say they know exactly that it'll cost $3.85 to get a heavy barrel to Chicago. It'll cost about $3.15, $3.20 to get a light barrel to Chicago. Now you can talk about where else to go with the crude. And there's also the joint tolling feature of the CTS that makes it attractive to get to those new markets. So we intend to leverage that and have been doing that.
The other thing is that we do have multiple lines, and the tragic accident you heard about, maybe, in Chicago over the weekend where 2 street race, drag race cars, 5 young men, tragically, and it's just -- I'm speechless with the sadness of the waste, really, that, that is. But anyway, drag racing, crashed through one of our fences near Chicago, ran into an aboveground piece of pipe that's actually used for launching smart pigs, 2 died, 3 injured, large fire, Line 14 down until yesterday afternoon. We restarted it yesterday afternoon. But I think that it really pointed out to me the importance of the multiline flexibility of the system, because we were able to route crudes onto Line 6A, onto Line 61, which is Southern Access, even though Line 14 from Superior to Chicago was shut down unexpectedly for several days. We have only one pipe, and something goes wrong, the crude stops and it just sits there until you're back up. So the multiline flexibility, especially into the big PADD II area, is vitally important. And I think that flexibility and reliability of the system is really what shippers value.
We're just going to take a quick look at a couple of forecasts. The first is the Western Canadian basin forecast. I won't spend a lot of time on it, because new forecasts will be coming out from both CAPP and probably the Canadian National Energy Board. Enbridge's forecast is the one that's shown there. We don't publish the details of the forecast, and we are generating a new one. But it's generally been fairly consistent to slightly conservative when compared to the CAPP and the NEB forecast. But basically, what that shows is growth from today, end of 2011, of about 1.7 million barrels per day in production, largely driven by the oil sands, but the sleeper is that there's also quite a bit of oil shale play starting up in Alberta also using Bakken-type technology and things like the Duvernay Shale and other names that you will see as time goes along. But of course, it is mostly driven by oil sands projects, both SAGD, our in-situ and mining projects.
So just a huge growth picture that looks like 150,000 to 200,000 barrels per day per year of growth coming out of Western Canada. Then you overlay onto that the Bakken, and what I've got here is our forecast, which still, we peak out at the end of the decade at 1 million barrels a day, coming from 400,000 or so today, near to 500,000 today. Raymond James, PIRA, others, have generally been a little bit more bullish than we have been. And if you listen to some of the individual producers talk to their book, this chart doesn't even start to cover exactly where that line is going to end up. But our view is that there are some practical limitations, we think, to just how much 200 rigs can do week after week after week after week for years, and so our own forecast speaks of. But that is still an astounding growth picture of some of the highest-quality light crude that you can find anywhere around.
The sadness is that that crude is trading at a discount, and therefore, there has to be infrastructure and good market to make sure that the value of that crude really is realized. I mean, quality-wise, it should trade at a premium to WTI, and then, of course, it doesn't, which is why you see rail companies and companies trying to put it on the rails to get everywhere from Philadelphia to St. James, Louisiana and so on. And there is place for that. In fact, we are playing a part in that. We've decided, if you can't beat them, join them. And so therefore, we're building a very large capacity rail facility at Berthold, North Dakota that I'll show a picture a little later on.
Just in terms of differentials, just a reminder of how volatile they are, we see on the left the Brent/WTI spread, which, of course, blew out very much. PIRA is now forecasting that it's going to go close to parity by 2016. The forward curve isn't quite saying that. And quite honestly, and we get this question a lot when we keep adding tankage at Cushing, because the logical question is, if we and Plains and others keep adding tankage at Cushing, at what point is there too much tankage at Cushing? And I remember addressing that question with you last year. If anything, my view is stronger that tankage at Cushing is going to remain valuable for the long term. Why? Because there is no tight lining through Cushing. Every barrel that comes into Cushing must be marshaled in tankage. There is a delay in time, sometimes weeks, sometimes months, sometimes hours, and then it gets marshaled out on pipelines. And of course, the bottleneck is that the capacity into Cushing is far greater than the capacity out, which Seaway will help to address.
But I think that Cushing, because of the fact that the Permian production in West Texas, the Mississippi and west of Cushing there, the Bakken and others is all flooding in and pointed at Cushing. Until we can do things that go to different markets, there is going to continue to be a need for time delay. There's going to continue to be a need to hold crude, and I think that's what we're seeing at Cushing. There's a lot of interest in those who want to hold crudes, who want to blend crudes, who want to look at the opportunities that there are when you have so many streams coming into one big hub. So we'll see what happens to that differential when Seaway actually reverses the forward curve has priced, obviously, some of that in.
And then the Western Canadian heavy, WCS to WTI spread, of course, is blown out. A lot of it caused by ConocoPhillips converting their refinery at Wood River now, flipping that over physically to the heavy Canadian barrel and actually pushing an awful lot of light barrels. It is made onto our system. It's actually made the markets pretty choppy just in the last few months, and we've seen, of course, pretty hefty differentials. Again, we need to do 2 things with heavy crude. One is to fill the cokers in PADD II, ConocoPhillips at Wood River, BP at Whiting and Marathon at Detroit, and then make sure there's good access to the Gulf Coast for the heavy barrel. It really does highlight, though, both of these charts, the need for new pipeline infrastructure to move that crude.
This is a table that I think really points up the challenge that's coming up for light crude. Basically, when you take those 3 refineries in those time frames and move them to largely a diet of heavy crude coming from Canada, that will displace in that middle column 455,000 barrels a day of light oil demand out of upper PADD II from just those 3 refineries alone at a time when Canadian light production is rising a little bit, synthetic crude and so on, and Bakken crude production, of course, is rising rapidly. So that lays a challenge before us as to exactly where that light crude needs to go. Our general bias is East and South. And you say, "There's a brilliant idea. How many other points of the compass would make any sense?" But it's got to go east, it's got to go south. So there's a proclamation for the morning. But we'll dig into that a little bit more.
And I'm struggling also because I don't want to, on a webcast, reveal all of our secret-sauce thinking, and yet you would like me to do that very much. And so I'll reveal as much of our general pattern of thinking as I think is wise. There's obviously some proprietary ideas and thoughts that we have on the goal that you would not, ultimately, as investors, want us to be putting in The Wall Street Journal just today. So I'm not going to do that. But I think that trend-wise, it's important to understand that there is a real issue coming for light crude, and that's why you see it on the rail, desperately trying to get just about anyplace, Tesoro, moving it by rail to Anacortes, Washington from North Dakota. Movements to Philly, movements to St. James and so on, just always looking for tidewater markets somewhere that will allow better pricing for light oil.
But first of all, looking at Western Canada, this is the way we see the supply and disposition picture shaping up. First of all, there's a 1.7 million barrels a day of Western Canadian growth that we talked about on the left-hand side, and this is the year 2020. We see, as I said, PADD II filling up, the demand in PADD II incremental to 2011 shown on the black on the right-hand side of the chart. I'm not sure if I've got a pointer here or not. I don't know how many buttons I need to push. I don't think I've got a pointer. Anyway, the next band is an interesting one, because we've allocated about 1 million barrels a day to the Gulf Coast market of Western Canadian sedimentary production incremental to 2011. The reason we so cleverly have blended in the artistry with the color -- so I guess it would be center button.
The reason we've done something clever here is that no one knows the future of Keystone XL. We just don't. I think our bias, and we've been very clear all along, we have believed that they should get their presidential permit. We have our own commercial thoughts about that line as competitors, but we do not believe their presidential permit should have been held up for the reasons that it was and has been. I think we still are assuming in our forecasting that it will ultimately get built. They are publicly saying 2015 sometime, and I guess we wouldn't quarrel with that. However, let's recall that nobody really knows the future yet of Keystone XL, and so we've had to be a little bit circumspect when we look at exactly what's going to happen in that 1-million-barrel space. But just in terms of supply and disposition, I think it's fair that the analysis shows that about 1 million barrels a day should move by 2020 to the Gulf Coast incremental to what's moving today, which is about 100,000 barrels a day of Canadian heavy down the ExxonMobil Pegasus line that feeds off of our system in Illinois.
And then finally, again, because we do not want to be market-limited, the West Coast of Canada, that would be the Enbridge Northern Gateway Project, possibly the Kinder Morgan TMX expansion than they're talking about now. So that's what we really see post-2017 as being the flywheel that takes the remainder of that WCSB growth. So that's kind of how we're seeing it. About 1 million barrels a day post-2014 to the Gulf Coast, ramping up through the rest of the decade.
Just in terms of Bakken again, the 400,000 barrels a day growth or so from where we are today. We do see the Eastern Canadian projects that we're working on there, 2013 and beyond. PADD II, PADD III, there are refineries in Eastern PADD II that run on a diet of WTI and crudes brought up from the south that could well feed off of a Bakken barrel. And then there's always the other pipelines, Keystone XL coming out of the Bakken and a lot of people that are enthused about rail that I think are important to consider. So that's kind of how we see the Bakken shaping up just in terms of supply and disposition. And of course, that upper band on the right-hand bar there is a pretty nebulous one. Who are the other pipelines exactly, just how much rail. But I think what it tells us is there is a place for rail. There's no question that in the coming few years, until the next tranche of pipeline expansion gets built, we are going to need to have rail capability out of the Bakken which is being developed.
Okay, then, just looking at a couple of other charts with regard to the mainline system capacity. And again, I won't spend too much time here because I've talked about it a little bit. We do have the available capacity on the system. We have an expansion upstream of Superior, Wisconsin of the Alberta Clipper that we could do. And then other expansions involving other lines that already cross the border that we could do that could bring us up to an expansion without a presidential permit from today of somewhere around 1 million barrels per day of expansion capability, mostly with horsepower, all on our existing rights-of-way. And then downstream of Superior, we have some available capacity now. We have the 50,000 barrel a day Line 5 expansion that was announced last fall. And then, of course, the Southern Access line can be expanded hugely. That line is a 42-inch line from Superior, Wisconsin to Chicago or Flanagan, Illinois. That line alone fully powered could move 1.2 million barrels per day. So we are developing a horsepower expansion plan for the Southern Access line, which has been, frankly, quite lightly utilized compared to its diameter since it went into service 2 or 3 years ago.
So where is the crude going? And this is really the heart of where our thinking is. First of all, Detroit/Toledo. So Eastern Access, that has been announced. Point number one there is the Line 17 Toledo pipeline expansion to serve those 2 refineries and their growth needs there. The second I talked about is of the Line 9 reversal to Westover, Ontario, which serves the 50,000 barrel a day demand incrementally at the Imperial Oil Nanticoke Refinery. And then the third one would be Phase II, which we have not commercially developed yet. But there's certainly is a demand just in the Eastern Canadian refineries to have access to a light barrel from the Bakken or from Western Canada. The Eastern Canadian refineries in Montréal, Québec City, St. John and other places are basically all paying Brent. And they're getting squeezed in margin, because the Gulf Coast refiners, Midwest refiners, are not paying Brent, and, therefore, there is a real keen interest in seeing Line 9 reverse all the way to Montréal, maybe even reversing one of the Portland pipeline lines from Montréal down to Portland. That is yet to be developed. And of course, long run, the question I have to leave hovering in the air is what about Philadelphia? What about the Philadelphia refineries, also stuck basically paying Brent, very much squeezed, lowest refining margins in the country. What happens to those refineries? Is there a way of getting reliable light supply from the west for those refineries, or isn't there? So that whole idea of east is what's portrayed here. But everything that we're doing there is pulling, as per the bullet point at the bottom, significant incremental volume through the Lakehead System, and there is no question that Lakehead EEP is a volume story. And so we will add expansion capital as we need to, but it's really going to be all about volume. And I really see a lot more volume being pulled through the system by virtue of this Eastern Access program that we are pursuing.
To support that, specifically, Line 5 expansion of 50,000 barrels a day, which we've announced. We could possibly replace Line 6B and up its capacity to 500,000 barrels per day. That is a commercial possibility. It is not yet a certainty. But I think what's important is on the lower right, you can see that the Eastern Access program as we have announced it so far does not require EEP to invest mainline capital. It's within the band of the available capacity upstream and downstream of Superior. So that's actually a very good story in the coming year or 1.5 year, is that EEP will see increasing volumes without the need for increasing CapEx, at least for the moment, driven by the Eastern Access initiative.
Now the Gulf Coast initiative could result in an acceleration of the need for mainline capital being spent at EEP. The 3 components here are the Seaway pipeline that we talked about, the partnership with Enterprise, basically taking that line and getting it down southbound-flowing by June 1, with 150,000 barrels a day of capacity going to 400,000 barrels per day by late this year. And also building over from Freeport to Port Arthur, an 85-mile lateral to serve the heavy shipper who wants to get all the way through to Port Arthur. The second leg then that it unlocks is the Flanagan South Pipeline, which is basically a looping of the Spearhead system between Flanagan and Cushing to be in service by mid-2014. That project is proceeding. It's just in the final scoping right now. And then the third possibility, and this is not yet announced, is the twin or the looping of the Seaway line with a separate line. And in that way, we would actually probably devote one line to heavy, one line to light ex Cushing, and that makes for a pretty attractive picture when you can optimize the capacity of the Seaway 1 system by providing a heavy crude line alongside of it. So that's where we're headed with all of that. And again, the same bullet point, significant incremental volume pulled through the Lakehead System, pulled through Flanagan, which is going to become a more and more important hub.
What that will require, then, just looking at the graph after Eastern Access is that this Gulf Coast Access does start to get into the need to expand Alberta Clipper into Superior, the need to expand Southern Access. And so there is where you will see actually significant CapEx, growth CapEx at very solid rates of return.
Looking at the Bakken, that is just a tremendously fascinating place. I don't know many of you caught the piece on CNBC the other night about frac-ing. But it really was -- I thought it'd be mostly Marcellus and places like that. The whole piece, virtually, was devoted to Williston, North Dakota and, of course, the social ills associated with moving people in at the rate that have had to be moved into Williston and so on. But it is an absolutely incredible story that I know many of you follow and names that you invest in are involved there. But essentially, we've got a great footprint there and, frankly, Mark talked about a great drop-down in 2001 or '02 of this North Dakota system. But it actually started before that for Enbridge when we bought that the whole system from Hunt Oil Co. Sleepy system, I won't say sleepy employees, because some of them are very much still with us and they're not sleepy. But it was a dying, slowly attrit-ing away kind of a picture in North Dakota. None of us ever imagined that this thing called the Bakken shale or the Bakken tight sands would come up like it has. So that we did in around 1996, about the same time we bought the Saskatchewan gathering system called Producers Pipeline. And the only reason we bought the North Dakota system was we were bottlenecked in Canada on the mainline, and we needed -- we said, "Well, look, there's spare capacity galore on this system here in North Dakota. If we could buy both of these and build a 12-inch line linking the 2, we'd move excess production down from Saskatchewan here and get into the mainline at Clearbrook," which is exactly what we did. But then the rising North Dakota production caused us to idle that line a number of years, a few years ago, and now, of course, it's reversed and flowing north and that's part of what will become the big Bakken Expansion Program that's shown as the second bullet there.
So the North Dakota system has gone from throughputs when we bought it in 1996 of somewhere around 30,000, 40,000 barrels a day to 210,000 barrels a day today. Moving on the North Dakota mainline, which is now hydraulically maxed out from Berthold to Clearbrook. But now we have some excess capacity available in the system west of Berthold, which is where the growth areas are, and that's why we're building Berthold rail. It says, "Look, the barrels are going to leave by rail somehow from Western North Dakota. Somebody is going to take those barrels away by rail. Why don't we use all of our gathering infrastructure for the benefit of producers who don't have to secure their own rail arrangements in Western North Dakota and build little facilities here, there and everywhere. We'll use the pipe capacity into Berthold, where we're then bottlenecked, and build a rail export facility at Berthold." If you can't beat them, join them. And that's really what we're doing there with a high-capacity 80,000 barrel a day rail facility that said, "Look, we will participate in that." I don't think it's going to have a terribly long life, because we do intend to have another phase of expansion available with pipeline that we've shown creatively here as being a looping of that system, but it could be something different than that. But that will be our next phase of growth, is figuring out how to take the next big tranche, 100,000 to 200,000 barrels a day of pipeline capacity, and make it available to get into the mainline.
And so there's the Bakken Access Program, which is really about streamlining how crude is gathered in the Western part of the Bakken play. So about $800 million of secured capital projects are under way today, including the big Bakken Expansion Program up to Cromer, Manitoba, and more to come as you see by the dash line there.
This is the North Dakota, an artist's rendering of the North Dakota rail project. It is a unit-train-capable facility, and that's important. You have to have a unit train if you're going to go a long distance. The other kind of cargo is called a manifest cargo. A manifest cargo says, "I can't assemble batches of 75,000 barrels to put on a unit train, therefore, I need to just go with little manifest cargo." The problem is that you lose track of your cars. You say, "How in the world did that car get to Missouri, and where is it sitting on a siding someplace," because manifest cargoes rarely move together directly to market. They might take a couple of weeks or more to show up because they get stuck on site, and unit trains generally don't. Unit train is, as it implies, a very focused large movement, 75,000-barrel movement that will go directly to places like Saint James as it is today, maybe Philadelphia and so on. So the idea here is, again, to take the crude off of our mainline at Berthold and put it through this large unit train loading facility for 80,000 barrels a day of capacity. We've contracted that for a 3-year period, with generally a 3-year period, with shippers who want to do that. I said earlier I don't know if it's going to have a long life, it may well. Because quite honestly, just when you think that you've got the situation figured out and rail will go away, there's a need for more. So this facility actually could remain viable even beyond 2015 or thereabouts.
And then just looking at contract tankage. I talked a little bit about Cushing earlier. Cushing is going to remain a major staging area for crude. There's just too much production from the Permian, the Niobrara, from Canada, from the Bakken and so on pointed at Cushing. And so we are, every time we build a tank, we're the largest operator at Cushing and every time Plains builds a tank, they're the largest operator at Cushing. We are side-by-side across the road and really the 2 biggest operators there at Cushing. But I think that as the picture unfolds, this fear of tanks going begging at the end of their contract periods is actually fading away. And that's the question. If you have a 5- to 7-year commitment period, what happens then? Will anybody want tanks at Cushing? Will it be so efficiently piped that nobody will need to store crude at Cushing? I think the answer to that more firmly is becoming no. There actually is going to continue to be the need for arbitrage and time value of storing crude at Cushing.
Just as I get close to wrapping up here, I wanted to show a picture on the safety in the pipeline integrity side, because it really is a remarkable story. This is kind of a typical smart pig. This would be, that one looks to me like a corrosion, high-resolution kind of corrosion, but could be a crack tool. But basically, they are all in some cases nearly as long as this room is wide, and that's why in some pipelines, especially a number of gas pipelines in the U.S., you can't pig -- a non-pig-able line means that the radii of the bends is too tight to pass a long chain -- a long train pig like that. But basically they're collecting data. So the tool gives you a GPS location and a clocked position on the pipe that this is where you have a feature that needs to be examined. And what I wanted to give you visual appreciation for is that's one indication, right here, and we dug 1,764 of those holes in 2011. I think that when the Ripley's Believe It or Not! people get done dealing with people who've grown their fingernails out 8 feet, they're going to come and they're going to say, "Believe it or not, you dug 1,764" -- what a boring Ripley's edition that's going be. But, "You dug 1,764 of these." That, I think, in my 30-years-plus in the industry, I've ever seen anything like it. I have never seen a big program that resulted in that. That's to investigate one feature, and 2011 was a remarkable year. 2012 will be about the same, and then I think we're going to start seeing it drift off, because we've already dug the highest-priority features. Now we're moving down the priority spectrum.
We also did 138 of these smart pig runs in the year 2011. And I firmly believe that's never been done in the history of the world. I do not believe I have ever heard of a company that ran anywhere near that number of smart pigs. And so, but that is the determination we have to say, we're going to run every possible line that we, on our analysis, believe needs to be run with corrosion and high-resolution crack detection, and we're going to have an aggressive program to just get right over the hump. And that's we've been up to. We also have an organizational commitment and a commitment to our board to be best in class in terms of leadership and pipeline integrity, safety and also in leak detection.
So the final takeaways are really just what we had at the beginning. Focusing on making sure that we have solid operations, an excellent safety record, a pipeline integrity program that is very aggressive, looking at the asset base and leveraging it as best we possibly can, leveraging the benefits of the CTS, the Competitive Toll Settlement, on the mainline and really taking again a look at understanding the supply-demand fundamentals and really using it to the benefit of Enbridge investors, EEP investors and so on.
So that concludes everything that I had prepared and I see that we're still green. So there should be plenty of time for questions. Anything that you have.
A quick question, or maybe not so quick, regarding the train facility. Just curious, if you build it, are you building it with the quasi-planned expectation of obsolescence in 3 or 4 years? I'm just curious, what kind of economics would drive such a project? Do you get all your capital plus a return out over that 3-year period? And because it's, again, quasi-planned, it's not going to be there forever. Does that revenue and profit basically not factor into distribution growth computation because you really can't count on it long term?
Stephen John Wuori
Okay, that's a great question. I think I'll have Mark address the last part of it around the distribution and how it plays into it. But I think there's 2 ways of looking at it. One is the standalone economics of the Bakken rail facility, and we look at those and certainly when we present to our board, that's exactly what we have to look at as a rock-bottom here is what the return is going to be. But then you also can factor in the positive effect of using the extra pipeline capacity from Western North Dakota that every one of those barrels is going to be moved on that would have otherwise disappeared from our system, never to be seen on to somebody else's rail facility. So we do look at that. Generally with Bakken, which is a first for us, we've never built a rail facility before in our history, and it's just that our analysis really led us to the conclusion that we could either watch the volumes disappear or we could actually gather them in and participate and touch those barrels. Our theory is that a barrel is a sticky barrel. If it's with you, it's likely to stay with you. Because of the ease for the producers who want to get out of North Dakota, the easier it is for them on the logistics side of getting to the right market, the more likely they're going to focus on their drilling program rather than worrying about how to do the next rail deal. So I think, yes, we are looking for a solid rate of return based on the 3-year commitments. I don't believe all the capital is returned in the 3 years, but a solid rate of return during that period. We also have handicapped a view of what the future would likely look like post-2015 or into 2016 and beyond. And we also quite honestly have had some discussions about alternate uses for such a large rail loading facility. Grain, for example, if there were handlers that wish to do such a thing coming out of North Dakota after 2015. So I think we're comfortable that the amount of capital that we're putting in is relatively limited. The return is solid. The overall return when you consider the use of the pipeline is a good one. Strategically, it is the right move to make. And our hope, just to be blunt, to give you the roadmap, is that these shippers will bridge onto our next pipeline solution. In other words, we don't ever intend to lose those rail shippers. We intend to bridge them onto a pipe solution for the 2015, '16, '17 timeframe. But Mark, you might want to just comment on the distribution side.
Mark Andrew Maki
Yes, I think, Steve, you covered that pretty well with your response. Certainly, when we look at how we plan for distributions in the future, we look at the -- asset by asset, we'll look at where the casual is expected to be, some are going up, some ratcheted down. I mean, typically when we do a project, we make an assumption around re-contracting and it involves a discounting of rates. A good example, an easy one to understand, is Cushing tankage. When we build a tank at Cushing, we'll have a, say, a 7-year contract. On year 8 it re-contracts. We'll assume it does so at a rate lower than what it was before. Very similar assumption we're going to build around this asset. So yes, it's factored into how we look at distributions in the future, but it would include a discount as we plan out for the future years.
[indiscernible] pipeline capacity out of Bakken.
Stephen John Wuori
Well, I'd like to think we've been aggressive. We put together the Bakken Expansion Program, which in its totality is 145,000 barrels a day when we did it. And that was -- at the time, that appeared to be adequate for some time to come. The need now, of course, is much greater. I think that the thing that we have to be cognizant of is, it's one thing to build a rail facility that may or may not be used for 10 or 15 years. It's another thing to put a pipe in the ground that may or may not be used. And so actually, part of the cultural issue is getting producers, sometimes small ones, who are not accustomed to making pipe commitments and taking them on to their balance sheet to make commitments which are necessary to get a solid economic project. And we were able to do that on the BEP, the Bakken Expansion Program. That was, I think, good, because we did get shippers who haven't ever made a pipe commitment to make that. But that's a shift for them. They're not just accustomed, many times, especially U.S. Mid-Continent producers, are not used to making long-term commitments on pipe. And it just looks funny on their balance sheet to them, and they go, "Why in the world would I do that?" But that's going to be the trick going forward also with the next wave of pipe growth is it's going to have to be underpinned by a certain level of long-term contracts. And by that, I mean at least 10 year.
Okay. And just 2 other quick ones. Number one, how much -- what would the tariff look like to get it into the Gulf, the sweets, all the way into the Gulf if that's where you want to go? And/or what does it look like to get it to Chicago, and how does that compare to current basis differentials? And then, second of all, on the mainline, you talked about increasing horsepower. What can we expect in terms of CapEx dollars to ramp capacity up there?
Stephen John Wuori
Okay. I don't think we're ready to talk CapEx just yet until we get the program more defined commercially. We'll, I think, let that go to announcement, but it will be significant just because even though there's not new pipe involved, there is a lot of pump station horsepower involved. Generally, just in round numbers, you can -- you should be able, just looking first at a Canadian heavy barrel, you should be able to land that barrel in the Houston, Port Arthur market for about $7 a barrel, and that depends -- from Canada, and that depends on exactly what term, what volume, a lot of things. So if you give me some grace around that number, that's probably about right. Rail, to do the same thing. There is some rail. Heavy crude moving out of Alberta right now is astronomical compared to that, but not when you compare it to the differential. So rail might be paying $20, $18 a barrel to move a Western Canadian barrel down to the Gulf Coast in some cases, especially on a non-unit-train basis, but the differential is greater than that, and so there is the opportunity. Coming out of the Bakken, it will be a little bit shrunken from that, both of those numbers. There, you're probably talking pipe at about $5 and rail at about $10 to $11, just, again, in round numbers. So when the differential is $25, just about anything works. When the differential tightens in, I think the rail economics become pretty challenged.
Okay, I'm not sure who was, I think Curt's got the mic, then we'll go Eve. Eve's got a mic, too. Okay. So Curt.
Curt N. Launer - Deutsche Bank AG, Research Division
I wanted to ask you to extend your comment a little bit relative to Cushing in the topic of blending. It seems like blending capacity is going to become more dear over the next several years as the lighter crudes end up there more so than the heavy, and what are the implications both for Cushing, the blending capacity and moving that oil through Seaway onto the Gulf Coast?
Stephen John Wuori
Yes, I think that's the opportunity that Cushing is going to offer more and more. With more streams coming into Cushing, there is going to be a need for blending and, frankly, an opportunity to take advantage of that just because there will be certain streams that can be blended down or blended up. And I think that we are seeing that a number of the people who want tanks from us on a contract basis are planning to do exactly that. We'll do some of our own, not at EEP, but through our own marketing activities. We'll do some of our own at Cushing through our energy marketing group. But yes, there is, and, of course, Plains is a splendid blending company. They know a lot about blending as well, and I'm sure that that's in their business model. But you're right on, Curt, that there will be a lot of opportunities to blend up to target the right refineries, the right markets. Sometimes there will be streams coming in that can be blended down and still meet a good spec in price. That is going to happen. And maybe that's a way of also saying that the possibility that Cushing is going to be this tumbleweed-strewn windy place with nothing going on 7 or 8 years from now is just not going to happen. It is, as the sign so boldly implies when you drive into town from every direction, the pipeline crossroads of the world. And I think more and more we believe it's going to remain so. And blending is going to be a big part of that.
Curt N. Launer - Deutsche Bank AG, Research Division
If I could just do one follow-up relative to the Bakken. Most of the attention in the last few weeks has been on Clearbrook and the differential blowing out there. It seems like many of the things that you're talking about will make things worse at Clearbrook rather than better any time soon?
Stephen John Wuori
Yes, and, that's right, and therefore, our solution has to go to Superior. Our solution cannot stop at Clearbrook. And just because the mainline is going to become bottlenecked at Clearbrook specifically. So when I talk upstream of Superior and downstream of Superior, I think what it means almost inevitably is that the solution, the next pipe solution is going to have to also address Superior, whether that is get to Clearbrook and just expand the mainline or whether there's something else. But yes, you're absolutely right. Clearbrook cannot become the bottleneck for the next tranche. It has to get to Superior. And from Superior, of course, then you have Line 5, take it across in light crude to the Ontario market. You have Line 14, which is basically a light crude line that shoots to the south. You have 6A, which is both light and heavy, and then you have the big Southern Access line which is light and heavy. So there'll be a lot of ways out of town once it's in Superior. That is something we're very focused on, is where the bottleneck is going to be.
Two questions. The first question is, could you talk about the shipper thinking coming out of Canada in terms of if Keystone gets built or not built? And how does that flow into your ability to expand and get the crude down to the Gulf or not down to the Gulf?
Stephen John Wuori
Yes. Well, that certainly is a question that's on a lot of people's minds. I would say that based on the results of our 2 open seasons, there clearly is some view that there should be an alternative to Keystone XL in terms of moving some barrels in a different direction. I think generally, though, the feeling of the Canadian-producing community is that XL is going to get built, and it will get built by sometime in 2015. They clearly have some contracts that have remained with them in spite of the expiry of some timelines associated with those contracts. And so it appears to us that that's what's going to happen. And I think that's the view of the Canadian shipping community is that I don't think anyone is really panicked that it's not going to get built. And of course, what we've done with our mainline capacity and then our ex Flanagan project to the Gulf Coast helps to allay the fear, frankly, that the world might end if Keystone XL doesn't get built.
And as a follow-up to that and also in the spirit of Noah's question before, when you made the acquisition of 50% of Seaway from Conoco, I think it was $1.2 billion, what was thinking in terms of expectation of what ultimately happens? Was the thinking that if we get 150,000 barrels a day, economics work, we need to get that 400,000 barrels a day to make the economics work. Could you sort of elaborate on the thinking there in terms of the profitability of the project?
Stephen John Wuori
I can. That's pretty much an Inc. question rather than an EEP question, because that's an Inc. project. But I think we saw the opportunity, and by the way, the 150,000 is just simply hydraulics. What we can do by June 1 in terms of capacity by the station we can get put in at Cushing in order to do that and then more fully power it up to the 400,000 for late in the year. I think our view is that we have contracts on that line that provide us with acceptable economics, keeping in mind that our economics and Enterprise's on that particular piece are different because they didn't pay $1.15 billion for half of it because they already had it and we did. But I think that's what our whole acquisition was underpinned on, was the idea that we were going to get as Enbridge Inc. a very much acceptable return, paying Conoco what we did for that line. And also, taking, frankly, a point of view beyond the contracts as to what the utilization of the Seaway line is likely to look like, just because of the world being very much attuned to wait for it and say this is what has to happen. And then the other piece that goes into that is how will we toll it in an environment like that. So I think we saw that under a conservative tolling philosophy and under a contract that we have achieved through the open seasons, we see attractive economics that could get better depending on how things play out. Our expectation is, though, the line is full, and it will be full, I think, basically from day one.
Just a couple of questions just kind of following on Curt's question. You have a chart here on the Bakken supply dispositions and showing I guess about 400,000 barrels of incremental supply. So I'm curious, if, and I assume or presume that's premised on the forecast numbers that you put up on an earlier slide. And so I'm just thinking what happens if the much stronger forecast come in? Would you just add to the projects you've got planned? Or would there be timing issues with regards to that? That kind of thing?
Stephen John Wuori
I think the swing on that will be what size of pipe will our next pipe be? That next solution that I talked about in the dash line, however we're going to do that. The question is, is it a 20-inch line, is it a 24-inch line, what is it? And I think that's the swing on the pipeline side is exactly what capacity line do we build out of the Bakken? Is the next tranche going to be 200,000 of capacity or 400,000? And that we're trying to triangulate around long before we have to lock in on the design. That to me is the big question.
And I guess dovetailing along that, I mean, there's different overall U.S. forecast. I mean, obviously, a lot of that comes into your area of the world. But you're seeing, I guess, EIA, they're looking at over the next 5 to 10 years maybe going to 6.5 million, 6.8 million barrels a day. And then you've seen other forecasts being as high as 9 million barrels a day of U.S. production. And I'm just curious, your thought process if were on a much higher trajectory, is that going to come back to this sizing issue that you just mentioned?
Stephen John Wuori
I think it will. Because by definition, that crude will have to access U.S. markets. It doesn't make sense for it to do anything else. And quite honestly, and this is just talking here between you, I, and however many people are on the webcast, but quite honestly, the higher the forecast goes, the greater the push to get it into the Philadelphia market, as an example. Where there isn't reliable supply into the Philadelphia refining market now. But the more domestic production that there is going to be, say from the Bakken, maybe from the Niobrara, maybe from the Utica shales in Ohio, that really shouldn't just dump down to the south to try to compete with the Eagle Ford and the Permian and the other barrels. I think there could be an inevitably more push to the east. But in the Bakken specifically, I think absolutely, all systems appear to be go. It's just that we do not want to build on our next tranche of expansion, overbuild and have capital stranded at some point in time. It's hard to conjure that up right now, but that could happen. But that is -- our pipe-sizing decision will be very critical in that whole equation. It really will. And then also making sure that, that crude isn't market-limited, whether it's Clearbrook or pipe-limited, either one. So it all has to work together, and the development of the markets to me is as important as development of the capacity to get it out of the Bakken, because otherwise you'd see what's happening today, and that is that the rail is kind of taking it to wherever it can go. Just to access, basically to try to get to tidewater and get the better pricing.
And then the last question is kind of dovetailing on Eve's question, so just to clarify. So If Keystone isn't built, okay, then there's enough -- I take it your answer was there's enough capacity on your pipelines and your right-of-ways that Enbridge could nonetheless handle the volumes necessary to bring them into the U.S..
Stephen John Wuori
Yes, I want to be careful about that. It's obviously a pretty politically charged environment to make a statement like that or to confirm it. So I don't think I should do that. We'll go back to the slide that noted that between 800,000 barrels a day and 1 million barrels a day of capacity is available on our system based on horsepower expansions of Alberta Clipper and Southern Access and so on. So there is a lot of capacity available. I wouldn't want to reflect on Keystone XL. I think it's kind has a life of its own right now in Washington, and I'm not living that life.
Winfried Fruehauf - National Bank Financial, Inc., Research Division
I have a two-part question. The first one is there are 2 unnamed pipeline companies vying for access to the Gulf Coast market. If the first one reaches the Gulf Coast by 2014, is there a first-mover advantage in the sense that it might delay the need for the second pipeline? That's the first one.
Stephen John Wuori
And Winfried, just to clarify, are you talking between Cushing and the Gulf Coast?
Winfried Fruehauf - National Bank Financial, Inc., Research Division
No, just anywhere from Canada to the Gulf Coast.
Stephen John Wuori
Oh, okay, okay. That's hard to say. That, I think, will depend on a couple of factors, one being the supply picture and the ramp-up of supply. I think we will be taking the contacted volumes that we have gotten over the 2 open seasons now and building those into this project. The presumption is that those will flow and therefore will not be available to any other pipeline system. Likewise, the Keystone XL does have contracts for a certain amount of its capacity. I think our assumption is that if the system is built by 2015, those barrels will flow at that time and therefore won't be available to come to the Enbridge system. I think there is an advantage in speed that we have because we're working on existing rights of way. There's no greenfields right of way at all. We're working on existing corridors that we're very familiar with, and I think that we continue to move ahead on a pretty aggressive timeline with all of that. But I think it has to do with where the contracted barrels are, and we understand that there are some contracted barrels on Keystone XL that we will be unlikely to see in our system unless it is, frankly, not built at all. But that's not a scenario that our planning incorporates.
Winfried Fruehauf - National Bank Financial, Inc., Research Division
The second question is, there's another company that is proposing to build a pipeline from Alberta to the West Coast in Canada. Suppose that pipeline gets built, and suppose the economics of exporting Canadian crude oil to East Asia are superior to those exporting to the United States. Might that result in some redundant pipeline capacity out of Canada to the United States?
Stephen John Wuori
It's a great question, Winfried. I think that ever since we've talked about the Northern Gateway Pipeline concept, that question is in the air and, frankly, needs to be in the air. However, since we started working on Gateway 8 or 10 years ago, the production profile has only gotten larger and larger and larger, and our thesis is that the Northern Gateway line will not carry oil that otherwise would have been destined to the U.S., but rather it will carry crude that otherwise would have stayed in the ground for lack of solid production economics. And so the presence of another system, the Kinder Morgan Trans Mountain system -- and by the way, let me just state, they do a great job. Kinder Morgan does a great job with Trans Mountain of moving what they can off of the dock at Vancouver, moving most of the cargoes to California, but occasionally, one makes its way across to Asia. We're challenged to understand how you could go from, say, 85,000 barrels a day on average off the dock to many, many times that through the Port of Vancouver, but that's a question that they will be asked and will be addressing. I think it gets back down to the contracted situation. Northern Gateway is now fully contracted for its capacity of 500,000 barrels a day, the capacity will be 525,000. So there'll be 25,000 for walk-up shippers. But all of the rest has already been contracted. And so what the Trans Mountain system will now achieve by way of committed contracts for an expansion of Trans Mountain is yet to be determined. I understand they intend to make some statements about that maybe in the summer. So I think, though, what you're really getting at is, is there a potential to cannibalize movements to the U.S. by virtue of too much capacity going off the West Coast of Canada? I don't really see that happening. I think the U.S. always has been, always will be the most important market for Canadian crude. And when you look at the growth picture of 1.7 million barrels a day out of Western Canada, even a Gateway at 500,000 or a TMX at 400,000 or whatever still does not overwhelm that forecast, even assuming that all of the current movements to the U.S. continue. So I think we always look at that cannibalization question. But I really don't see that emerging right now.
Winfried Fruehauf - National Bank Financial, Inc., Research Division
[indiscernible] export to Asia produce superior economics relative to moving Canadian crude oil to the Gulf Coast? And I'm implying that maybe there's a need for an expansion of that pipeline to the West Coast. If that were to happen, could there be a cannibalization?
Stephen John Wuori
Yes, yes. And I think -- well, what drives the need for a West Coast outlet for Canadian crude is the fact that the U.S. market is stagnant. Demand is flat to declining. Domestic production is rising. Every Canadian barrel is now competing with domestic U.S. crudes. More capacity off the West Coast into what is undeniably a vast Asian market would perhaps produce economics that would be superior. But I guess I have a hard time, Winfried, conjuring up a scenario in which you would have over 1 million barrels a day, let's say, moving off the West Coast of Canada such that the U.S. market goes begging. There are refiner-supplier contracts of long standing in place. There are large cokers in PADD II that will be filled. And so I really don't see a scenario where cannibalization is going to be a major factor. There's too many arrangements. There's too many refineries who will access the supply from the oil sands, some of whom have tailored their plants to do so, to just see that happen, even though on a macro basis, you could imagine that happening. Certainly, the Asian market is a vast one. And it's a an attractive one. But I don't see all of the oil sands crude suddenly funneling off or a huge portion of it funneling off to the west. The way I see it is that Northern Gateway, perhaps Trans Mountain would provide an outlet and lift the value of oil barrels but not become the primary routing. How bad are we? This red light is just getting to me. Yes?
My question related to the operational aspect of things. The OpEx [indiscernible] 2012 guidance implies seems to have ticked up quite a bit. I was wondering, how do you think about that medium to long term, especially as the new projects on the liquids side come up?
Stephen John Wuori
Yes, and I think you're primarily referring to integrity costs, OpEx rising? Yes, well, between the U.S. and Canada, talking both Enbridge and Enbridge Energy Partners, we were traditionally spending about $150 million a year in integrity cost management, which is a large number, I might add, in the industry. For 2012, that's $475 million between the 2; 2011, similar. So there's no doubt that there's been a ratchet up as we have very aggressively attacked the integrity management all across the system. I see that tapering off, and I don't know, Mark, if we want to talk a run rate at this time, but certainly, I don't see that remaining at the $475 million, let's say half of being EEP, for the long term. I think we're going to see that maybe not revert to a traditional $75 million number, but certainly not $200-plus million for a run rate. But I think we'd be better off to give guidance on that at the right times going forward. I think you're going to see 2011 was high, 2012 high, 2013 it's going to start coming off. Okay, other -- all right, good. Thanks very much.
Let's all go ahead and break for 10 minutes and reconvene at 10:55.
Hello. If I can kindly ask everyone to take their seats, we'll get -- we'll reconvene shortly.
John A. Loiacono
Okay, my name is John Loiacono, I'm the Commercial Officer for the gas gathering and processing asset for EEP. Our key messages today that I believe take -- that you take with you, once again, to stress operational excellence, safety and then system integrity are our top priorities and form the foundation of which we would grow our business. We have a strategic -- we're going to spend a lot of time on how strategically positioned our asset base is. Our premier position in the Granite Wash, the liquid-rich play that's going on there, participation in natural gas, NGL value chain and then recent investments that we've announced there and then the importance of our execution on our growth projects within that line of business.
First, we're going to start with the natural gas fundamentals. Shale gas has taken a much -- significant prominence in the domestic gas supply picture, currently running 33% of the U.S. gas supply and projected to grow at over 40% -- I'm sorry, 55% by 2035. Of course, that's being driven by the technological advances that have occurred in recent years. There's the horizontal drilling aspect, there's the economies of scale of multipad drilling and, of course, the fracturing technique, and all this has led to the significant growth that's gone on.
And in recent months, or recent years, there's been a significant focus and shift from shale gas from the dry gas play to the rich gas plays to the attractive processing economic and frac spreads that go along with it. Another significant dynamic that is changing in the sector of the business is we don't foresee a significant need for large-scale transmission pipes as most of that infrastructure already exists, but there'll be a significant gathering infrastructure that will be need to be built to get this shale gas market.
Here's a couple indicative price forecasts. We also are showing the Enbridge forecast here along with EIA, and what you'll see is we foresee a robust demand growth for natural gas in the future, and that's why you see the prices pick up as they do. This demand -- we're going to talk a bit more where this demand growth will come from. But the other thing to note from this is that high gas price somewhat counteracts the effect of processing margins, because that high gas price kind of -- we have a more conservative view than PIRA or the EIA would have relative to processing economics because that high gas price forecast is out there.
So I think our ratios run -- begin at roughly 626 or so in the early years for the "crude oil to gas" ratio. Then by the end of that time frame, we're roughly a 21. Versus EIA, the tailwind is more of a 24. So we view this as a much more conservative view on that side of the business than what the EIA would forecast. Another thing to note, our price forecast are a blend of the forward curve and [indiscernible] and PIRA. So we kind of take a middle-of-the-road approach relative to the EIA forecast.
Now the demand fundamentals for natural gas are also quite strong. The growth in gas consumption is going to come from, we see, from 3 main places. First of all, this theme is a much more reliable source of supply with all this advent of shale the gas coming into play. In addition, gas being the fuel of choice for power generation, for electric power generation and we could see that beginning to grow. And then most importantly, coal displacements and retirements that are on the horizon will also, we thought, would be absorbed [ph] a significant amount that will be absorbed by natural gas. So also a -- we think, a very high likelihood that natural gas will get more prominence in the potential U.S. energy policy as a clean-burning fossil fuel, and it should also get that support as well.
As I mentioned a minute ago, electric generation will be the primary driver for natural gas growth in the U.S. We see currently where the market share is roughly 24% for natural gas, should grow to 27% by 2031. This will be at the expense of coal, as we mentioned, and over the next 20 years, we expect coal to drop from roughly 45% the most -- 49% in recent years. So lower level of roughly 40% by 2035. And of course, the other thing to note, we see no nuclear generation being added beyond 2012. And the other category over there on the far right is solar, hydro and nuke.
I'd like to spend a little bit of time here talking about the increased fundamentals for NGL supplies. Given all these recent technological advances in the horizontal drilling and the shale gas and the migration of more rigs to the NGL-rich plays, supply of natural NGL liquids is projected to grow to 3 million barrels a day by the EIA by the -- roughly over the next 25 years. Current levels are roughly about 2.2 million barrels a day, and so that's significant growth. And that added supply along with the robust demand growth anticipated for LPG products over the next 25 years on the globe makes it a very nice, attractive picture for this supply growth that we're going to see in the U.S.
The other thing -- the chemical complex in the Gulf Coast is also going through a lot of expansions, and it's a very stable region, and there's a very stable source of supply for the ethylene products that are generated. And so the U.S. and the petrochemical complex is very positively situated as a low-cost provider of ethylene products due to the quantity of supply, the location relative to the other geopolitical risks say, Asian -- I'm sorry, the Middle East and also just the low-natural gas prices consumed to make the a product. So those things all kind of go together to make a very attractive position for the long term for natural gas liquids supply and demand.
Okay, this next chart kind of shows the relative economics of all the different natural gas plays or some of the more significant natural gas plays going on in the U.S. and what is -- well, this is developed by Wood Mackenzie to show roughly what a 10% internal rate of return would be at a breakeven price. So first thing you'll note on the chart is the different colored bars, and the green bars indicate the liquids-rich plays, and then the blue bars are the dry gas plays. There's been a significant shift, as I mentioned, in drilling towards the more rich plays. So the box, the yellow boxes indicates the rig counts in these different regions. And you can see that the large percentage of rigs are running in these rich-shale plays like the Granite Wash, the Marcellus, the Eagle Ford and then even some of the other rich plays that are ongoing. We're located in the Granite Wash and the Barnett Shale. We're in both the rich window as well as the dry gas window there. We're also -- you'll see the Haynesville Shale, the Bossier shale and then the Cotton Valley shale, which is -- or the Cotton Valley sand in East Texas, which is also a processable play.
Okay, over the last few years, there's been a significant drop in gas rigs that have been running. It's roughly has dropped roughly from 690 rigs on the dry side. Dry rigs then projected to be the 320 rigs in 2012. But at the same time this shift has occurred, the rich gas rigs have been running roughly in 2009 at 200, more than double to be about 400 rigs that are running now from the prior forecast. So what this kind of tell you is there has been a big shift, and everybody is shifting because the economics are much more attractive with the economies of scale, the NGL uplift and where there's rich gas, there's usually condensate so for oil as you would determine [ph]. So their economics are just very attractive. We're going to talk about that more in a second here.
The other thing to note, there's been even a more dramatic shift in horizontal rigs. The horizontal rigs now make up about 61% of all the rigs that are running in the U.S., and that's up 50% from what they were running levels in 2009. So what that's done -- what you don't see from that is that they've also gotten much faster at drilling these wells. The time to complete has dropped significantly from where they started when the horizontal plays really started roughly 4 to 5 years ago, and the Barnett Shale has been longer than that. But you've seen a steady progression of being able to complete these wells and drill them faster and faster as time goes on.
Okay, our natural gas strategy addresses the competitive landscape that we see in the midstream space, and we look to leverage off of our existing asset positions and grow our business. First and foremost, operational excellence, system integrity and safety are the key foundations that we will form, because we don't feel without being able to be safe and to be good operators, we can't grow our asset base. So that's first and foremost in our minds, and we focus on that quite a bit. We're looking to also expand our asset base. We have a premier position in the Granite Wash, we have a significant footprint, and we'll talk about that some more. We've expanded our processing capacity via our acquisition we did over in -- roughly 2 years ago with the Elk City asset, we're building -- we're in the process of finishing up processing capacity buildout, starting additional buildout, we'll talk about it in a moment. We have also initiated condensate handling facilities with our investment in Texas expressing geo pipeline, and we're also looking to grow that investment, along coming up with fractionation ownership via either a contractual ownership joint venture or partnership or actual ownership.
We also look to leverage off of all of our asset positions and do acquisitions, similar to what we did with the Elk City assets and the Panhandle and some other smaller ones we really don't talk about in the public, they're not really large. But we also look to always leverage off of where we're at in and aggregate more. And we're also looking for strategic acquisitions while maintaining our financial discipline in different regions where we don't have assets today.
If you haven't this before, this a bit more of a broad view of where our assets are located. You'll see we're predominately a Texas-based company and to some extent, in Oklahoma. Texas is a good place to run business, I mean, as far as very friendly in terms of the people understand each other, you work with your landowners, and your constituents understand the business. And we're located in some of the best basins there are for shale gas drilling. The East Texas, of course, has multiple plays. It has the largest geographic footprint of all of our assets. The Bossier shale, the Bossier sands, the East Texas Haynesville Shale play that has been ongoing and also some of the more conventional plays have been around for a long time. The Fort Worth basin, which is where the Barnett Shale has been so active, and, of course, the Granite Wash, which is really isn't a shale, it's more of a tight sand, but still has similar features to what the shales have. So we're competitively positioned in all this plays. We have about roughly 2 Bcf a day of active processing capacity and north of about 1 Bcf a day, 1.2 Bcf a day of treating capacity. And most of that treating capacity is located in East Texas.
This graph kind of gives you a little bit of a snapshot of how we've grown our business and optimized our assets over the last number of years. We've grown our NGL production. Our natural gas has grown from 1.5 Bcf a day back in 2005 and projected to grow roughly north of 2.5 Bcf a day in 2012. We've had a steady history of growth, and roughly the largest part of this growth is projected to come from our Anadarko system, in that basin over the next year. We are forecasting roughly a 20-plus-percent increase in our NGL production over the next -- for 2012. We roughly had 87,000 barrels a day of production in 2011, and we're forecasting to be roughly 107,000 barrels for 2012. Most of that is going to come from the Anadarko Basin, as I mentioned, as we the gas volume growth as well as the NGL growth.
In 2011, we also completed some upgrades at 2 of our plants that we parked on the Elk City assets, our 9-mile plant and our Sweetwater plant, and what we did -- those plants were really not situated to handle the type of gas that's being discovered in the region. So basically, we refitted them to be able to take our higher-GPM gas, roughly the 5 GPM type of gas we're seeing in the area. In addition, we completed our Allison plant buildout, roughly -- we basically became -- it became online in late 2011, and we're still finishing up some odds and ends, but it's prepared and ready to go. And right now, we're waiting on third-party NGL takeaway capacity, which should be up, we believe, within the next 30 days.
As we mentioned, our Anadarko system is competitively positioned in the Granite Wash play. You will not see anybody, I believe, that has the same breadth of assets as we do, almost 3,000 miles of pipe in the area. We have one treater plant that doesn't really move a lot of gas because most of this gas is all processable gas. And we also have 11 active processing plants. Based on that equation, almost 1 Bcf a day. That is with the Allison plant only, it does not include the Ajax plant. Ajax is under construction, it's for another 150 million a day and we've made roughly, I think we're seeing roughly in service by mid-2013 is what we're kind of looking at, maybe early.
And the other thing you'll see here, we've kind of shown the rig count. It's really roughly running about 86 rigs, it's nice enough [ph] to change what we've seen. We expect additional rigs to be coming in the area based on what the customer telling us, and we're going to explain to you why and how much value there really is in pursuing this play from a production side in just a moment.
In addition, as we announced, I believe, yesterday or recently, our participation in the Texas Express pipeline also allows us to participate in the NGL transportation value chain, and we'll talk about that more in a moment as well.
Okay, this chart on the left kind of shows only our Anadarko Basin processing capacity as we built it out in 2009 and where we're projecting it to go. So the red bar shows our processing capacity in terms of [indiscernible] gas capacity. So we're roughly anticipating to be at rough -- just north of 1.2 Bcf a day of processing capacity in the region. And our NGL production capacity roughly will be about 85,000 barrels a day once Ajax is built out. So we've increased that capacity over the years significantly from 2009 when roughly 20,000 -- we were at 30,000 barrels a day, or just north of that. For 2010, on this chart, indicates the acquisition of Elk City, and it was only -- that was on a full year basis. And then 2011 was the enhancements we made at the facilities and a small, nominal amount from Ajax -- or Allison construction. 2012 is the increase related to a full year of the Allison plant being online and as well as the upgrades at 9 miles and Sweetwater and then 2013 as the increase comes from the Ajax plant.
Now on the right-hand side, and probably one of the more important slides that I think that's in here, really explains why people are drilling for this in this thicker play. What it does it breaks down the component values of what a producer would get at the wellhead if there was no other deductions or royalties or things like that. So the residue gas value today, although we use $2.75, I think, in this chart. I think today is trading at roughly $2.30 on the NYMEX. The NGL portion there is the processing upgrade. The 100% of the NGL processing upgrade on a $1 per Mcf basis at the wellhead. And then the condensate, and this would be approximate, once again, for the Granite Wash play, another $3 on top of that. So on a dollar-per-Mcf basis, you guys can realize roughly $10.50 before royalties, before taxes, before any midstream deduct, operating costs, things like that. So it gives you a rough idea of the total value inherent in that well stream and why they're continuing to drill it. And this would be a similar chart depending on what your net back prices are for NGLs and things like that, whether you're in the Marcellus or Eagle Ford, and the GPM content would vary. But it's directionally accurate for rich processing plays.
As I said, recently, we announced our investment Texas Express pipeline, and this is our first step in becoming a participant in NGL value chain. And we were able to basically become a participant in this because of our position in the Granite Wash and the amount of production that we have in the area. We are also very pleased to be partnered with 2 very reputable leaders in the energy space, namely Enterprise and Anadarko Petroleum. And so Enterprise is going to operate and construct the main line, which is -- I want to say is like 580 miles and we will -- well, that 580 miles, I believe, includes the gathering lines. But we're going to operate and build the gathering lines shown in red in the Eagle Ford, in the Granite Wash region as well as the -- we'll build infrastructure in our Barnett Shale area as well.
The aspects of this investment, which are, I think, even more so than some of the other announced projects, is it can actually store liquids from the Rockies via our partnership with Enterprise, but from the Rockies, from the Permian, from the Mid-Continent and as well as South Texas. So we think this can be a very attractive way for people to move liquids and, for us, to be able to participate in this new line of business has been very exciting.
Okay, our North Texas position has actually been able to, I'll say, enjoy relative stability, even in the state of declining rig count. And the reason why is because really we're only -- about 1/3 of our throughput comes from dry gas window of the Barnett Shale, about 2/3 of it, and that's approximate, comes from the more rich, processable area in the plays. So that's one of the reason why we've been having more stable production growth. The rig count has dropped, and a lot of those rigs that have left were the lean gas side, more in the Eastern side of the play. And we're actually seeing continued drilling from well, I call it, I don't want to call it more -- there are still some Barnett activity going on, but it's more of the oily stuff that's in the area. And along with that oil, it comes with casing head gas that has a high liquid content. So we're still expecting to stay fairly stable in the area. We have roughly 400 million a day of processing capacity and some active wells. And that footprint is very extensive. It's gotten in the area, we've got a lot of compression, a lot of pipe in the area. So we're pretty well poised for things as they go on, and we're expecting and hearing from people that this oil -- some of these oil plays that are going on will continue to be pursued.
East Texas, of course, is our largest footprint in terms of aerial extent. It's -- there are a lot of different formations that are associated with the areas, some rich, some dry. The more historical ones that people are familiar with that where a lot went on was the Bossier sands, the tight sands, that went on for a number of years, and there's still a lot of activity going on in that. In addition, in the recent last, roughly, 3 to 4 years, the Haynesville shale was so prominent in the area, and a lot of that did occur in East Texas as well. And we've built some infrastructure, and it's really this -- right here in this part the East Texas area. And we're probably moving north of a half a Bcf a day from that play. The thing that's been nice about it is there were very highly prolific wells. We saw some very high initial rates and things like that, but with these gas prices, we're actually seeing some pullbacks from some customers. But at the same time, they're still very attractive. We have some customers who continue to drill because they are or still have to meet -- attracts the economics.
The other thing that's very exciting that is still only 2 things, first of all, renewed interest in around our Longview area, and this where we have more of our processable gas. And our plants typically run fairly loadable. We're seeing more higher content of NGLs that we actually, we'll see at the plant. And so there's still more horizontal drilling going in that. So we're looking actually to do some upgrades to our facilities for increased NGL recoveries. And then even more so, this part of East Texas down in the southern part of our East Texas system is there's been a lot of leasing activity related to rich gas area play, namely the Eagle Ford, I believe, to be extended in this area as well as Woodbine. And the Woodbine formation has been around for a long time. There's been a lot of successful processing plays that went on in different areas, but these aren't new formations, they've been around. It's just you're actually seeing that they're actually extending these areas. So we're actually looking to expand in those part of the areas, and we actually have pipe, we have pipe there and looking to build processing plants and be able to aggregate the price of the [ph] market. And looking -- and customers actually looking for one-stop solutions for NGLs, condensate and natural gas. So we're very excited about that as well.
And just as Steve mentioned as well, the gas side has a very comprehensive integrity management program. It covers all of our transmission pipes, our gathering pipes, all of our other facilities like our plants, our compressor stations and some of our other platforms. We use internal-external benchmarking for best practices and for our cost, and we have a very -- any acquisitions due-diligence-related items. In relation to integrity, we have a very strict due diligence protocol and make sure we've assessed all the different integrity, potential integrity issues that may be present. We're installing some emergency-flow-restricting devices in our pipes which affect the high consequence areas, whether it be for our natural gas liquids pipelines, our transmission pipes or even some of our higher HUS pipelines [ph] that operate.
We also have some of our leading best practices in place. We do corrosion inhibition, chemical treatments, valve inspections, public awareness programs, pipeline signage and all these things where we're trying to be best in practice. We follow all those, and we're continuing -- looking to enhance our abilities to do those things as well.
And once again, I hope -- I want to stress to you all exactly just how we are very focused on our operational excellence. We've had a lot of intense activity in the Panhandle, catching up to processing -- building our processing capacity built out over the last year as we've been constrained for -- as we ran our processing capacity and third-party takeaway. So we've been -- have a very safe record for the last 12 months on how strategic our assets are placed in the very basins that we talked about and especially in the Granite Wash with our extensive pipeline network and our processing capacity as we build it out. We're also looking to expand our value chain. We have -- I didn't mention it, we also are putting a rail facility in Pampa to handle all the condensate and the Granite Wash and we're also seem to execute on our growth projects for those assets.
Some questions, yes?
Two-sided question here. I found the chart on the natural gas prices very interesting. And I'd love to have you give some color as to what's behind ENB's belief that in an environment right now with $2 gas, that will be a $4 gas in 12 months growing to $5 over the ensuing 3-plus years after that? And on the flip side of that, if ENB is wrong and for the next 2 or 3 years, we're actually in the $2.50 to $3 maximum gas environment, what kind of impact that might have to the partnership?
John A. Loiacono
Well, that gas price forecast is substantially lower that we had thought probably 6 months ago, all of it, obviously. And what that is, is our assessment of a blend of what the forward curve is saying, which is much lower than what everybody else is saying. And some other parties have much higher because we're trying to take a middle-of-the-road approach in that we didn't see it progressively getting as high as what some of the other consultants were saying nor the EIA. If those prices turn out to be lower, I think you're going to see continued pressure on gas rig, pure dry gas rigs to lay down, obviously. That's, I think, goes without being said. The only ones that will continue to drill are people who are trying to hold leases. And we're starting to see some people who actually are talking about walking away from some of their leases they have to drill in order to hold. I think for us and the partnership, we would see probably -- we're already projecting a lower -- we've already kind of assessed our forward thinking, at least for this year and the outgoing year, that gas prices will be probably lower than that in our mindset, and we've kind of taken that when we think about the forecast. It will, however -- it would enhance processing economics if gas prices go lower, which are valuable to us as well. In some of our regions, we have keep-whole processing. So I guess it's not a double-edged sword, but you would expect that, yes, there'll be some drop-off in drilling. The unknown -- the real uncertainty with that drop-off in drilling, though, is an Eagle Ford shale well in terms of gas isn't the same as a Haynesville well. A rig operating in both areas don't yield the same type of production. And so with the number of rigs that have lain down in some of these dry-gas window plays, we're going to have to see how long it takes before that gas -- how much disconnect there is between that and how much gas are coming out some of these other rich-gas plays on the residue side. Does that make sense? I think that's probably the biggest unknown, and that is one thing you can make that -- some of those higher gas curves come into play. I hope I did a good job answering, but it's the best I can do.
Just following up on the processing. How many of your contracts are rolling over, say, over the next 2 to 3 to 4 years, maybe away from keep-whole and people want to been borne [ph] to other contracts?
John A. Loiacono
We do not have a lot of keep-whole processing now. I'd say it probably makes up less than 5% or 10% of our processable gas that's probably under a keep-whole range. I'll have to say keep-whole or wellhead purchase. Keep-whole is a term people throw around, but I would say it's roughly about where we at, and really, I'd say, very little of that should roll over. We don't expect very much of that to roll over at all.
Okay. And then in the Anadarko, are you factoring in a lot of volumes on Texas Express? I think you've got '13 picking up pretty well, and I'm just trying to figure out if that's just because the processing plant's coming on or is it because of the pipeline? And kind of how should we think about the long-term growth in the Anadarko off of Texas Express?
John A. Loiacono
Well, the Texas Express volumes are, of course, driven by volumes other than our own volumes. We're one of the number shippers. Our volume projections for -- as our NGLs we contribute as a production side is a ramp-up over the next roughly 10 years. So it starts out at a more -- a lower number, and then as contracts roll offs is when they would come into the pipe. Did I answer your question? Yes?
Yes, I was just curious, what kind of ENP producer commitments you have with regard to your assets in East Texas are, especially [indiscernible] putting your capital to work?
John A. Loiacono
I couldn't understand. As far as the term or the type of contracts?
Yes, both the term and the type of contract.
John A. Loiacono
Well, okay. East Texas is a huge area, right? I mean, we have a lot of customers. A lot of, I'd say, of the total gas moving to East Texas, roughly 1/4 of it is processable. The rest of it, most of it requires some type of treating as opposed to processing. Most of the gas in East Texas, probably half of it is keep-whole, maybe, and half of it's under some type of processing arrangement. All of the treating gas is typically featured under fee-based business. A substantial portion of East Texas EBITDA is associated with fee-based business. [indiscernible] as well as for treating fees, compression and things like that for service fees.
[indiscernible] on the volume metrics side. Do you have like length-of-life kind of commitment? Are you in a fixed-volume commitment?
John A. Loiacono
Well, once again, yes, it's all of those. Some of them were very long commitments. The things we've built most recently have anywhere from 5 to 10 years of life we've built in the last couple of years. Some of them are more on a shorter-term basis. But the bulk of them are longer-term life. But life of lease, we don't have a lot of life-of-lease type of arrangements that I'm aware of. It would be a very small part of the portfolio, I'd say. Yes?
Sharon Lui - Wells Fargo Securities, LLC, Research Division
You mentioned that you wanted to secure or develop a position in fractionation. Just wondering is that mainly through contracts, or are you actually looking to build frac assets?
John A. Loiacono
We are exploring all those, and we're not married to anyone. We just want to make sure we have some ability to participate in the value chain, whether it be through contractual ownership of space or a position in one being built or potentially building our own. So all those are options that we're exploring, and I don't think we're married to any one of them. We just want to -- we always kind of look to where we can expand some NGLs with some of the value chain that's out there. And we've been exploring that for the last roughly few months.
Sharon Lui - Wells Fargo Securities, LLC, Research Division
And the second question is for Texas Express. Can you just tell us, I guess, in terms of EEP committed volumes and how that compares to the total volume secured for that project? And how we should think about the EEP volumes with regards to your anticipated returns on that project?
John A. Loiacono
I may have to let Mark take that.
Mark Andrew Maki
Sharon, we, like John mentioned, we ramp up over time. So as Texas Express comes into service, our volume commitment is relatively small. As you get out towards the way the contracts are set up on the system, the primary term is 10 years, and there's a dedication for 5 years thereafter. So you've got a volumetric commitment for 10 years. That, in our case, it ramps up. I think at the inception, it's probably 15,000 a day, it is our commitment, and then it increases to -- my recollection's about 100,000?
John A. Loiacono
Mark Andrew Maki
Yes. 100,000 a day at the end of the 10-year term. And then it would go to a dedication thereafter. And what that would do for us is it would replace other arrangements we have with other parties, so our cost will drop off to company X and be replaced by a -- effectively an expense to Texas Express. Our return on the project when we look at this one over time, it's attractive to us. It hits all the key elements, much like one of our liquids projects would. It's got good contract to volumes with others besides ourselves, of course. The partners are great. In terms of Enterprise, Anadarko couldn't ask for better partners. And so for us, on the return side, it's accretive. We look at the EBITDA to EV multiple, it's attractive. So it hits all the things and helps us integrate the value chain, one of the key things that John was touching on in his presentation. So we see this as a very important project to us, and again, the relationship with Enterprise, getting closer with them is important, and John mentioned contract fractionation. That is something we currently we do with Enterprise quite a bit.
John A. Loiacono
Stephen J. Neyland
Well, I think Mark was right. That was certainly a lot of passion by Steve and John. I've got to admit, initially, I thought he said fashion, and I thought, "We are dead." But anyway, I'm happy to follow them. Hopefully I can keep up with the passion. My name is Steve Neyland, I'm the Vice President of Finance for Enbridge Energy Partners. I'm pleased to be here today. First, I want to touch on our key messages. Kicking that off is our long-term value proposition, which we'll dig into momentarily. And the solid progress that we made on our 2011 financial objectives as well as wanted to lay out for you our 2012 objectives. We've been working very hard to secure a significant amount of liquidity, $2 billion approximately, been working hard. Given all these projects that Steve and John have noted, we're looking to secure funding for those. And again, these are attractive low-risk organic growth opportunities. And finally, all that finds its way into our distribution, and growth of our distribution will be securitized and driven by these projects, which we're very excited about.
Over to financial objectives, wanted to touch on our 2011 report card. As Mark noted, we've done a good job the last couple of years of staying true to our 2% to 5% distribution growth, and we've been at 3.6% and 3.8% respectively over the last -- 3.8%, 3.6% excuse me, over the last couple of years. We've maintained our strong investment-grade credit rating, and as John noted, we've integrated successfully our Elk City assets. And again, we'll touch on liquidity, which in the back half of 2011, we've had a very busy treasury group for sure.
As it relates to 2012, we continue to target our 2% to 5% to grow our distribution. We look to maintain that strong investment-grade credit rating, which, as a reminder, is BBB flat from S&P and Baa2 via Moody's rating, and secure the potential growth projects. Steve and John have a lot on the go, want to make sure that we have the financial wherewithal to back those up. When you get those projects, deliver them on time, deliver them on budget. We have an established major projects group within the Enbridge family that we rely heavily on to monitor and develop those projects and make sure we hit those critical targets. And then finally, we want to meet or exceed our earnings guidance, which we announced at the end of January, which is $510 million to $550 million range.
As it relates to our value proposition, we continue to look at EEP as a stable, high-quality investment with an attractive yield and a very strong tax deferral. So when we look at our yield, we continue to see ourselves on the higher side of things. We look at that as attractive from an investor standpoint, as well as the fact that with all the construction we've had over the number of years, the organic growth creates a lot of tax appreciation and a significant tax shield for our investors.
Just touch on briefly, this is a pictorial of our distribution growth over time. You can see that the last couple of years have been very solid in the 2% to 5%, as we had targeted. 2009, we did take a year off, given the market meltdown and such that occurred and the ensuing credit crisis. But feel very well positioned to deliver on this 2% to 5% through organic growth platform that exists.
In underpinning of successful organic growth projects lies in the disciplined approach to our projects. As Mark noted, we're a conservative group, and so I wanted to touch on our approach to thinking about the economics when we look at a project. First, we have a risk-adjusted cost of capital, hurdle rate that we use internally. No project is created equal. So we have a very robust process where we plug in all the various risk factors that make up a project, be it operational risk, be it credit risk, be it integrity risk. And additionally, the one that I think gets a lot of attention is whether you're a surety of revenues associated with the contract structure. And so we boil all those things together and we come up with internal cost of capital and we run that through our modeling process. Not something we take for granted. It's something that we do in concert with a sign-off from our treasury function, and it really underpins the initial decision-making that occurs on a project.
Other key aspects associated with that as we look for those projects to be accretive in year 1 to our LP unit holders, and we also look for it to be strategically aligned. So we've talked today about a lot of projects that are strategically aligned, from the Bakken to the Granite Wash, places where we're looking to enhance our footprint, expand our market presence where we have a current infrastructure to leverage off of. Additionally, we've also talked about some areas where we're looking to grow our asset base. The example there would be Texas Express and the vertical integration play that John described.
And finally, the asset management aspect. I wanted to talk about each. Once an asset comes into service, we have a dedicated asset management team, be it liquids, be it gas, that oversees the P&L associated with that entity as well as a dedicated operational staff that's looking at the critical aspects of safety, integrity and keeping our environment safe.
Current growth initiatives. We're looking at $2 billion of growth projects, several of which I'll touch on in the next slide, that are secured. Ready to go, we're in process. Incremental to that, we're looking at a $4 billion program of potential growth projects that exist beyond that, the largest component of which sits on the liquids side of the house. As Steve mentioned, we've had a lot of opportunities as the rising Western Canadian oil sands as well as the Bakken create significant opportunities for the company.
The intent of this slide is to demonstrate the future impact of some of the projects we have on the go. The $2 billion mentioned, the capital associated with this slide, is a little less than $1.4 billion of capital spend, and we've given some illustrative EBITDA associated with those projects. As it relates to these projects, we've been very busy securing capital. And so there's been some prefunding that's been necessary to some extent to put these into service. But we look at 2013 as being a big year as it relates to placing assets and service. And I wanted to touch upon, just very briefly, each of them and the strategic rationale associated with it.
The Line 5 expansion, Steve mentioned, bringing light volumes over to the East Coast, and then really the next 3 bars that really drive the Bakken footprint. And contract structures are different amongst them. Steve spoke to some of that, be it the take-or-pay arrangements that exist on our Bakken expansion or the different contract structures associated with the $145 million Bakken rail project that exists.
Finally, the last couple of bars on the slide speak to the growing Granite Wash producers chasing the NGLs and trained in the gas stream and not only just the Granite Wash, but also the takeaway aspects associated with the vertical integration. So each of these projects plays into a key strategic area within the different components of the company. And again, these are just estimated first full year contributions in the EBITDA and are for an illustrative purpose.
CapEx. So a lot of those projects has been off capital that we're spending currently and will be spending in 2012 that find its way into a $2.1 billion capital program for 2012, significant in nature definitely. And then also bringing those assets into service and other projects we have on the go, we have a 2013 bar which illustrates the potential spending that may be out there. So it's in dotted -- it's dotted lines for a reason, we're currently in our process planning for long-range strategic plans, and we'll be firming that up over the next several months as we go through that. But it illustrates that there's certainly upward pressure as it relates to capital with some of the organic growth that's on the go.
Financial metrics are critical. Maintaining our targets and looking to achieve those targets are critical, because as we mentioned at the beginning, credit rating, our investment-grade credit rating is critical. We will maintain it and do what we to do to ensure that. And through that process, we'll be keeping a careful eye on these financial metrics as we move throughout our planning process.
We will spend just a couple of minutes here on our liquidity funding requirements. So we have about -- as mentioned, we have about $2 billion of available liquidity. We mentioned at our September 30 call, and there've been a couple of items noted here of success that I did want to point out, and kudos to Dave Wudrick and the treasury function that has enabled this, but we have upsized and extended the credit facility to $2 billion, that mature in 2016 as well as increased our commercial paper program to $1.5 billion. Those things as well as the significant amount of capital raise that occurred in the back half of 2011 have set us up very well as it relates to achieving our needs and funding requirements in 2012. So as a reminder, we look at a whole variety of different funding opportunities, be that your typical debt or equity offerings, be that private placement, be that our -- we also have an equity shelf program which we use from time to time that's available to us as well as the credit facilities that are mentioned here. So again, a good mix of available capital aspects to set us up well to securitize and underpin the financing for these projects.
Important to the certainty of our distribution, the certainty of our -- of the partnership and its returns is a low-risk business model. So I wanted to touch on that briefly. We've shown the 2/3 liquids, 1/3 gas split previously. And Mark noted that we expect that to grow significantly on the liquid side of the business. So we expect more growth from the liquid side of the house versus the gas, but both growing. One thing to point out in the green sliver there on the gas side of the business is that approximately 50% of the earnings when you look out the next year are driven off of our Anadarko assets, which sit within the Granite Wash. So significant amount of gross margin is driven off of the Granite Wash asset. That gross margin, then moving across the page to the right, we demonstrate what's fee-based in our gross margin and what's commodity-sensitive. We are commodity-sensitive on -- for components of our gas business as it relates to POP, POL and keep-whole contract structures. The way we manage that risk, down on the bottom left-hand corner, is through a very regimented hedging program that we have that's in place and overseen by our Board of Directors and then managed by a risk management committee that watches the metrics and the hedging requirements closely.
Year 1, year 2, we have a mandated hedging requirement of 70%, 50%. Then thereafter, as liquidity becomes more of an issue, we have a little more strategic in nature as it relates to the hedging, although our targets that we look to hit are noted in the beige bars on the chart.
After that hedging program, well -- and one thing I wanted to point out, on our hedging program, a couple of things that are important to note and reinforce is that from a credit standpoint, we're using A-grade or better counterparties. Most of these are financial institutions, but credit is a very important aspect when we go out and do this hedging. The second thing that's important to note is that we do not hedge dirty. We hedge clean. So if we're going to hedge ethane, we hedge ethane with an ethane swap. We don't go out and hedge ethane with WTI or some derivative. And we look to eliminate our exposure in a very methodical way through that.
Once that hedging is complete, you can see that the green sliver of the 25% modifies down to the 8%. And there we're at a smaller percentage of volatility that exists, and that volatility is further managed by a "cash flow at risk" program that we have, and we look out for the first 12 months and we make sure that, that cash flow at risk is no more than 7.5% -- it's 7.5% or less as the partnership as a whole. So a lot of mechanisms in place to ensure that we're managing our commodity exposure effectively.
Next slide, just quickly touch on the various contract structures that exist within the gas side of our business. John touched on several of these. What you see here is the blue sliver, well, I call it a wedge, sliver would be understating it, the blue wedge that exists on our commodity at length are -- it's really the growth in the POL and POP contract structures. This relates directly to the fact that producers continue to chase NGLs on the gas stream, and these are predominantly preferred contract structures by the producers and ourselves. So we look for that to grow in the coming years. And then pursuant to that, it will fold into our risk management program just mentioned.
Briefly wanted to touch about -- touch on sensitivities associated with our business. From a commodity standpoint, starting on the right, we're naturally hedged from a gas standpoint. We have a link that the partnership has as the shippers pay us in kind for the POP contract structures, offset by keep whole, [ph] feeling the shrink that we bear. Net-net, we have very little exposure on the gas side of the business -- gas commodity side. As it relates to NGL, different story. NGLs drive the boat as it relates to commodity exposure, and here we show what a 28% move in prices can do, plus, minus, within the partnership. And it becomes larger in the out-years as there's less hedging that has been associated with it. Additionally, we also see NGL growth, as mentioned before.
So we could move to the next slide. I wanted to briefly spend a moment on the financial outlook for 2012, same financial outlook that we went over at the end of January on our call. Keynote here is that we feel very confident in it. We're excited about looking to achieve the $510 million to $550 million of earnings for 2012 and continuing to kind of grow the earnings of the partnership.
Well, finally, key messages, I'm not going to read the slide, I'll let you look on. But I would like to reinforce that we are focused on a disciplined strategy to ensure that we're in a critical, well-positioned situation to support the secured growth projects that are coming online.
So with that, I'll stop there and ask for any questions.
Okay. First question just the estimated first full-year EBITDA contribution. I'm curious, what is the growth trajectory after the first year that you expect, I guess, in aggregate from those projects?
Stephen J. Neyland
Yes, hard question. Certainly dependent -- certainly depends on an asset-to-asset basis. A number of these, such as the Bakken expansion, it's just a take-or-pay contract structure. You'd expect a fairly consistent type of return as you look into the out-years associated with that. So we're talking about 10-year take-or-pay type commitments. Some of the other -- so it's really on a dependent basis. I point to that one as the largest one. Texas Express, as Mark and John mentioned, it's going to ramp as we move forward. But again, it's also underpinned by those take-or-pay type commitments that ramp into the future. And then there are some that have a level of volume sensitivity to them, and that would be the Ajax Plant for one, although our belief in the growing Granite Wash and the chase for NGLs make us feel very good about prospects there.
Okay. Let me ask another question on [indiscernible]. On percentage terms, what would you look for kind of annual growth off of those first-year numbers? I mean, 5%, 10%, what are you thinking?
Stephen J. Neyland
Tough question. I would say that, certainly, you're talking low single-digits type of growth when you look at those.
Okay, great. And then the next question, just looking on the slide, I think it was Slide 70 in your -- on the deck, on sensitivity analysis there, just the horizontal scale, is that changes in EBITDA for -- given changes in prices? Is that what that's supposed to be, the 60%, the 20%, 40%, 60% plus or minus? Is that what that's indicating?
Stephen J. Neyland
Yes, that's the changes in our margin. If you had a 20% shock, plus or minus, to the NGL price, that's what you'd see -- the change you'd see in our margin. And certainly in the out-years, the change is more because there's less hedging associated with it.
Jody K. Lurie - Janney Montgomery Scott LLC, Research Division
Jody Lurie, Janney Montgomery Scott. As you shift -- earlier in the presentation, you talked about how you're shifting from 2/3, 1/3 liquids to natural gas into more of a 75% to 25%. How will that change your hedging strategy as well as your exposure to commodities?
Stephen J. Neyland
It should reduce it. Well, on an aggregate basis, we see both sides of that coming back up. On an aggregate basis, we see both sides of the house growing. It's just that the liquids side of the house is growing at a faster rate than the gas side. So as it relates to that hedging, program will still be necessary. There will still be incremental growth. Then you see more and more NGL hedging in our future as the areas that we sit in, the Granite Wash and some of the areas that John noted in East Texas and North Texas, the continued chase for those NGLs and condensates. So I expect it to grow over time. It may not be -- it is not going to double, but it will be kind of a stair-step growth that occurs.
Steve Ross, [indiscernible] Wells [ph]. Looks like your leverage metrics have been below your historical levels, which we obviously like to see. But it also looks like your targets are also below where you were a couple of years ago. Is that rating agency-driven, or is just upper management kind of trying to push for additional flexibility there?
Stephen J. Neyland
Yes, I would say that our credit metrics are certainly a combination of the conservative nature of the company as well as where the rating agencies would like to see us. There has been -- as you know, there's been some modest improvement associated with that. And we recognize that things will fluctuate as we move forward, but we want to make sure that we have the appropriate financing in step with the organic growth and to manage these financial metrics effectively. We're also blessed by the fact that there's a number of projects coming online that give us additional distributable cash flow, which certainly helps out relative to the metrics.
Regarding Slide 14, what are the key drivers of the guidance ranges of the various columns?
Stephen J. Neyland
Sure. Our financial outlook is driven to an extent by volumetric expectations on the assets themselves, so no secret there. But I want to state that as it relates to a lot of the projects or a lot of the assets we have in place, especially as it relates to North Dakota and our Lakehead System, you're talking about a cost-of-service type contract structure. So it's pretty fixed in nature. So the variable, you don't have to -- it doesn't take too much science to get to the right answer. As it relates to our gas business and components on our liquids side of the business, there is some volume that will moderate the earnings up or down. So as John mentioned, I think one of those challenges, when we looked at our numbers, was certainly, what do you believe about gas prices, what do you believe about drilling in the dry gas areas? I think when you look at our projections on a year-over-year basis, we're keeping our gas volumes effectively fairly flat from '11 to '12. We do have additional assets that we can leverage, but we're taking, I think, a fairly conservative view associated with that. But as we've noted, the volatility in gas prices have been substantial over the last 6 months, and we stand by, ready to react to that as necessary as to whether there's more or less capital that's needed in our areas. So I'd say that volume's the key. The other aspect, obviously, is cost, and we are spending additional dollars this year as it relates to inline inspections, especially on our liquids side of our business, to ensure enhanced integrity of that program. And kind of in concert with the dig program, we're spending a lot of money as it relates to '11 and '12 in order to ensure a top-of-class system for both our shippers and the environment itself.
Regarding the investment criteria on Page 6, what is your estimated cost of capital? And how high is the hurdle rate?
Stephen J. Neyland
Yes. So certainly, a difficult question. One which I will sidestep to a degree is our cost of -- as mentioned, it's depending upon the situation itself and the asset base itself and the risks around it. Typically, we're talking about ultimate returns on our projects. It really depends upon the risks associated with them. But on a gas project, for instance, which has some volume risks, we'd expect the returns to be in the high-teens, low-20s. If you had a take-or-pay, cost-of-service type contract structure, obviously, you are able to sustain a lower return than that as a point of reference. So...
You have a significant amount of debt coming due between 2015 and 2020. When might you start trying to roll over some of that debt?
Stephen J. Neyland
So we're -- we have a mandated governance requirement that says that no more than 25% of our debt will expire in any one given year. So that's one rule to grow that we have to manage by. Additionally to that, we're always looking to -- for some additional debt in place. So not trying to forecast it, but we will be actively looking at that over the next year or 2. And we'll look to be putting in some type of 10-year, 30-year type instrument probably to mitigate that rollover or replace -- I shouldn't say mitigate, but to replace that debt load. So...
Stephen J. Neyland
Executive compensation. Yes. So -- yes, this'll be good. I got a bunch of guys who say it's too low, so it's too low now. That's what their eyes are telling me, I don't know. I don't know what they're really thinking. No, as it relates to our executive compensation programs, certainly something we take very seriously. The -- it's a combination -- first of all, we're looked at within the partnership 3 different aspects of how well has the company done for the year, how well have you done for the year personally and how well has the business unit which you're directly tied to done for the year? So those 3 things are looked at on an aggregate basis. And so you have your base salary, bonus potential, which is driven off of those 3 aspects, as well as there's long-term incentive that's put in place for our executives. And so long-term incentive is obviously the key aspect of retention. We have a very long and lengthy executive compensation section in our 10-K that will be coming out for about a good 20 pages. I think those are -- I'd say those are kind of the key aspects from my vantage point. So certainly retention, but also incentivizing, we're thinking the long term. We don't incentivize -- because this is a long-term investment, it's a long-term investment vehicle. So we want our executives thinking in the same terminology.
Stephen J. Neyland
There is some earnings-per-share metrics, but there's not, I would say, a key catalyst per se or one that drives the boat.
We talked earlier about all the integrity spending you're doing. Can you just remind us again about when you're expecting to get the recovery on all the spending? Is it mostly in '12? Is it -- have you gotten some of it back, more '13? Or what's the timing there?
Stephen J. Neyland
Sure. The -- as Steve noted in his discussion, doing a significant amount of integrity digs last year, this year. And as it relates to recovery of those costs, it's a bit of a mixed bag as to how we recover those costs. A good amount of those we expect will be recovered through what's referred to as our facilities surcharge mechanism, which is a mechanism within the toll to give you a modest return but something you're talking about, probably a low-teens type of return. But those are discussions we have with our shippers as to what's going to make sense from their perspective. So there's a component of that, that certainly we get a return on through the FSM, but there's a component upon that, that we may not get a return on, that we may just recover through our index tolling mechanism -- our index tolling process, which is not a significant return of the FSM. And so it's a evolving discussion with our shippers, and some of those discussions also play into some of the longer-term projects that we have on the planning board as opposed to the evolutionary-type process. But they are at the table definitely as we're talking through that. And so I think at this time, it's really hard to like pin a number, pin a percentage as far as how much we expect to recover through FSM tolling.
Okay. Seeing no further questions, I'll turn it back over to Mark to close us up.
Mark Andrew Maki
Okay. Well, thanks, everybody. I mean, first off, again, I want to thank you for investing time with us today. It is a good hunk of a day for all of you, and I hope you get a lot of good information out of these discussions. Great questions, great discussion, no question. I got a homework assignment from David Maccarone [ph]. Always appreciated, so I go home and do something. Good question, David. And Sanjay will be gathering feedback at some point here. I'm not sure when, but not -- probably not today. But he'll be surveying you and asking you for constructive suggestions as to how to make these things better and more useful for you. So again, feedback, absolutely welcome and much appreciated.
So the last item of business is lunch. That is behind me in the next room, so please have lunch on the company. And again, thank you for your participation today. And if you've got questions, absolutely grab management and bend our ear. Thank you very much.
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