Alan S. Armstrong - Chief Executive Officer, President, Director, Chairman of Williams Partners GP LLC and Chief Executive Officer of Williams Partners GP LLC
John R. Dearborn - Senior Vice President of NGL & Petchem Services
Randy M. Newcomer - Executive Officer
Francis E. Billings - Senior Vice President of Northeastern G&P Operations
Allison G. Bridges - Vice President
Rory Lee Miller - Senior Vice President of Gulf & Atlantic Operations
Donald R. Chappel - Chief Financial Officer and Senior Vice President
J. Michael Stice - Chief Executive Officer and Member of The Board of Directors
David C. Shiels - Chief Financial Officer of Chesapeake Midstream GP L L C and Principal Accounting Officer of Chesapeake Midstream GP L L C
Faisel Khan - Citigroup Inc, Research Division
Williams Companies Inc (WMB) 2013 Analyst Day May 21, 2013 8:45 AM ET
All right, good morning. I think we'll go ahead and get started. I'd like to welcome you to the 2013 Williams and Williams Partners Analyst Day. My name is John Porter and I head up Investor Relations for both of these companies. Continues to be an exciting time for our industry, and particularly, for Williams, so we're really glad you could join us here in person or online on the webcast.
Flipping to Slide 2, we've got the agenda here. I won't take you through all the lines, I'll just point out a couple of things. We will have a break this morning. Alan will do the introduction, and then we'll have our NGL and Petchem Services presentation. We'll take a quick break. We're going to do Q&A at the end of each speaker's presentation. So we'll save time in each presentation for your questions and answers. Doing something a little this different this year in terms of lunch. The packed room, hope it works. We're going to have box lunches. We'll take a break. After Frank Billings, Northeast Gathering and Processing presentation, we'll go get those box launches. And then we'll do a lunchtime presentation, where Allison Bridges will review our Western operating area. And then we'll pick it back up after that with Rory in the Atlantic-Gulf area.
Slides 3 and 4 are the forward-looking statements. Important information in there, so you should take a look at that. Additionally, we have non-GAAP measures in the presentations and we reconcile those to the nearest GAAP measures in the back of the presentation materials. So again, I'll just say thank you for being here, and hope you have a great day.
And with that, I'm going to turn it over to our President and CEO, Alan Armstrong.
Alan S. Armstrong
Thank you. Well, good morning. Thank you, John. Before I get going, I just wanted to acknowledge the tragedy in Oklahoma. And let folks know that, of course, in Tulsa, we're about probably 100 miles away from that tragedy. But obviously, it's a big impact to our state, and certainly, to Access Midstream who's based in Oklahoma City, a lot of employees are impacted there. But anyway, I just wanted to acknowledge, I can't imagine a more horrible thing than having -- not knowing where your kids were in a moment like that. But anyway, I just wanted to acknowledge, the management's respective of our thoughts and prayers go out. And we'll certainly do our part as a corporate citizens to support the recovery of an important place in our state.
With that, we certainly are very pleased this morning to be here today. We have so much going on. It really becomes very challenging to present all of this information in such a succinct way. But I wanted to say again to John Porter and his team, how impressed I've been with their ability to pull all this information together, with all the various projects that we have going on and put it in front of you in a way that I hope answers a lot of the questions and really shares our excitement about the great future that's out in front of our company today. This really is an incredible time to be in this industry. I really don't know that there ever will be another moment like this in our career, certainly as a management team, to be able to see the incredible opportunities that are out there right now because there is so much demand for the kind of infrastructure that we are very good and very focused on getting in service and being able to help out to take advantage of these incredible amount of natural gas and natural gas products that we've been blessed with here domestically.
So we've continued to build out our organizational, I'll talk a little bit about that this morning. But this team is really excited to have the opportunity we have to play such a major role in this infrastructure build-out, and I think you'll see that as you hear from the team today.
So here is a quick overview of what I'm -- what you're going to hear today. And first of all, in my presentation, you're going to hear about, a little bit about the new organization model that we have and some of the leadership changes that took place at the first of the year, really in an effort to go and address all of the changes that we've got going on. You'll also hear about our strategy and some of the strategic choices that we've made over the last several years and how that has positioned us extremely well for the extraordinary growth that we're experiencing today and the kind of growth that is leading to the dividend growth at WMB that we continue to enjoy and continue to build and deliver.
I'll also share a little bit of perspective on the commodity environment as it impacts our strategy. And then later, you're going to hear a more detailed explanation of the olefin market fundamentals from Randy Newcomer and John Dearborn, who I'll introduce in a moment. The number of opportunities that we've got going on are really causing a lot of capital allocation on our part. That's a good problem to have, but nevertheless, it requires a lot of discipline on our part. And I'll talk a little bit about our capital allocation that we've got going on and how we think about that. And then I also will provide a quick overview of the fundamentals that are driving the Bluegrass NGL pipeline and in a very rapidly growing resource play that is the Marcellus in Utica and how critical we think Bluegrass is to the continued development of that resource base.
And then many of the detailed explanations that are supporting the projected 62% growth in our distributable cash flow at WPZ between '13 and '15 will come from the business leaders today as they explain the various projects that are supporting that kind of dramatic growth as we continued to build up infrastructure in each of these 4 areas. Also included in that explanation, you're going to hear from Frank Billings on the -- some of the challenges that we've been facing in the Caiman acquisition at Ohio Valley Midstream and be able to explain exactly what we're up against there and exactly what we're doing to get that business on track. It's a good problem because there is plenty of resources there. It's just a matter of us getting the infrastructure really matched up to build and deliver against such an overwhelming amount of resource that's available there.
And then finally, Don Chappel's going to bring it all together in terms of what this is going to do for our financial performance and the powerful support for this 20% dividend growth that we continue to deliver at WB on an annual basis.
So next of all, let me talk about the new organization that we formed. And this really has developed all of last year. We worked on this, we thought about -- after we spun off WPX Energy, we thought about how we needed to form to be not just good, not just another midstream company because there's plenty of us out there, but really, somebody that establish themselves as great. And the areas that we really thought we needed to be great in and put the most effort into was in our project development and project execution space. And so you'll see that these organization is formed in a way to build and deliver on that. And I'm proud to tell you that we -- I would say we were pretty good. We certainly had a long history of developing a lot of complex projects, on time and on budget. But to take on the kind of capital program that we have, we thought we really need to step it up and even bring in more focus and more attention to that.
So we put this new organization into effect of the first of the year, and we now have 4 operating areas: the NGL & Petchem Services Group, the Northeast Gathering and Processing area, the Western basin and the Atlantic-Gulf. Now the West includes both Northwest Pipeline and all of our Western Gathering & Processing. And the Atlantic-Gulf includes Transco, Gulfstream. We'll include constitution, so those 3 major transmission systems and then the -- all of our Deepwater in our onshore gathering and processing in the Gulf Coast area.
The operations and the commercial efforts in each of these areas, so that means our field operations and the folks that go out and develop the business in and around those existing assets, all report into each of the leaders in these areas and that is a combination of John Dearborn and Randy Newcomer, and I'll explain that in just a second; Frank Billings, Allison Bridges out West, Rory Miller in the Atlantic-Gulf. And so those are the 4 operating area leads.
In addition, all of our project development and project execution for a major capital project is now led by a gentleman named Fred Pace. And Fred's been in this industry just a little longer than I have, and I've had the pleasure of working with him in and out of different roles within Williams. And also, he owns his own engineering construction firm for a number of years and was very successful with that. We were able to attract him back to run this portion of our company. He's been with us now about, been back where he's about 3 years now. And he's really making a difference in stepping up our game in terms of the way we manage these major projects on a professional basis.
Also supporting our very best operating practices and expertise is a gentleman named, Brian Perilloux. Brian -- neither Brian or Fred are here today. But Brian formerly headed up some of our Gulf Coast operations for us and is now leading the areas that include things like our EH&S, our asset integrity, all of the things that are really common to being a great operating company. It includes our control centers, all of the pipeline control centers and a lot of our areas of expertise like measurement and rotating equipment. So a lot of our centers of excellence are run by Brian. And he is a very can-do kind of guy. That was not an easy role to take all of our operations across all of these areas and make sure we're bringing the very best and not relearning the same lessons over and over, but being able to take things that we learn in one area and apply them to another. And that's a lot of what Brian's team does.
Then Jim Scheel leads our Corporate Development Group. And these are large business development project like the Caiman acquisition, the laser acquisition last year, the Bluegrass project, just to name a few. So as you can imagine, Jim and his team has been extremely busy. And then Robyn Ewing leads our HR communications and IT functions. And she's been with the company for about the same time I have, and it came us through the MAPCO acquisition, does a great job keeping things stable there on those important fronts.
And then finally, Craig Rainey is our General Counsel. Craig's with us today, and he's been our General Counsel for about 18 months. And prior to that, led our Midstream business. He was the head of our General Counsel for our Midstream business for many years before that. So thrilled to have Craig in that role.
So that pretty well rounds out the corporate support there. And so now, let me introduce some of the management team here that's with us this morning. And I'll ask them to stand up and wave. In the case of John since he's already standing. But I will tell you, I am very excited to introduce you this morning, John Dearborn. John Dearborn came to us from SABIC. And before he had a long career at Union Carbide, Dow. And really the kind of international experience that we were looking for in the olefins segment is knowing how to connect all of these great resources that we have here in the U.S. to these markets that are really, really looking for these lower cost feedstock and these lower cost resources. And so we were really thrilled to have John's talent and experience with us. And he'll be talking a little bit about our strategy this morning in that area, and I think has some very important information to share with you. I do want to be very clear on this front though. We are not going into this business to be big in the petrochemical space. That is not our angle. We are focused on serving the petrochemical space, and we think it's going to take a tremendous amount of infrastructure to serve this petrochemical space that, as you're going to see, has got an opportunity to build out in a very, very large way. And so bringing somebody in from that side that knows the needs and knows how the business will build out and also knows those markets is really key for us and very excited about that.
Also, Randy Newcomer is with us this morning as well. Randy has been serving as the Interim Lead for our NGL & Petchem Services. And I've been trying to get him to stay for many years, but he's been, -- he and particularly his wife, have been working hard to trying to get him into this position and retire. And so Randy has served the company in a very, very important way, and certainly, wish him well in whatever he and [indiscernible] will decide to do here in the future. So Randy, thank you very much for your long service to the company.
John and Randy are going to tag team that NGL Petchem story. Frank Billings, who has, a lot of you all know, has a very big role in developing and operating our fastest growing segment in the Northeast Gathering and Processing business. So you're going to hear a lot of information from Frank, but he's certainly going to be hitting head-on the OBM operational issues that you've heard about and we've discussed in the past. But particularly as well, showing the power of the growth in this exciting area.
And then Allison Bridges, who has formally led our Northwest pipeline operations which continues to be very successful, and Allison did a great job in leading that for us. And now she is leading all of our Western operations, which includes, as I mentioned earlier, a gathering and processing all out in the Rockies. So a lot of very stable cash flows continue to come out of that area. Despite much lower margins, we still are enjoying tremendous free cash flows out of that business.
Rory Miller, who previously is running a Midstream operation, is now running Atlantic-Gulf, which includes both Transco and our Midstream operations. And Rory is bad in cleanup. For the way you're seeing this morning and I'll tell you that he's really in a somewhat envious position this morning or enviable position this morning because he is showing the strength that you got when you got great position, very powerful competitive advantages in the markets that you're serving. And you happen to be sitting on great growth areas, those are the Deepwater oil development in the Gulf of Mexico, and as well, the gas demands that Transco in our interstate pipelines on the East coast are enjoying. You're going to see a pretty powerful story there of both free cash flow and growth in that area.
And then Don Chappell, of course, you all know, and Don, very pleased to continue to have gone managing so much of this important growth from a finance standpoint and appreciate his great leadership to the company as we continue to push through all of this great growth.
And then finally, I'm very honored to have Mike Stice with us this morning, who leads Access Midstream. Thank you, Mike. And you're going to hear a great story from Access Midstream as well, and I'll remind you. We own 50% of the general partner of Access Midstream and about 24% of the LP units. And so you're going to hear from Mike what we were so excited about that. I'll tell you, that is a great strategic fit for us today, but it is also a really powerful financial position as we get on the very terrific spot, from my perspective, on the IDR runup on the GP that we own there. But very sound business and very well aligned, frankly, with our strategy of having large-scale positions in the right basins.
So moving on now to a little perspective on the commodity prices, real quickly here. First of all, the commodity prices that we're currently experiencing certainly had some negative influence against our guidance. As we've seen NGL margins get cut in half from first quarter of '12 to first quarter of '13. And then again, we saw then fall from fourth quarter of '12 to first quarter of '13, that even in that period, they fell 21%. So we've continued to see a pretty major decline going on there in our NGL margins. Now there's 2 drivers to that, and I'll also tell you there's really 2 sides to that. First of all, the gas price has run up here, which actually, while it may seem like a negative in the short term, actually I think that's a very positive long term for our business model. Because it is going to take some more sustainable gas price to develop the kind of supplies that we think are going to be needed to meet the demand that is growing. I would tell you, I keep telling people this, but I don't think the whole market really is listening, and certainly, I'm not sure investors are listening to this. There is a tremendous amount of demand that is building up in this country for natural gas. There is capital rolling in all over the place trying to take advantage of our low-cost energy prices here in the U.S. It's coming from international, and it is really going to work to take advantage. The concern I have is that it's all going to show up at once. If it's not showing up today on people's radar screen, I think it's not happening. But I'll tell you there is a lot of capital that's going in the ground that's going to take advantage of that. And if we were sitting here with $3 gas prices today, I would be very concerned that we were going to be on the wrong side of this when that demand finally hit, and we weren't keeping the supplies building on the gas side. Thankfully, I think, at this kind of pricing level, I think we're going to see a healthy market develop, both on supply side and the demand side as well. And so I think we're very well positioned for our strategy because our strategy is very focused on volumes. We are really moving away from being a spread-based business, but we are very exposed and continue to position ourselves to be exposed to volume growth, both on the natural gas side and on the NGL and NGL product side. So we think that's a great place to be, and we think this market situation where we've got first gas, low-priced gas attracted all this demand, I'm telling you that's going to show up. And then eventually, this low-priced NGLs that we have are now attracting a lot of capital on the petchem side. And we're going to see that demand show up. It's lagging, but it's going to be there, and it's going to be there in big volumes. And you'll see some support today from that.
So in the short term, I think the commodity price environment, certainly, the ethane price is going down as fast as it did caught us a little bit by surprise, even though we've been forecasting lower ethane margins for some time. But I'll tell you, it hit a little faster and has been more prolonged than we would have expected. You can see in our guidance today, we're expecting no ethane margin, no ethane recovery on our facilities all the way through '15. Now I'll tell you, one thing I do know is there will be periods in there where we are recovering ethane, but it will be very short lived, and it's going to be low margins to be had because there is plenty of supply out there to meet the current capital demand. Beyond '15 and the '16 and '17, I think you'll see that demand start to pick up. And again, it's going to drive volume, and that's exactly where we want to be. We really want to be somewhat indifferent to price, but we want to be very exposed to the volume growth.
So one of the things -- first, you'll hear on our strategy. One of the things that I think we actually can be accused of and I'd fully admit, is that perhaps, we've been a little too strategic. We're very focused on building a model here that has competitive advantages, that are very sustainable for the long term. And to do that, it's required that we go into some pretty bold positions and that we certainly pressured our short-term cash flows and our distribution ability at WPZ. But we're doing that because we are convinced that we need to gain these major positions now while those opportunities exist. And certainly, we're working to balance that, but I'll tell you, there's not going to be very many opportunities come along like this to get these major positions in these new resource plays. And we are committed to that strategy.
One of the questions I get around our strategy is what do we mean by premier, and I'll be very clear on this. We don't go into a basin, we're not interested in going into a basin unless we have very strong and unique competitive advantages. And one of the best ways we know of the gain, good competitive advantage in areas that have very large scale, so that we can be connected to the very best markets and so that we can operate at a very low unit cost. We've seen plenty of advantages come to us over the years, particularly out in the Western area, by having that kind of large scale position. And so we're not going to be everywhere, but where we are, we are going to be large scale. And so when we say premier, we're really talking about in the market or the basin that we're serving, particularly. And we really see that we have really 3 strategic groupings today. We have areas where we're developing into that #1 or 2 position and so the Marcellus and Utica is a good example of that. Or we have areas where we're taking advantage of an already very established competitive advantage. And the Canadian position's a great example of that, where we have a very unique competitive advantage that we continue to grow off of. And then finally, maximizing returns in mature established markets. And so in areas like out in the West, where we've got an ability to continue to see great free cash flows from those businesses, that's exactly what we built those businesses for, was to enjoy tremendous free cash flows in return, and that's exactly what we're enjoying today.
So we do believe that our strategy is very well suited for this predicted commodity environment. We've certainly, as I mentioned early, we've certainly seen the ethane margins disappear rapidly, but we've been positioning ourselves and had already committed to the guys in ethylene expansion and knowing that we need to move very quickly, we pushed ahead with that one, very thrilled with that project. The project's coming on very nicely. And we're excited about the kind of the terms that, that project would deliver for us, and particularly, the kind of balance that it puts to our position. At the end of the day, again, we're going to be focused on volumes, and we're going to be focused on being a great market outlook for our producers.
Additionally, we've been positioning on -- to be more dependent on volumes and not on prices, as I've said. And we're now forecasting that our fee-based business will grow 51% between 2012 and 2015. And that's against now -- and this is in our guidance. At a midpoint, our NGL margin will decline from $752 million down to $332 million during that period. So you can see the kind of growth that 62% Bcf growth that we have is not dependent on margin decline in our NGL business. And it's actually about a 10% decline in the margin that we saw on the olefins business from the first quarter of 2013. And so, we're not really looking for big margin expansion, in fact, we're working against that headwinds. Because so much of our capital is going to be in fee-based projects, we're able to continue to grow nevertheless.
Finally, I would tell you, this is all underpinned by what we think is a massive arbitrage between these very low cost U.S. prices for natural gas and natural gas products and a continued high price around the world that is dependent on higher-priced oil businesses. And we think that gas, even if oil were to drop tomorrow in a fairly large way, gas still got a big advantage. And I think it'll take some time because I think the U.S. consumers and demand has been convinced that we have the ability to continue to deliver gas and gas products at a low cost. And that competence is building the capital that's going to move the volumes ultimately that we're going to be dependent on.
So I'm not going to spend much time on this. Don's actually going to hit this in a minute, but real quickly here, you can just -- remind you, our annual growth that WMB through 2015 is 20%. And I think as you'll see today, we're building the firepower to continue that kind of annual dividend growth for many years. And then as well at Williams Partners, 9% growth on cash distributions in '13 and still in '14 and '15 at a very healthy 7%.
And with that, I'm going to move that on to disposition. First of all, I told you I would talk a little bit about capital allocation and how we think about that. And I'll tell you, I've just never seen a situation where we've been turning down so many good projects as we have been lately. But it's just because the huge amount of opportunities that our competitive advantage has given to us. So the way we think about it, first of all, we think about it on a very typical risk-adjusted return. So obviously, things that have commodity weighting, require a very large return in our portfolio, things that are more fee based and don't have construction risk, so we still have projects in our pipeline business where we don't have to take the construction risk and make them with 20-year contracts. Those kinds of things deserve a lower return, and so that was kind of the 2 ends of the spectrum there, and we're very, we're fairly sophisticated about the way we weight the risk on these various projects. But one of the things that we think about though is we remain very committed to our strategy. And so, while we all measure the risk-adjusted return, we don't ever forget what we've set out as a strategy on an area. And so we're still looking for those premium returns, but we are certain that building on investments that continue to build into other assets will continue to pay dividend.
And what do I mean specifically by that? You think about a GulfStar project in the Deepwater. We make a nice return on putting that floater in place. I think the fact that we bought Marubeni alongside as they partner, and we kept a lot of the upside on that project from future tie back is evident of the solid return just from that 1 project. But what we enjoy, in addition to that, is we enjoy the downstream revenues in our pipelines, in our processing plants downstream of that. So our incremental return on a project like that is much higher. So when we think about our strategy, we remain committed to thinking about having that kind of scale where more and more investments pile along and provide higher and higher incremental return. And that really gives us a long-term advantage out there.
And just to mention a few other areas here and how we think about our capital allocation. The NGL petchem investment's an interesting area for us right now. We are convinced that the petchem space is going to build out in a very major way here in the U.S. We are so advantaged. Today, around the world, a naphtha cost, it costs into the crackers about $0.44, and the cost in on the ethane side right now is about $0.11 to $0.12. We have a huge advantage, and people are -- we have even really begin to tap the ethane resources in a lot of these locations. And so the supply is there, I will tell you that the international players are very convinced to that. And really what you have going on right now is you have the well-established majors that are here, like the Dows, the LBIs and the Exxon, they have great positions here. And they want all of this advantage for themselves, but what you're starting to see, you're starting to see a lot of international players starting to look over the top of them and look at players like Williams and figure out how they can get aligned with something like Williams who has access to these NGLs and figure out how they can grow their business. Because the only other option today is to invest in the expansion of ethylene crackers and propylene units on the back of naphtha. That is a very cost disadvantage position. And if you were in their shoes, you probably wouldn't and couldn't raise the capital to go invest in that because they're barely operating on a cash margin today, but much less making that margin to support the capital. So we're coming here and we think we're extremely well positioned to help serve that market.
Our Canadian investments continue to offer competitive advantages as well, and we'll continue. That's a pretty simple story, we've got a great competitive advantage. And Syncrude is our next and only, of the current updaters, the only one that's not contracted today. And so CNRL will come on in 2015, and then we hope to be working very quickly to bring Syncrude in very quickly after that, but very clear slate of value and very obvious how the value builds in that business.
In addition to that, I will tell you another thing we look at in our strategy -- sorry, in our capital allocation is that we look at the windows that we control. So we take the parachute plant that we were expanding and we recently decided to delay that project for several reasons but one of them is we really control that window. We can take those volumes up to our Echo Springs plant today, and so we've got plenty of flexibility there to not go ahead and build out that plant and wait till we see stronger market signals from that. But as well, again, we really control that window, and so to the degree we can't control a window of opportunity, we can delay projects rather than dismiss it.
Now looking a little bit at the areas of supply growth and how we're positioned against that, and importantly, how Access Midstream complements that as well. A couple of things here that I think are really, this is the Wood Mackenzie slide, so this is something we made up. But I can tell you, we've scrubbed this pretty well, and we think there's pretty good data supporting this. First of all, the Northeast from 2012 to 2031 on this graph is up 152% from Latin 9.4 Bcf a day to 23.4 Bcf a day in 31. Clearly making it the fastest growing area. And as you'll see in a minute, that sounds pretty incredible, but if you see what is going on there and you see the pace of development and what they've actually been able to accomplish over the last couple of years, it makes it seem very realistic.
Even the Rockies, on this graph are up 63% going from about 9.6 Bcf a day in '12 and 15.7 Bcf a day in 2031. Now a lot of people think that the Rockies are dead and there's no growth there, and certainly, we've seen a lot of rigs pull out of the area there, but we think with a more sustainable gas price like what we're enjoying right now and we think the kind of gas price, the demand that I'll show you in a minute that we expect, we'll pull, we think that the Rockies are extremely well positioned because it has the infrastructure, it has the takeaway transmission capacity and it also has the resource play in place, it's just a matter of price for the gas, and we think once that price signal is there, they'll be [ph] in production. The one area that we have trailing off here is the San Juan Basin. And in this picture, it declines about 13% between 2012 and about 3 Bcf a day. So it's not a big number against this, and I'll tell you, our team there has done a great job of maintaining our margin out there despite declining volumes.
So this is the picture, you probably looked at that last slide, and go, well that's all find and good but where is all that gas going to go and how is that demand going to pick up. And I'll tell you, it's not a very difficult picture, in fact, I would tell you, I think this might be a little conservative, particularly kind of in the '15 through '20 time period, I think we may actually see this grow a little faster because of all the activity we're seeing right now driving this kind of growth.
So one of the -- and in fact, if you look at the growth that we saw from 2009 to 2012 with 10%, you actually kind of wonder how this demand wouldn't grow even faster than this given how fast we're going to do in that period. One of the interesting pieces of this picture that I like to point out is the decline that we saw in the industrial load from 2000 to 2012 and you see how dramatically that declined during that period, but that is coming back in a very big way. That was a lot of fertilizer plants that we lost, a lot of the petchem load that we lost, but that is really coming back in a big way. And not only are we going to regain what we had in 2000, which you can see is pretty good stretch from where we are today, but we're going to go well beyond that given the amount of capital that's going into that space. We also think on the power gen side, that particularly here over the next years, we could see that actually outperform this analysis, and so I will tell you that we're pretty bullish on what we're seeing on the demand side.
And another item that I think that really is yet to hit the market and partially because we've been working so hard to overcome the economic crisis that we've had here in the U.S. But the power gen market and our ability to reduce greenhouse gases, we're the only country, only major industrialized country that's been able to lower our greenhouse gases, and it's become very important to the environmentalists that we've done and they all know that we've done that on the backs of natural gas conversions from coal. And so I think you're going to see a lot of continued pressure because people are not --- believe me, the pressure is not waning on greenhouse gases here in the U.S.. It has taken a little bit of the back seat to all the other immediate issues that we've had, but I think it's going to come out roaring, and when it does, I think, it's going to going to continue to drive a lot of gas side power generation here in the U.S.
So with all this gas supply comes a lot of NGLs, and you can see here the Wood Mackenzie picture on this, and I'll tell you that we think this is easily achievable. In fact, maybe a little conservative as well, given the richness of the gas and the amount of ethane today that is not being recovered that's out there in the markets today. And so we really think that this is all fine and good to show all the supply and I think we're all convinced the supply is out there. The question is how are we going to get enough demand built for this. And that is exactly the position we're in to help develop a lot of that demand. And I can tell you that there is a lot of money winding up, preparing for either the export side of this, but more importantly, I think, we'll be able to make higher value products out of this, we still remain very competitively advantaged and our pricing levels for the rest of the world, and we're pretty good, as capitalist, we're pretty good at arbitraging that. And I think we very much have the infrastructure in place to arbitrage that.
So now I'm going to move real quickly to the Marcellus because you'll see here in a moment, the Marcellus and Utica is a very major portion of this growth. 86% of the growth here in this period, and even in a very price pressured market, we see this kind of growth. In the liquids area now, this liquids of 446%, assumes that there is not infrastructure-constrained, so serious things like Bluegrass get built. Because if it doesn't get built, I can tell you that we don't know how that market will be served and how the supplies will feasibly be developed without something like Bluegrass. But you can see here, this, I think, is a very impressive slide. This came of our -- Western Brazil [ph] presentation, but it's [indiscernible] and you can see here, you see all this big graphs going up and strong to the right. But this is in actual, this is a forecast and it shows that the Northeast really is the place to be. When we talk about growth everywhere, but really what has been carrying the growth here for the U.S. is the Northeast and particularly the Marcellus, and now starting to develop is the Utica. And so this is pretty impressive growth trajectory. You can see here over this 2-year period, and we are very pleased to be investing so heavily into this space because we do think this is the right place to be. And speaking of investments into the space, this is a picture of our position today in the Marcellus and the Utica. It's a pretty impressive stats now. First of all, you'll notice here that we've included the acreage that's dedicated to Access as well.
So we're really trying to show what our total exposure is as Williams to the Marcellus and the Utica area. 4.7 million acres of dedication. That is an enormous area of dedication, enormous position of exposure that we have out there. You can see the great partners that we have, that we've aligned ourselves with out there. And we are extremely well positioned, there is not very much going on in this basin that we don't know about, and understanding economics behind. So we have [indiscernible] position ourselves, we have spent about $4.7 billion there through 2012, and plan to spend about $3.2 billion and again these are just waves, this does not include access. But about $3.2 billion in the gathering and processing business, and about $1 billion in the gas transmission space in the area. And I'll tell you that number is probably bigger than that given the number -- given the need for additional transmission capacity in the area. And of course that does not even include anything from Bluegrass. So we are certainly committed to the Marcellus and the Utica. We started this in about '08, and we think we made a very wise strategic decision here to go all in to this basin and we think it's going to pay huge dividends for us in the future.
This is a little set up now for the Bluegrass project. And just to explain this graph real quickly, first of all, you can see the green there is basically the liquids that really don't have a home other than to be railed or transported out of the area. So the bottom, the orange band there is the local propane demand. Now even though there is local propane demand of that amount, a lot of that can't stay up there because there's not enough storage in that market. So if it was all your load, that would work out fine. But unfortunately, some of that has to move in and out of the basin because there's inadequate storage in the basin for that propane. The rest of those projects that you can see there is about 220,000 barrels a day of ethane projects, and so the balance of that is non-ethane supply in the green there, and today, and we know this because we're one of the parties that [indiscernible] up there today, it cost about $0.26 to $0.44, all in to transport either by rail or truck and that's our actual numbers from last year that we paid in rail and truck transport out of the area. That does not include fractionation.
So you're putting a big bite into this. And I'll tell you that, that transportation cost is only going to go up because these rail loading terminals and so fort will continue to be very congested up here. And really there's a limited amount of ability with the kind of liquids we're talking about to go do that. So we've studied this for quite some time. We are convinced that Bluegrass or something like Bluegrass absolutely needs to get built up here to sustain the development of the pace that is going on up here. And I'll tell you, one of the big plans that's probably not real obvious to everybody, certainly doesn't show up on a graph like this is that it's the majors that are moving in up there. And the majors want major solutions, they are not interested in doing feasible [ph] development, they are not up there just to say, gee, we drill the well and they got a huge IP rate and therefore, our companies valued work a lot. They are up there because they really want to develop major resource basins and major reserves. They're going to go after this in a big way. And if you think about the kind of partners that we've been developing up here, it is people that are up here to stay. It's the Chevrons of the world, the Shells of the world, and they are moving in, in a pretty deliberate way, so they're not in for the fast buck but they're moving in, in a way where they can really go after this resource play. And one of the major concerns that I always hear from them is, somebody has got to deliver solution on the NGL side up here. And we've been hearing that for a number of years, and so our Bluegrass project is the answer to that.
And just real quickly, there are 3 different sections to this. First of all, the northern section, it's the new construction. And that will go down to Hardinsburg, Kentucky, going to Texas gas line, where we had interconnected with the Texas gas line. We've been working on that for about 9 to 10 months now, and pretty far along on the development of the routing and the environmental permitting requirements for that pipeline. Then Section 2 which is the conversion of Texas Gas 26-inch line from Hardinsburg down to Eunice, Louisiana. And then Section 3 which is a little bit of pipeline from Eunice over to the Lake Charles area. And then as well as a major fractionation storage facility there and potentially export there at the ship channel.
So a lot going on with this project. And we are spending some development dollars on that right now. And because we're really working hard to maintain its in-service date of 2015, which is really, really critical to the producers to be able to have an in-service day. Very pleased to be working with [indiscernible] a great job on getting support for the conversion of the Texas Gas 26-inch. And we think they've got that well in hand. And so we are -- we couldn't be more excited about the way this project is coming together. But it is big and it's risky and in terms of the permitting and the timing, it's probably the biggest challenge on a project like these days is the regulatory permitting. But we've been working this, as I said, for quite some time and we think we've got a really good handle on this at this point.
So just to wrap up here on my portion. Certainly, we are well-positioned for what we think is going to be continued strong volumes in natural gas, natural gas liquids and the olefins sector as well. And we're going to be positioned around that in a way that we are a major provider of the infrastructure and we enjoy the volume and the growth of the overall market, not just the supply side, not just the demand side, but the overall market. And then finally, we certainly have the capabilities to continue to deliver these projects. We get asked a lot about why you guys have got so much projects, are you sure can handle all these projects. And I'll tell you, we have a terrific team who had delivered a lot of projects where others haven't been able to, on-time and on budget, the pipeline that we delivered in Canada came in below budget and right on schedule.
The BP supporter that we built in Canada not too long ago also came in below budget, on schedule, the major Gulf Deepwater pipelines that we've build out there. So we have a tremendous amount of experience, Transco continues to build and deliver its projects, and it has many, continues to build and deliver all of its major projects on time and on budget. So pretty excited about the position we're in and you're going to hear a lot of excitement from the management team today about the kind of opportunities that they're seeing in their area. And with that, I'm going to turn it over to John and Randy.
John R. Dearborn
Well, good morning, everyone, and it's my great pleasure to be here speaking to you as a new employee of Williams. Our discussion this morning is segmented into 2 parts. In the first, I'll provide some proof points that we really believe that there remains great potential in this operating area, providing infrastructure at the intersection of energy and petrochemicals. And further, that Williams is well-positioned to be the sought-after provider of NGL & Petchem Services. I'll then pass the baton over to Randy Newcomer, who'll describe the projects, but more importantly, the solutions that we're putting in place to serve this industry. Within a few days, Randy will pass the baton back to me as he winds down his illustrious career and he transitions to his new adventure.
First off, let's take a look at the market for ethylene. This market is amazing as I've watched it over the 30-plus years of my career. The ethylene market always grows, but perhaps goes from dips from time to time, but always steps back on to its growth pattern. That's normally a small multiple of GDP globally and locally, the GDP multiples can vary from place to place. But today, recent forecast say that the market is growing at about 3.8%, now this is ethylene that winds up in derivatives that gets shipped to derivative customers. Importantly though, what we all need to remember is over the next 10 years, the world will need 58 million new tons of ethylene capacity, and the feedstock to feed those machines. If we translate that capacity figure into ethylene plants, that's between 40 and 50 new crackers depending upon their individual capacities. Interestingly, on this graph, the green bar calls out the growth in the U.S. market, which today is growing at about 4.1%. But let's look a little more deeply into that.
If we look at the actual growth in the domestic market, the market is only growing at about 2.2%. While ethylene produced for the export market is forecast to grow at between 9% and 10% annually, and in that way, yielding the composite growth rate of 4.1%. So what do we conclude? Well, the first thing's obvious, North America is taking global share; and the second, very interestingly, is capital is rolling back to North America in the petrochemical world. But why and for whom? Well, there are really only 2 sources of feed stocks, Alan mentioned both of them earlier for ethylene production. Ethane, the byproduct of gas production; and naphtha, a byproduct of the refinery and a component of the oil barrel. Prospects for advantaged ethane in the Middle East, which had been taking share for the last few decades, are slowing as their petrochemical industry matures. That leaves, for the immediate future, U.S. ethane, China coal-to-olefins and additional in-market liquid naphtha cracking to satisfy the global demand in countries like China, India, Brazil and other high-growth economies.
This then brings us to the next point to make on the same slide. So as long as we can see naphtha remains a dominant feedstock for ethylene. Essentially pegging ethylene places to the naphtha value, and of course, the price of the oil barrel. While ethane is expected to be in excess supply and will remain a cost advantage feedstock. That bodes well both for investments in pets in North America, our home territory, and for the Williams guys with cracker.
To conclude the analysis, let's now look at ethane supply in the U.S. which, by our analysis, and this is a slightly different analysis than you may have seen in prior presentations, shows the expected growth of ethane in barrels in a rather unconstrained market, which of course our company is looking to accomplish. I don't know exactly how or exactly when, but sometime into the next decade, we expect that ethane should grow to about 2.4 million-barrels per day as the unconventional oil and gas production matures into the early part of the next decade. Taking into account the expansion and conversion of existing ethylene plants, and the new plants that we're all very well familiar about that are expected to be built in the coming few years, this brings ethylene demand to just about 1.8 million barrels as represented by the bold red arrow on the chart. This data would imply then that there's sufficient ethane to work crackers in North America. Perhaps, as many as 6 crackers in the 5- to 15-year time frame. I believe the data is compelling. And that North America, again, becomes an export hub to satisfy global demand.
So what are our aspirations? How does Williams expect to capitalize on this eventuality? But first, we are an unbiased and transparent broker connecting both the supply of NGLs to the demand of olefins. We don't own the feedstock, and we also don't compete in the marketing of derivatives. We bring skills and capabilities in the operation of olefins unit into required infrastructure both upstream and downstream from the olefins unit. Furthermore, and you'll hear more from Randy, we're developing open access solutions for signature logistics of olefin products, but heretofore has been reserved by the existing players as proprietary. These capabilities and solutions will bring value, of course, to future potential Williams investments. But also, will bring capabilities to existing customers and existing demand in North America as that ethylene demand attempts the back entry. And importantly, we'll bring knowledge and confidence, valuable to new entrants, wanting to connect advantaged supplies of derivatives here to their growing global demand markets. As a result, we believe Williams is well-positioned to be the partner of choice in this growing industry. I'll be back for questions in a moment, but for now, I turn the podium to Randy.
Randy M. Newcomer
Thank you, John. This map shows an overview of the infrastructure we operator have a ownership position as NGL & Petchem Services. This is the asset base we are building on to connect the increasing supply of NGLs that you heard Alan and John described in North America. Our operating area here phases with the other 3 operating areas, within Williams. In that we further handle the liquids that are produced and seek to connect those liquids to the markets of highest value, either for our upstream customers or for ourselves in the case of our own equity liquids. And that also shows the basin in shale plays in which we currently operate and collect or collect liquids today, and that doesn't include any additional areas that are included in the access footprint which you'll learn more about this afternoon.
As you can see, we're currently gathering natural gas liquids from our U.S. gathering and processing businesses in Southwest Wyoming, the Four Corners area of Colorado and Mexico, the [indiscernible] area in Colorado, the Gulf Coast and the Northeast. In addition, our Overland Pass pipeline is receiving liquids from the Bakken shale in North Dakota, via a third-party pipeline that transports those liquids to the Mid-Continent. Emerging areas liquids production for which our Conway assets are also well positioned to handle in the future is the Mississippi line play in Oklahoma and Southwest Kansas. We provide a number of services to our customers. First of all, we provide long-haul transportation of raw mix liquids, sometimes called Y-Grade via pipelines like our 250,000 barrels a day Overland Pass pipeline and the proposed Bluegrass pipeline from the Northeast to the Gulf Coast. And additionally, we provide fractionation services to turn that Y-Grade into finished products, purity products such as ethane, propane, normal and isobutane and C5+ natural gasoline. Our joint owned Conway fractionated can handle up to 100,000 barrels a day of Mid-Continent liquids.
We also provide underground storage services at Conway. We have over 180 storage wells, storage caverns at our Conway facility with a storage capacity over 21 million barrels. Our distribution services at Conway includes both truck and rail, loading and unloading, and is well-connected to the pipeline infrastructure. On the demand side, we operate a joint-owned 1.3 billion-pound per year ethane cracker at Geismar, Louisiana. We also own a propylene splitter at Geismar that purifies purchased refinery grade propylene and turns it into about 450 million pounds per year of polymer grade propylene or PGP for short. We've assembled some pipeline and storage infrastructure in the Gulf Coast that we are building into a robust petrochemical services business, which I'll highlight a little later.
In Canada, as Alan mentioned, we have a unique business that processes off gases. From huge bitumen upgrading facilities in the Alberta oil sands near Fort McMurray. The liquids extracted from this off-gas streams are very rich in NGLs and olefins, and we've made some great progress in growing this business in the last couple of years, and I'll highlight that a little later as well.
With that introduction, I'm going to take you through a tour of what we see as exciting developments and projects that we have going on in NGL & Petchem services in an era that we believe will become a Renaissance in the U.S. petrochemical industry.
Our first stop is our guys in our Louisiana ethane cracker. As John noted earlier, we believe that ethane will be advantaged feedstock for the foreseeable future based upon its low price relative to naphta. The growth in global demand for ethylene will keep us price well correlated to crude-based naphtha rather than ethane, natural gas-based ethane. In spite of the increased demand for ethane that comes with new ethane crackers and cracker expansion, there'll still be lots of supply, beyond what is being recovered today. We expect that trend to continue as producers continue to drill in liquids-rich basin. Long story short, we expect to see continued strong cracks between ethylene and ethane prices. As you can see from this slide, ethane prices are currently riding on top of the natural gas price on an equivalent basis. This is obviously great news for our guys at our cracker who has been enjoying record earnings at Geismar over the past couple of years as a result. And we believe that our strong earnings performance at Geismar will continue.
I do want to point out that a lot of pricing scenario here provides for 0 or little ethane margin for our gathering and processing businesses from overall Williams perspective, we actually are exposed to the margins to the natural gas and ethylene for equity ethane production, I guess, cracked at Geismar. With ethane recovery margins improved relative to natural gas and Geismar crack margin might suffer a little but, but we'll more than make up for it at our gathering processing businesses and our volume-dependent assets like Overland Pass.
We really like our strong cash flow position at Geismar, Geismar's ability to hedge WPZ's ethane margin risk. We like it so much that we are currently in the process of expanding our Geismar cracker by about 50%. The 600-million pound expansion will bring the plant capacity up to over 1.9 billion pounds per year of ethylene production, which will consume about 57,000 barrels a day of ethane. This incremental ethane consumption will take WPZ from a net-long ethane position when in full ethane recovery to a balance to net short position going forward. The expansion will also improve the economies of scale of the plant, which will lower the per-unit ethylene costs. Our joint owner in the facility at Geismar has chosen not to participate in the expansion, which will increase our ownership in Geismar from about 83% to about 88% post expansion. The expansion tie-ins will be completed during a plant shutdown for turnaround that will occur late summer this year and the expanded plant will be commissioned and placed into service shortly thereafter in early fall of 2013.
As I mentioned before, we chose to put this project on the fast-track because of the record ethane crack spreads, and we believe our project will beat other expansions and new build projects into production and that will give us a head start and an opportunity to supercharge our return. Because of the fast-track nature of the project that was sanctions prior to having complete detailed engineering definition fully expansion and the planned expansion of existing plant is much more complex, more complicated than a new [indiscernible] plant because of the need to tie it into existing processes and utility infrastructure. This complexity has been evident in this project and cost have escalated somewhat as the engineering definition has been completed. However, that's been done now, and actually the project economics are better than they were when it was originally sanctioned in spite of the increased cost due to the strengthening of the fundamental of margins that we are seeing today and expect to see over the next several years at a minimum.
The next stop on our tour is the Canadian oil sands. We have a very unique business in Canada, and it's so unique that nobody else is doing it. In Canada, there are number of companies that are coaching heavy crude oil out of the oil sands, either through mining and extracting it physically or in situ injecting steam into the formations and melting it and pumping it out. This heavy oil is typically called bitumen and it must be further processed to convert it to something that a typical oil refinery can handle. The further processing of this bitumen is called upgrading, and there are 2 stages of upgrading that are typically employed. Primary upgrading involves either a delayed or fluid bed coking process that cracks up the long molecules of the bitumen into shorter molecules. And in aggregate, they are in the boiling range that is typical of refinery grade crude oils. So hence, it's called synthetic crude oil. Second stage of upgrading typically involves taking the raw synthetic crude oil and further hydroprocessing it to remove nitrogen and sulfur compounds and make it into a premium quality product.
The first stage of upgrading, the cracking, initial cracking, that provides the off-gases that we are after in our Canadian business. This upgrade of our off-gas, as I mentioned, is very rich and typical NGLs like ethane, propane and butanes, but it also contains the corresponding unsaturated molecules like ethylene, propylene and butylenes, which have a much higher value than the saturated NGLs.
In this slide, you can see the margin on a dollars per million Btu basis between Alberta natural gas price there at the bottom and U.S. Gulf Coast NGL to olefins. And you can see that propylene is at the top of the value chain here, and it is propylene that provides us with the biggest value driver in our Canadian business at present.
The other thing I'll note here is that similar to the slide we look at, when discussing Geismar, you see that there's very little to know margin and ethane recovery today in our forecast for the next couple of years. But because of infrastructure constraints in Alberta, it is short of that [indiscernible] despite the ample supply that is available to the U.S. Gulf Coast. One of the projects that I'll describe in a minute targets the recovery of ethane for NOVA Chemicals to feed our Alberta cracker at Geoffrey. Our contract with NOVA provides for floor price for ethane that is based on natural gas price plus a fee to ensure a new ethane supply force for its business.
Our Canadian upgrader off-gas business has grown significantly from its infancy in 2004. And I was there to see that happen. We currently have one cryogenic off-gas processing plant adjacent to the large Suncor upgrader complex in Fort McMurray. We process around 120 million standard cubic feet per day of off-gas at this plant to produce about 16,000 barrels a day of mixed propane+ liquids. When you do the math, that equates to a very rich 5.6 gallons of propane+ liquids for 1,000 cubic feet of off-gas. When we add ethane and ethylene recovery to the equation, that number goes to about 9 GPM, again, very rich when compared to natural gas. The [indiscernible] liquids from Fort McMurray are transported to our Redwater processing complex via the new Boreal pipeline that was completed and put into service in 2012. As currently configured, this new pipeline can handle up to 43,000 barrels a day of raw mix liquids. With additional pump stations, Boreal can handle up to 125,000 barrels a day, so there's plenty of room to grow our business out of Fort McMurray. However, at our processing complex includes the fractionator that separates the raw mix into 3 basic streams: A propane propylene mix, a butane butylene mix, and a residual pentane plus mix. Polymer grade propylene has been produced by splitting the propane propylene mix in a very tall purifying tower. The butane butylene mix is also further upgraded by spitting off the normal butane and then selectively hydrogenating the material to produce the premium-grade feedstock for refinery gasoline production process called alkylation. The production of PGP and alky feed, as we call it, provide very significant margin enhancement to our Canadian business, which has grown to be a very strong profit contributor to Williams starting from very meager beginnings in 2004.
So where do we go from here? Our focus now is on expanding our processing volumes to recover in aggregate more liquids out of Fort McMurray. This will also increase our utilization of the investment that we just made in the Boreal pipeline. And in addition, we'll be recovering an ethane stream for our petchem customer and pursuing a project to produce more polymer-grade propylene beyond the volumes that can be recovered directly from the off-gas.
There are 3 large upgrading complexes in Fort McMurray -- in and around Fort McMurray that produce rich off-gas today. One of their current producer customer, Suncor, which has been commercially producing synthetic crude oil in the oil sands since 1967.
Suncor currently produces about 350 million barrels per day of synthetic crude oil and we are currently processing substantially all of the-off gas available from their upgraders. The second complex is Syncrude, which Alan mentioned, which is owned by a consortium of partners including the Canadian Oil Sands partnership, Imperial Oil, Local Energy, Murphy Oil, China Tech and Suncor. This Syncrude upgrading complex currently produces about 300,000 barrels a day of synthetic crude oil and has been operating since 1978. The third and newest operating complex in Fort McMurray is owned by Canadian Natural Resources Limited or CNRL, one of the largest independent crude oil nor and natural gas producers in the world. The first phase of upgrading capacity was commissioned at CNRL's Horizon Complex in 2009. CNRL currently produces about 110,000 barrels a day of synthetic crude oil, but has plans to expand that to 250,000 barrels a day over the next few years. So you can see that we are dealing with some very substantial and long-term off-gas producers.
In 2012, our Canadian team executed a long-term agreement to process the upgrader off-gas from CNRL's Horizon complex. Our project to process is off-gas has been sanctioned and will include a number of subprojects around both Fort McMurray and our Redwater processing complex. This subcontract -- these subprojects include a new cryo plant at the Horizon Upgrader, a 40-mile pipeline lateral from Horizon to our existing Boreal pipeline and an expansion of our olefins fractionator at the Redwater complex. The project will initially recover about 12,000 barrels a day of ethane plus liquids, but will be designed to handle CNRL's increased off-gas production as it expands its upgrading capacity. And these facilities are expected to commissioned in mid-2015 at a cost of $500 million to $600 million.
Our second highlighted project is the recovery of ethane from our existing cryo plant at Suncor upgrader, and modifications to our Redwater processing complex to separate out this ethane stream that I talked about to deliver to the NOVA Chemicals under our long-term sales agreement. Our total production of ethane from both Suncor and CNRL is committed to NOVA under the sales agreement up to 17,000 barrels per day. Again, there's a contractual floor on this contract that it said if natural gas price plus a fee, so there is some project return protection in it plus upside, if the market for ethane increases substantially in the future. The project is in the final stages of the construction, and is expected to be commissioned in late summer this year at a cost of between $450 million and $500 million.
With the completion of these 2 projects and a considerable amount of work done by our Canadian team to improve the reliability of our existing operations at Fort McMurray, our liquid volumes in Canada are expected to triple from our 2012 levels of about 12,000 barrels a day by over the next 2 years to about 37,000 barrels a day by 2015. This growth is represented by the blue bar segment on this graph. Again, this volume increase wouldn't be too exciting if it only included the typical NGL products, but it's the volume growth in polymer grade propylene, alky feed and the long-term sale of margin-protected ethane that will drive our financial growth in Canada in the future.
With the CNRL agreement, we now have off-gas processing contracts in place with 2 to 3 major upgraders around Fort McMurray. And, as Alan said, we're pursuing and will continue to pursue Syncrude and believe we're in a strong position to process that off-gas as well should they choose to work with a third-party to do so. As you can see from the green bar segment on this graph, our recovering liquids from Syncrude off-gas would roughly double our production again from 2015, when there is a 37,000 barrels a day to over 75,000 barrels a day.
Now I'd like to highlight a Canadian opportunity that very much compliments our off-gas business but also goes beyond it. This graph from IHS illustrates the impact of the industry's conversion from heavy-feed crackers to light-feed crackers in the United States and Canada. Because of the compelling economics associated with ethane cracking that was noted earlier, many, if not all, of the heavy oil crackers in North America have converted some or all of their feedstock to cracking ethane. And this isn't something that can be done with the flip of a switch, but rather it requires plant and infrastructure modifications to accomplish. Olefins producers have been making this investment over the last several years. And this has had a very significant impact on the volume of propylene that is being produced as a byproduct of the cracking process. Heavier feedstocks like naphtha and gas oil produce more propylene. Lighter feedstocks like ethane and propane produce less propylene. But the demand for propylene hasn't decreased. In fact, it continues to grow globally by about 4% a year. The supply of propylene in North America from crackers though has shrunk by about 40% in the conversion to like feed. And because our crackers aren't producing enough propylene, a window of opportunity has opened up for other on-purpose processes to produce propylene to fill the gap. One of these on-purpose processes called propane dehydrogenation or PDH for short. PDH is different in that it isn't a cracking process but rather a catalytic process that facilitates the removal of 2 hydrogen atoms from propane to produce 1 molecule of propylene and 1 molecule of hydrogen. While propane cracking produces a small percentage of propylene as a byproduct, PH is very highly selective and yields a very high percentage of propylene, from propane, somewhere over 90%. So much more selective to propylene. The biggest margin maker in our current off-gas business is propylene, as we've discussed, and is represented on the slide as the off-gas margin. Our off-gas business currently recovers and purifies about 150-million pounds per year of PGP from the Suncor off-gas. Once our new cryo plant is commissioned at the CNRL upgrader, our off-gas recovered PGP volumes of growth of about 250 million pounds per year. All of this propylene is currently transported by rail to the U.S. for sale to downstream customers that use the PGP and feedstock for their propylene derivative products.
Our off-gas business also recovers and produces a significant volume of propane. About 7,000 barrels a day today. With the ethane recovery project and the commissioning of the cryo at the CNRL Horizon upgrader, our propane production is expected to grow to about 13,000 barrels a day. Propane recovery economics are obviously not as good as propylene recovery economics in our off-gas processing business, as you can see from the spread here between the blue natural gas line on the bottom and the next line which is the green line, the propane line. Unlike propylene though, propane is fundamentally in a supply surplus position in North America, including Canada, with the wealth of propane that's being recovered in natural gas processing. This is to press propane prices significantly in North America and push significant additional discounting back into Canada. Like the propylene, though, the book of our current propane production in Canada is being exported via rail to customers in the U.S. This gets us up very nicely to pursue an opportunity to capture the significant spread between propane and propylene that is shown on this slide as the PGP/C3 margin upgrade over here on the right. This additional margin will be captured via our PDH project.
Our Alberta propane dehydrogenation project will convert about 22,000 barrels a day of Canadian propane into 1.1 billion pounds per year of PGP. With the additional 250 million pounds of the PGP that comes from the off-gas, we'll have a total of almost 1.4 billion pounds of PGP sales once all of the projects are completed. As I mentioned earlier, we will be supplying about 13,000 barrels a day of the 22,000 barrels a day of propane feedstock that's required from our own production in Canada. So the PDH provides a nice hedge for our propane market exposure as well. The incremental 9,000 barrels a day will be purchased locally, while there is ample supply available via a wide grade fractionator that's next door owned by Pembina at Redwater or via pipeline from other sources.
Now our base case plan assumes that all of our PGP production will be railed to customers in the U.S. As I mentioned, we already rail all our PGP and all our propane from this complex, so we're basically turning it all to propylene and shipping it out so the volume of [indiscernible] doesn't actually go up that much. But we're planning our infrastructure investments to ship it all out. However, our Canadian team is engaged with a number of international derivative manufacturers that are very interested in developing or codeveloping facilities near our PDH unit to turn it into derivative products nearby. While a companion derivative's facility would be a value enhancement to the PDH project, it's not necessary to achieve a base case project economics. The project is currently being conditionally sanctioned and it's in the beginning stages of engineering. And as you can see from this photo, a site for the PDH has been secured that is adjacent to our existing Redwater complex, and is well suited for our purposes. The project is expected to cost about $900 million, and is targeted to be completed in mid-2016. The project will be funded primarily from international cash-on-hand and our Canadian business cash flow.
Our final stop on the tour is the back in the U.S. Gulf Coast. I'd like to finish up by talking about our emerging Petchem services business, where our team has been working very hard to bring to reality the vision of open access infrastructure solutions to the petrochemicals industry. We believe that the petchem industry has been historically underserved from an infrastructure perspective for a number of reasons. Some of this dates back to the 1960s in the first wave of petchem investment built upon cheap natural gas and natural gas liquids. The work midstream players like Williams around back then had an infrastructure development as their core business. Additionally, some petchem players pursued a strategy of controlling infrastructure in the belief that it would provide a competitive advantage for their crackers in derivative products. Over the years, this has resulted in an efficient utilization of pipeline and storage infrastructure for the haves, and a high cost for access to infrastructure for the have-nots. We knew the time has come for a new model and we are encouraged and excited about the customer reaction to our projects. With some existing pipeline and storage infrastructure that we control today to supply our Geismar cracker with ethane volumes, and some additional in-service and idle pipelines that we've acquired from others recently. Our Petchem services team has developed a series of projects that we expect to be well received and well subscribed to by our present and future customers.
First of these projects is an ethane pipeline expansion undertaken by WPZ that will not only provide additional ethane volumes that will need for our Geismar cracker expansion, but will also provide some additional capacity to transport ethane to other customer facilities stretching from Mont Belviue in Texas, to the Mississippi River in Louisiana. This project's being built in stages. The first stage was recently completed to transport ethane from Mont Belviue to a customer in Port Arthur. First deliveries of ethane to this customer were made last month, and will continue to be made under long-term transportation and supply contracts. As you might expect, our build up of this project will also be integrated with the proposed Bluegrass pipeline project that Alan talked about briefly, which will add additional NGLs in the Lake Charles, Louisiana area. So as that project comes to fruition and is better defined, we will integrate our activities with that as well. Our second project is the Texas Belle pipeline, and this project has now been fully sanctioned by WMB and will transport isobutane, normal butane and natural gasoline to customers in the area of the Houston ship channel. We've executed a baseload contract with an anchor customer, and are finalizing shipper commitments with others. The last 2 projects highlighted haven't yet been sanctioned but are certainly in serious developments. Our Promesa project involves an expansion of our ethylene hub at Mont Belviue, an additional ethane pipeline infrastructure to expand the distribution network to and from the hub. As you may or may not know, Williams has been working for years to bring transparency, more transparency and liquidity to the ethylene market and have achieved some degree of success in this regard through the establishment of the ethylene hub. In fact, Williams hub is now a primary pricing point for spot ethylene purchases and sales transactions executed through CME.
The industry has seen the benefits of having a more liquid ethylene market and we want to continue to expand our ethylene infrastructure around our hub to enhance that. We also want to bring the benefits of transparency and liquidity to the propylene market. Just as we have with ethylene, we'd like to establish a propylene hub, and our Jack Rabbit project does just that. We're working with the customers and suppliers to build a propylene transportation network and storage hub that will connect propylene producers and consumers along the Texas and Louisiana Gulf Coast. Our plan is to have all these projects in service by late 2014 or early 2015.
These projects form the foundation for a new fee-based business focused on connecting the growth and supply of NGL products that will come from or newly abundant natural gas resources with the needed growth and demand to balance it. And we believe that providing open access infrastructure that connects the best market options for our customers is the key to success.
Williams has invested over $240 million in this business to date to acquire some existing pipelines. Some of these pipelines are already operational and generating cash flow today while others are being pieced together but delivering investments to complete the 4 projects I highlighted a few minutes ago. We intend to invest a significant amount of additional in-guidance capital in this business over the next several years and expect to garner mid-teen base returns on these projects with significant upside. Our focus will initially be on the Gulf Coast over the U.S. but there may be other opportunities to invest elsewhere as well as we see where our petrochemical customers choose to build.
As you can hopefully tell from my presentation, we have some grand plans for NGL & Petchem services. It has to be grand because we truly do see the coming of a Renaissance in the North American petrochemical industry. This Renaissance will spring from the abundant and low-cost supply to natural gas liquids that are produced and will be produced in existing and new basin throughout the U.S. and Canada. Serving the upstream NGL producing customers and the downstream NGL consuming customers from these basins will require new infrastructure structure and a new way of thinking about infrastructure. It will also result in new petrochemical plants being constructed to produce olefins and derivatives of olefins in products like polyethylene, polypropylene, PDC, glycols [indiscernible] and many other petrochemical products that will likely be destined for export, as John mentioned. Much of this will probably be exported, but that's good for our business. We want to be the infrastructure provider of choice and leverage Williams strategy and bring its market opening large scale capabilities to the NGL & Petchem service and sector.
Finally, we think about -- we think that we have a compelling growth story from a financial perspective as well as can be seen from this slide. Now our NGL & Petchem services operating areas spans both WPZ and WMB. The primary driver of our WPZ growth is the Geismar cracker expansion with some fee-based contribution from our ethane pipeline system expansion, and you can see the CapEx guidance there on the right that shows significant drop-off in capital required post 2013 due to the completion of the Geismar expansion. The primary drivers in our WMB growth, our Canadian projects, along with contributions from our fee-based Petchem services projects as they already in the U.S. Gulf Coast as well.
So in summary, these are the key points, key takeaways. We believe that Petchem fundamentals do support the U.S. reemerging as a global supply hub due to the advantaged feedstock position that U.S. will have. WMB and WPZ are well positioned to capitalize on this in the liquids space. We'll fast tracking the Geismar cracker expansion project to capture those record high margin and balance our ethane position. Our unique Canada business has shown steady growth and we've got a lot of things lined up there that we're going to continue that. And the PDH projects, we'll build on that, enhance that as well. We are bringing our market opening large scale capabilities to the NGL & Petchem services sector. And the result of all that will be strong growth, cash flow growth for both WMB and WPZ from the NGL & Petchem services operating area. So with that, we'll open it up for questions that you might have for either John Dearborn or me.
The first question is on Slide B-8. You have the forecast for ethylene price. And I guess, just 2 quick ones on that. What do you think is the biggest risk to ethylene prices not staying where you have them in 2014 and 2015? And if they were to decline, what do you think is going to, in your view, the bare case price for ethylene?
Randy M. Newcomer
Well, again, as John mentioned, we believe that the ethylene price will stay strong because of the huge P70 global ethylene production that is tied to NAFTA. NAFTA is primarily produced from crude oil and so as long as the crude price, the crude-to-gas price stays -- spread stays wide, we believe the ethylene price will be supported by that, plus the growth in ethylene demand will continue as well. So we don't see a significant risk of significantly lower ethylene prices going forward. John, did you have anything you want to add to [indiscernible]?
John R. Dearborn
No, nothing further. I completely concur with Randy, it is really all a matter of what happens to oil over the coming quarters. And that's the call I think we all need to make as to that impact on NAFTA and the result in ethylene margins.
And then one quick follow-up. Alan, you'd mentioned the -- in terms of, and I don't know if I caught the number right, in terms of what was the cost to kind of rail and truck in the Northeast like you have mentioned in the cost and...
Alan S. Armstrong
It's [indiscernible]. So $0.26 to $0.44 is what our actual cost range from last year for barrels that will transport it out on our behalf.
Faisel Khan - Citigroup Inc, Research Division
Faisel Khan with Citigroup. If I can just ask the last question in a different way. When you take into account the value of the co-products you get out of the NAFTA cracker and the value of the coproducts you get out of an ethane cracker, what were the gas ratio, the tipping point start to take place when we were at the [ph] advantaged shift back to the NAFTA cracker?
Randy M. Newcomer
I don't know the specific tipping point of that. I guess I would just say that it would be significantly -- at a significantly lower -- significantly higher ethane price or significant lower NAFTA price to make that happen, otherwise, you wouldn't be seeing every cracker in the United States being converted. The driver is so compelling between 20-some cent ethane and 40-some scent NAFTA that would be -- can take us -- and still don't move in order to make that happen.
Faisel Khan - Citigroup Inc, Research Division
The value proposition here said you're going to take market share away from NAFTA crackers, right? I mean, that's the proposition here. I mean, that -- to really export market, you have to take that market share, right? I mean, that's how...
John R. Dearborn
No, it's really not the case. I really don't think that's not the case. And that's the amazing thing about the market for ethylene. The market for ethylene year-upon-year tends to grow at about 3%, 3.8% and you continually need more crackers. So if you follow the logic of perhaps the first couple of charts that we presented, the globe over the next 10 years will need about 30 to 40 crackers, right? We are today building somewhere on the order of 5 or 6 in North America on the back of our advantaged ethane. There's perhaps 1 or 2 coming up in the Middle East so there are mixed-feed crackers. So the less of the cracker demand or the rest of the ethylene demand will be satisfied by either coal to olefins in China, which has a very low variable cost of operation but a huge capital hurdle to overcome to build it in the first place or it will be NAFTA on the increment built probably in market, whether that's in India or whether it's in China parts or whether it's in another part of the world. So no, I don't believe that our ethane crackers are competing to take share from NAFTA. It's just a question of what that growth profile looking forward, how many ethane crackers get built, how many coal to olefin plants gets built, how many NAFTA crackers get built in the long run.
Hi, this question is for Alan. Just going back to the charts in A-8 and A-9 and [indiscernible]. It looks like right now, putting aside whether the gas markets are in balance, we have a $4 price right now. But just going out even to 2020, it looks like there's a 10 Bcf differential in supply and demand, and that continues right up to 2020. And I know you're optimistic when it came to the demand side. I'm just curious, how much have you factored in the potential for the export factor that we're starting now? We have 2 facilities that have been quasi-approved once they're waiting for the FERC. And how much do you think that, that can grow to, what impact that might have if it doesn't come to fruition on the price of the gas and reverse some of this?
Alan S. Armstrong
Yes, this plan had, I think, right at about 9 Bcf a day of export built into it. And so I would tell you that could probably grow quite a bit larger. Again, I think the challenge is going to be to see all of this move in lockstep. There's plenty of market to move into, but we need the supplies to come with it, we need the prices to stay strong enough. So that's why I'm actually very encouraged with the kind of pricing levels we've got right now in natural gas, because at $3, we wanted to keep the supply coming to have people's confidence in that happening. I think, at these pricing levels, we'll see growth across the market. But I think this forecast has about 9 Bcf a day of LNG export built into it.
We've got [indiscernible] upfront here. Go ahead.
Okay. I had a question on Bluegrass pipeline project. The rate on ATEX, which is an existing -- or I guess, comes online in the first quarter of '14 is about $0.15 a gallon. And there's talk about changing the scope of that project to potentially carry propane as well. But what I wanted to understand was, do you believe Bluegrass has the ability to provide producers a better value to customers and still earn an attractive return on capital at that kind of rate? And then, also, are producers willing to sign long-term contracts on capacities to support this project moving forward, even with incremental capacity on ATEX still available?
Alan S. Armstrong
First of all, we think we can compete very easily with that $0.15 rate. And secondly, I would say that the long-term contracts and what producers are willing to commit to there are structures would be one where if we've got a dedication from the plant or so forth next [indiscernible] done in the Rockies where it's not volume commitment but dedication from plant, that we'll have a fairly -- a higher price, not -- quite a bit higher tariff. If somebody's willing to make a kind of commitment that ATEX has where the ship would pay kind of contract, then we'll have a lower price and we can certainly compete with that pricing level if it's a firm commitment for transport.
I had a question about the ownership structure of the NGL services business, the Canadian business and Bluegrass. I think you've guided that you have $300 million of EBITDA in the Canadian business and NGL services in 2015, then you have a PDH plant coming in 2016, potentially, Bluegrass on top of that. Conceivably, you could have $1 billion EBITDA business at the parent company. How do you think about ultimately owning that business at the parent company versus owning it at WPZ? As WPZ gets through its major capital projects, do you see Bluegrass, PDH, Canada, NGL services being candidates for drop-down into WPZ over time?
Alan S. Armstrong
Yes, I think, certainly, those are options for us and we certainly have included that. But I think they'll make great candidates for that in the future. And I would just say we've got so much growth right now in PZ that we certainly don't need that, but we certainly like the idea of building a warehouse and drop-down candidates for PZ in the future, and I think, exactly what we're accomplishing right now.
What's the limiting factor in terms of getting the assets from the parent company into WPZ and kind of recreating the pure play GP at the parent company?
Alan S. Armstrong
I don't know if there's any limitations to that, but frankly, as you know, PZ is pretty full right now. We've got about all it can take on the balance sheet right now in terms of growth. And so I think it's just a matter of time likely toward that option available to us. And certainly, there's no reason to bring that complexity to bring in the Canadian assets in their -- to WPZ right now.
As an addendum to that line of questioning, as you think about future drop-downs in your multiple projects, assuming, for the sake of argument, Canada's not going to be dropped down, but maybe you'd like to correct me on that, is there anything in terms of timing with respect to the size of drop-downs that can really move the needle that we should keep an eye out for? You've got some multiple projects going on at the MB level that individually may not be as great outside of Bluegrass but collectively may be worthwhile. So how should we think about that in terms of 2, 3, 4 years down the road?
Alan S. Armstrong
Well, I do think your time horizon and maybe the 3 to 4 years is the right way to think about that. But again, right now we've got all the growth that PZ balance sheet can really stomach right now. And so I think we're well positioned to just continue to grow PZ, can continue to incubate great cash flow projects for the future for them to move.
John R. Dearborn
So perhaps just to add to Alan's comments. Again, I think, we believe that using WPZ's capital capacity to seize third-party opportunities rather than drop-downs is the smart way to play it. However, as those opportunities lessen or if there's a dip in the road, if you will, and we have some excess capital raising capacity at WPZ, I think that would be the kind of time that we would look more seriously at a potential drop-down. So I think as Alan mentioned, we are building a very large portfolio of assets that could be dropped down. We don't see a rationale for anything in the very near future. However, it's great to have the inventory, if you will, of assets that can be dropped when WPZ has the call to financial capacity without sucking capacity away from its ability to grow its business during this time where we need to continue to invest in assets to strengthen our long-term positions.
Question on Bluegrass. You mentioned that you're working very hard to meet the late 2015 in service date to meet needs of producers. What are some of the key near-term milestones you need to hit to stay on that schedule?
Alan S. Armstrong
We have, first of all, finalizing agreements with Boardwalk, and I would say we're getting very close on that. Secondly -- so that's first item. Second, we have teams in the field right now doing the environmental surveys and permits particularly on that Section 1, that Northern section, and that's critical to staying on time. And then the next thing is very quickly maybe even here in the next couple of weeks, we'll be having the exposed, meaning the shippers to the tariff. We've been in the process of getting those approved for the FERC. And so we're about done with that process, and then, we'll be putting that load out to shippers. The good news is we've had shippers really wanting to see those and a lot of interest in us having. We can't really -- we couldn't just talk numbers without having the details about the tariff and what the obligations would look like on their part, and so that's what we've been working on.
And then, I think you mentioned on your earnings call that there's roughly $2 billion included in the potential CapEx for Bluegrass and not in the plant within the potential market. Does that include amounts for potential LPG export capacity as well?
Alan S. Armstrong
That does not include the LPG export, but that I would tell you that's pretty modest amount compared to the overall project. Because of where we're locating -- some were even locating in a safe place along the dockside where we've got the ability to transport out of.
Let see, I want to get the back to the NGL petchem specifics, maybe one more question, then we'll take a -- maybe we'll take a break. So let's do one more question. Maybe something for Randy or John? We're going to have lots of time at the end of the day to ask questions to Alan and Don specifically. So anything else for Randy or John?
Real quickly right here. This relates to Slide B-18. You have a proposed storage, a proposed frac and a proposed dock. Could you put some parameters around that when you're thinking it might come online? And then I assume the $500 million you referenced on the next slide does not include those.
Randy M. Newcomer
Well, really, this is -- what you see there on that slide is really the Bluegrass. It's really the terminus of Bluegrass. And you'll see the blue coming down the proposed dock and frac are -- those that are associated with Bluegrass. So it's not something in part from that. Alan just spoke to that. It just happens to be shot on this slide.
Alan S. Armstrong
But it's not -- that $500 million is totally separate. That is developing that petchem service systems like Texas Bell that Randy referred to.
Randy M. Newcomer
Right, it does not include anything Bluegrass-related.
Okay. Well, let's plan on trying to resume at 10:50. It's about 10:30. That'll be about a 20-minute break, and then we'll come back with Frank Billings with the Northeast. Thank you.
All right, I think we're going to get started shortly with Frank Billings in the Northeast gathering and processing presentation. So if you can grab a seat, we'll get going shortly. Thank you very much.
All right, I think we're going to get started with Frank Billings.
Francis E. Billings
All right, good morning. So in the Northeast, we clearly have some distinct businesses and different terms of cycle and complexity that we have going on right now. It's kind of 4 years into a 50-year play. We have some great franchise positions up here in the Northeast, and we're developing some great positions to take advantage of what Alan talked about in his opening remarks. And that's kind of getting in the path of the volume growth that is being projected in this area. It's clear the basin of wet and dry gas development for the United States, and we have a lot of activity and a lot of people are coming into this basin from a production perspective, but then we're seeing infrastructure opportunities that are available to us as well.
In the early 1990s, I remember, working with -- at the time I was with MAPCO, but Williams and MAPCO were trying to put the scale infrastructure together to serve the Western U.S., those Western basins. And kind of the same teams here today doing the same thing in the Northeast. And 20 years later, it's not that different. We overcame a lot of challenges out there and we're going to be overcoming challenges along the way in the Northeast. But at the end of the day, we had great franchise positions that have been generating cash flow for Williams for the last 20 years, and definitely, over the last 10 years very robustly. And we think the shareholders of Williams are going to receive the same benefits of the effort in the execution that we're doing in the Northeast. So excited to be here. The main difference I see between what we were doing in the '90s and what we're doing in 2013 is the scale and the opportunity set is much, much larger than we had out West.
One of the things that we're doing up here that is pretty important, I think, for long-term success is we're really developing some geologic diversity, geographic diversity and also producer diversity. The play is different from Northwest Pennsylvania, Northeast Pennsylvania, Ohio, it's all different development, it's all different productive capability. And I think we have a nice footprint and the opportunity to get into as many of those as we can to diversify those areas where production cost is going to be different, infrastructure cost is going to be different, but at the end of the day, getting ourselves in front of that volume path and being able to take advantage of those opportunities when those separate and distinct areas of the Marcellus and Utica start to take off. We started in 2009 with Laurel Mountain Midstream. It was an acquisition we did with Atlas and that really created a pretty a significant footprint, 47 counties, most in Northeastern Ohio and North or Western Pennsylvania. And really, what we did is we started developing. We put in a lot of infrastructure to support a pretty robust drilling curve that Atlas and Chevron were beginning to implement. And as Atlas -- as Chevron came in, they had some organizational capability challenges that they went through and we've seen their production level off. Not so much because they don't like the acreage position, it's time, but it's really -- they're starting to focus again on the weather positions that they have up in this area and we're in a good position to be a service provider for them in Northwest Pennsylvania.
Three Rivers is right in the middle of one of the acreage positions that we have and with LMM as well as maybe opportunity to leverage some of our opportunities and investments in Ohio through this pretty significant footprint. So it's something that we have to grow with, we have to develop and we think it's a great position to start with.
that we have to grow with, we have to develop, and we think it's a great position to start with.
With Laurel Mountain, we've seen different volume curves come out over the last 3 years. Most of them have really been just a reaction to Chevron, changing their perspective and changing their -- when the gas prices softened a little bit, they backed away from the dry area a little bit. And we've kind of seen their producer drilling program kind of go out into the right a little bit. What we have done in reaction to that is we've stripped out quite a bit of capital that really wasn't robust revenue generation for us over the time period you see here. And we have the productive -- we have the capability to move about 620 million a day of Chevron gas in our Laurel Mountain system today. So we have the ability to ramp up quickly, given Chevron moves into those areas that have capacity available.
Where we are expanding our capital is really in direct response to a very specific drilling program that they have. That's backed very well by the volume that's associated with it. So any of these new expansions that you see in 2014 and 2015, those are going to -- those will go forward when the drilling program is put in place for those to take place.
But again, in element, we have the ability to move quite a bit more volume than we're moving today. And then I think as Chevron allocates their capital dollars, that's going to be pretty low hanging fruit for them, and we should see the benefit of that over the point-in period.
Susquehanna County, it's a whole and other animal. It's the gift that keeps on giving. I think you'd be hard-pressed to find a better dry gas production area in the world than what we're finding and what we're seeing in Susquehanna County today. Cabot stated they have over 3,000 identified drilling locations in the sweet spot of the Marcellus and with rates of return that rival or exceed all the top U.S. liquid plays that occur in commodity prices. This is going to be an area that we're putting a lot of capital in, when we'll talk about it here in a minute, into this area and we are expanding our capacity significantly. We're going to add about 2.3 Bcf a day of compression dehy capacity in 2013 to 2015 to -- really, in response to what Cabot's doing up there, as well as a couple of other quality customers and WPX Energy and Carrizo. We've got a lot of opportunities to grow our position up there, but for us, we're really responding to Cabot transitioning from an acreage capture program to really efficient pad development in 2014, and you really see that from the standpoint that we're going to have a lot less capital going into this area, but we're going to see significant volume growth.
And one other thing, there are some questions that the earnings release or the earnings call around the increased capital that was being seen in this area, and I think I probably didn't do a great job of explaining that at that point in time, and I think you guys, or a lot of analysts, were assuming that it's a -- maybe cost overrun or higher cost, but that's really not the case. What we're doing is we have put in place additional capital in response to a more robust drilling program and some recontracting that we're working on with Cabot. And as such, we had to add about $400 million of capital associated with that. And with that comes, which you're going to see here, which is some significant compression expansion projects to increase the deliverability out of this area to about 3 Bcf a day. And we see Cabot's and other producers' production curves being right along with that. So we have great opportunity up here. We're going to see our capital investment up here fall off as Cabot goes to the efficient pad drilling. We're going to have the majority of the infrastructure built out, so we're just going to be able to connect their wells and get their gas flowing.
But other than that, this area is significant for us. It's going to be -- when you look at an area, when you think about 1 county delivering about 3 Bcf a day, that doesn't count the neighboring counties of Bradford. ACMP has a nice position over in Bradford, and between those 2 counties today, I think -- between our 2 companies today, I think we're probably moving in excess of about 3 Bcf a day today between our 2 companies. And we've seen ourselves grow and in this county, and I'm certain Mike and the ACMP guys see their business growing in Bradford as well. So it's a great location and -- for dry gas drilling for us. It's not as complex. We can put in -- we've put in a lot of the dehydration and we can flow gas before compression comes on. We'll free-flow a lot of gas and when the compression comes on, we get the uplift associated with that. So again, very great for us, it's a great investment, a great opportunity for us to grow our position up there.
Now with Ohio Valley, we got a different story. And still a very good position, very -- we're really engaged with our producers up there. They really are working to understand the drilling locations that they have. We're really working with them tightly to make sure we have the right mix of assets in place, so that we can support the drilling profiles and the production profiles that they're wanting to execute on over the next 2, 3, 4 years. It's really important in these areas that you get -- understand what you're producers are wanting to do, at least 24 months out, if not more, because it does take time to get infrastructure in place, it does take time to get the permits in place. And when you're dealing with some of this area where you have a lot of high liquids handling, whether it be, what they call condensate or NGLs, and just the logistics of getting all those to markets is what we're focused on.
The larger producer players up there right now, we have a great customer mix up there behind this business, we got Chevron, we got Statoil. They have required 3 of the portfolio companies that were originally in this business. And we have Stone and Gas STAR, Trans Energy. We have quite a good group of producers that really see this is an area that they're going to spend a bit.
Our current set of producers have delayed some of their drilling plans in response to some of the difficulties we've had moving gas out of the area, but we have not seen them back away from the area long-term. In fact, we see them engaging with this now to make certain that we have -- they understand what we're doing and we understand better what they would like to execute on. And we can put in place the projects to make sure that we can have the capability to move their volumes and handle all hydrocarbons that are being produced from this area on a timely basis, so that we don't have capital too far ahead. But better that, they don't have any capital that -- or production that's stranded behind assets that aren't able to take it.
We've recently seen some better volumes from this area. Warmer weather is our friend up there, and I'll speak to that here in a little bit around some of the things that we're seeing up there. And I think we've got a window of time here where we're going to have mother nature help us out a little bit, but it gives us time to get some of the liquids handling facilities, that I'll talk about later, in place before we get to the fall and winter months next year.
We're really setting ourselves up for a nice ramp-up in volume here. 2013 is going to still have some of its challenges, from the fact that we've got to get assets in place over the next 3 or 4 months. But our goal, is by the end of 2013, to have ourselves well-positioned, to get ourselves back to the volume curves that we've projected for this area. And we think we can do it and we know we can do it. I think it's going to be incumbent upon us to show the producers that we can move their volumes and make sure they get the netbacks that they want. And at the end of the day, our goal is to make certain that the producers are not waiting on us and we have the way -- the ability to move all their volumes that they have available. And they have confidence to start investing drilling dollars in an area that has very good rates of return for drillings. So we've got to -- again, we have to execute and we know we can.
So over the next 6 to 12 months, we've got quite a bit of activity that we're focused on to get these assets in a position where we can consistently, reliability, but more importantly, safely operate and move the volumes that are behind this -- or at this resource. We have done a lot of work up there. We have completed some of the projects that came and had started, and some -- and made sure we had all of those things complete. But really going forward, we've got to make certain that we get all of these key projects done in 2013, specifically the liquids handling projects at these existing CRPs, which we think unlocks probably another $70 million to $80 million a day of volume that's sitting behind those stations today. As well as the Moundsville fracturing 2. This one's pretty critical for us as well because as the volumes ramp up, we're going to have to be able to move all of the NGLs out of the area.
The one thing that hurt us in 2013, and it's going to hurt us until we kind of get all this stuff -- get all this volume flowing, is we -- it's just you had anything in processing revenues that we aren't able to collect, we had a lot of natural gas liquids transportation, fractionation and NGL handling revenues that we get when we put our volume through the fractionators and we put the volume into truck and rail car. And when Alan talks about volumes that are leaving by truck and rail, he's talking about Y-grade volumes that weren't able to make it into those assets, so to the extent we can get the Y-grade into those assets and we have the ability to collect all the fees that are due us, relative to these contracts that we have in place. So for us, it's a full -- it's the full meal deal. It's making certain that we're handling everything at the CRPs, but then also making certain that we're collecting all the associated revenues for gathering, processing NGL transportation, fractionation, loading that are available to us.
One thing we're doing out here, too, we have quite a bit of construction going on, our Oak Grove facilities, the 200 million a day processing plant that will be online at the end of this year. We have brought the -- our Fort Beeler plant is fully functional now. We have all 500 million a day of capacity available for that plant. And our target's to exit 2014 at 700 million a day of volume, and we feel like what we're hearing from the producers is we have -- the resource is going to be there and we'll have the assets in place to move that volume. So we can make certain that we can hit their curves but more importantly, deliver on the financial results for the organization.
As we've talked about a lot, our biggest hurdle here has really been dealing with the system design for a certain specification of hydrocarbons that really doesn't match well with the configuration and operating conditions of the assets. And I'm going to talk through that here on the next slide. But specifically, on the west side of the system, where unfortunately we have the majority of the gas but we also have a 12-inch pipeline, I would say location, location, location is great in real estate, but it works pretty well, too, when you have assets in the places where you'd wish you had them versus where you didn't, which you had them, but -- on this map, you'll see the, kind of the yellow dots, the yellow squares, those are going to be the -- those are the, really, the 4 central receipt points where tend to have the most issues, and that's the 4 locations where we're going to be installing the liquids handling facilities. The reason that -- so a lot -- and if you look at where they're at on the map, they're kind of the farthest away from where we want the gas to be, and that's up at the Fort Beeler complex, up at the top of the chart.
What's really happening out there, is that 12-inch pipeline, because it's full, because it's at capacity and operating at high pressures, it's really been acting more like a refrigeration plant than a pipeline. In the wet areas, there's 2 kind of things that get you in trouble, and that's temperature and pressure. And at this part of the time, we kind of have been experiencing both. So the product, when it reaches Fort Beeler, shows up at about 40 degrees, which is a pretty low temperature. When it enters the pipeline system back at those square dots, it's coming out of the ground, it's coming through the compressors at 120 degrees, it's probably going through coolers to get you down to 95. And then it's getting into the ground, at ground temperatures which are more like what you're seeing at Beeler. But what we have -- what happens is within that first mile of pipe, we get a lot of liquids fall out, almost -- we get very quick liquids drop out there, and what that does is that loads that line up pretty darn quick. And we've got the picture of the top left of what the 12-inch line kind of looks like today, and the issue is that when it goes into the pipeline, it's a gas and it's moving just fine. But very, very quickly, it goes into 2-phase flow and we get -- we fine ourselves where we have a lot of liquids that start to pool. And if you've ever been to West Virginia, it's a little hilly out there. And you get these liquids that begin to pool in the bottoms of the pipe.
So what happens is, is we're actually trying to pig that pipeline 3 times a day to keep the pressures -- keep the pressure down, but as soon as we run that pig and as soon as that pig clears, that gas coming in behind, again very quickly, is going to turn back into 2-phase flows. So we never really get the line swept out well enough to where we have consistent operations.
The other thing that happens is that at Fort Beeler, we have to operate the plant at about 800 pounds because we have to make certain we get all the liquids extraction out on the tailgate of the pipe -- of the processing plant so can meet hydrocarbon dew point into the residue pipeline. So we have to run the plant at 800 pounds at the inlet of the plant, and then we have to -- sorry, and that puts about 1,000 pounds or more back at the CRPs. So again, what you have is at higher pressures like that, you get condensate formation at temperatures well above freezing. So in the winter and when you have -- if the dehys aren't working or if some of the producers give you some produced water, then very quickly, we can find ourselves in a situation where even though the gas -- or the temperature might be 50 degrees in the pipe, we're getting a hydrate formation. So we have a lot of things going on that we have to clean up and fix. And I think we're handling the water issue, we've installed some dehydration, we're trying to keep the pipeline dry to the extent we can. But really, what we're doing now is we're going to make a philosophical shift on how we operate the system, and we're going to put liquids handling facilities at those 4 points. And our goal there is to turn the upper left-hand box into the lower right-hand box, and what we'll do there is we'll take out all of those liquids that want to turn into -- or all those fractions of the gas that really want to turn into a liquid at the operating conditions we're seeing out of the 12-inch line. And we have the ability in the 4-inch line then to move those liquids to Fort Beeler.
So on the west side of the system, the 12-inch line, there's a 4-inch pipeline that is right next to it, and that's the line that was supposed to handle the condensate. As most of us in the business and I would -- when we talk about condensate, South Texas condensate, something that comes out of the ground at 14 pound or 12 pound, well, the condensate up here is significantly higher than that, 150, 200 pounds. So it's a lot higher vapor pressure. But what we can do is we can use that 4-inch line almost like a -- think about it -- think of it as a Y-grade line almost. So we're going to knock out some of the heavy liquids at all those receipt points. We will then have a nice stream of gas that can go in the 12-inch line, that doesn't have any hydrocarbons in it, that want to turn themselves into liquid at the temperatures and pressures that we're operating in the system. And then we can take all of those other -- all the liquids up the 4-inch line to Fort Beeler, where we're going to have stabilization facilities there. We're going to have the ability to then take all of those liquid products and put them into the right purity products or ultimate commodities that the producers are going to want to sell. It's tailgate liquids off the fractionator, or we're going to be creating some condensate-handling facilities to sell maybe 14 pounds vapor pressure, gasoline or some other product that we can get into the market [ph] in Canada, which is where a lot of these products are starting to find their home.
The main benefit of this is we see, and what the producers are going to see -- and when we talked to all the producers, they really liked the plan, because this will allow us to take off some equipment that is not very reliable. We have some vapor recovery compression that was installed that is not a very reliable unit, and we'll be able to take off -- there's some locations that we have to operate again. They are very unreliable kind of quick-fix production, handling equipment that doesn't really -- it's not really what you want for long-term, high-reliability operations. We're going to be able to take a lot of that equipment out of service, we're going to have a system that's very highly reliable, and we're going to be able to provide the producer the kind of consistent operations that they need, but it's also going to allow us to have much more consistent operations, reduce our costs. But then I think more importantly than anything, we should increase the safety, because we won't have such all the team activity going on, and we will have a system that's a lot more stable.
We -- again, this area is very -- competes very well economically with other production areas in the U.S. Our producers behind this system are very excited about it. A lot of it, for some of them, it's their main place. It's the way they're going to grow their company. And we want to make certain that we are allowing our producers the ability to maximize the value of their company.
But then we also have so much bigger players, like Statoil, and Chevron that have another -- have a big drilling program that they're trying to implement, and they're just on the early stages of that. So we should see a great opportunity to stabilize our volumes in '13 and then start to deliver on the volume growth we forecasted '14 and on.
And it's really -- again, it's really a function of facilities, and it's not a function of resource. And what we have to do is make certain that we've got those facilities in place, so that we're not the bottleneck, and we can work hand in hand with our producers over the next 10 years to really deliver on the cash flows that they want to deliver on for their shareholders, as well as for ours.
Talk about Three Rivers for a minute. Three Rivers was kind of not a big announcement but, really, it's a great opportunity. And we see it as the first step in a lot of development of that Northwestern Pennsylvania area. We talked about $200 million a day processing plant, which is kind of the initial announcement. We are in the process right now of trying to identify, along with Shell, along with other producers in that area, kind of really where the sweet spot is for the Marcellus and Mercer, Lawrence, Crawford, those counties in Northwest Pennsylvania, as well as Northeast Ohio, Trumbull and Mahoning. So for us right now, and almost every producer up there, if you ask them where they're at in their program, they're all in the appraisal part of their program. They're trying to appraise where there wells are at, they have a lot of acreage position up there.
Again, we talked about geologic diversity. Well, there's a lot of geologic diversity across the Northwest Pennsylvania. You have dry Utica, you have wet Marcellus, you have to -- if you want to do early production systems, you have to sometimes drill a dry well and a wet well, so you can blend them to get your production numbers up. So, really, this area is in appraisal right now, but what we're doing is we're trying to identify the areas where our current producer set is as well as other opportunity sets that we're chasing up here, and determine where we want to lay out our gathering systems and pipelines. And then how much real processing capacity that we're ultimately going to need up here and how that gets legged in over the next 3 or 4 or 5 or 6 years.
And the key for us up here again is -- Bluegrass is a key component for us in this area. At this time, we're not really looking to invest in local fractionation in this area, so getting the NGL around and aligning our plant startup date with Bluegrass in service date's [ph] pretty critical for us to be successful up here and for the producers, really, to get the maximum value for the investment that they're making in their drilling program.
So, really, right now, I'd say that the main thing we're doing up here, and I think it's been very consistent with our strategy as we're building scale in the Marcellus through the strategic investments. When you look at the curves that Alan showed earlier today about U.S. gas production growth and you look about how much of that is coming out of the Marcellus, it's a pretty significant load. And we find our own producers providing us some insight into that, so at the end of the day, 2017 timeframe, we could be moving close to 5 Bcf a day of gas out of the Marcellus, which is a pretty significant share of that. And that's really just in the investments that we have, clear line of sight on the day. This really doesn't take into account what we might have in the future with Three Rivers Midstream. This doesn't have any Blue Racer volume in it as well.
So this is really just kind of under the current producer set we have and the current assets and investment base that we know we're executing on. So it's a great opportunity up here for us in our known contracts, in our known business. But we also feel like with Three Rivers and Blue Racer, we're preparing ourselves to be a much bigger player as those areas become fully developed and people really begin to understand what it means to get a full wet gas development program in place out of an area that seems to be pretty productive, given all the numbers.
To talk just a little bit about Caiman Energy, Blue Racer. When we did the Caiman acquisition last spring, with that, we formed Caiman II, and we had an ownership interest in Caiman II. In December of 2012, Caiman II merged with Dominion and some of the Dominion East Ohio assets to form Blue Racer Midstream.
Blue Racer Midstream is a standalone company. Jack Lafield manages that company, and Williams invests in those opportunities that Jack and his management team bring together Williams to compete against Blue Racer in the space. And we feel like we've got great opportunities, but what we also feel like is, given some of these investments, given some of the footprints that we have, there's probably opportunities for us to lever both positions to the benefit at the Williams shareholder from the standpoint of making -- make a start -- smart choices as our customers may need infrastructure, as their customers may need infrastructure as a way to manage some capital. But again, it's a great investment for us, and really, it's a great opportunity for us to put ourselves in a position to be active in Ohio, given all the things that we have going on right now in West Virginia and Pennsylvania.
Alan mentioned, and I just want to show the picture of kind of our capital growth and kind of where those investments are being put today. Again, I think we're diversifying across the play. We aren't just dry-centric, we aren't just wet-centric, we have pretty good portfolio of opportunities to invest across the entire geographic area. And we think that's great from a risk-reduction perspective to the extent some of these areas become less appealing for whatever reason, or they just tend to fall apart or down someone's chain -- or decision point, we feel like we've got a good opportunity to be a part of that. All these investments here in Susquehanna, Laura Mountain, Ohio Valley and Three Rivers are all based on current contracts. And I know most of the Blue Racer investments are a lot of stuff that's under negotiation as well as some supporting investment in the Dominion East Ohio assets.
If you look at what our segment profit growth is in DD&A, we have quite a curve to deliver on, and we really feel like we can do that. Very confident in our ability to get the issues that we have in Ohio Valley resolved. If you look at the portfolio that we have in Northeast PA, if you -- I can remember in 2011, right after we bought the Cabot assets, having similar conversations with Cabot around compression not running, dehys [ph] are not running. We had salt. We have all of these other issues that we had in 2011, and we worked through those.
And now we have a great performing business. And we're executing fairly well up there, and I think we we're going to -- we will find ourselves in the exact same position in Ohio Valley by the ability to kind of get the assets that we acquire in a position, where they're able to do the work that they need to do to move the hydrocarbons that are coming out of the ground and getting them into the higher supplies markets, ultimately with Bluegrass and other residue pipeline opportunities that were going to come. So we're in a great position to deliver a great growth track for Williams.
Kind of our key points here. Again we're bringing large scale profits and infrastructure to the Northeast to serve the fastest-growing U.S. volumes. And we feel like we're right in the middle of this. We've got great opportunities in Ohio Valley. We're creating a great position in Northwest PA with Three Rivers. And we have other great footprints and opportunities that we're evaluating. We continue to evaluate if they make the right since to step into.
Continued expansion for the Susquehanna Supply Hub. I know Rory's going to talk about the Constitution Pipeline in his presentation, but that's another outlook, that's another opportunity that we see is going to be critical to moving all the volume that Cabot -- we have on the Midstream side out of there. That pipeline is going to come online, moving about $600 million a day. And there's opportunities to expand that going forward.
We have our OEM short-term challenges, but this is a great long-term growth trajectory for us. These are not things we can overcome. We've got the right technical teams and the right experts in there, creating the right philosophy and all we have to do now is to execute on that to kind of clear the path for the producers to have great success.
We have our joint ventures with Three Rivers and Blue Racer. And then in Northeast PA and Ohio. I know Mike is going to talk a little bit about what he's got going on with the Utica East Ohio basins, but I feel like I crossed our -- all of our portfolios across all of our businesses. We have a great coverage of this area, and it's going to be a robust growth rate for the U.S. for many years to come and feel very proud to be able to leave the Williams effort up here.
And again, with that, we have the fee-based cash flows that are associated with this business.
With that, I'll take questions. Yes?
Yes, a question right here at the back. Faisal Khan with Citigroup. So looking at your segment guidance -- the segment profit guidance. I'm looking at your expected gathered volume growth through 2017. Is it fair to say that I should look at the segment profit guidance and look at the relative percentage of the organic volume and segment those volumes that way? Meaning that is you -- sorry if I'm not being clear, but if I'm looking at your segment profit DD&A, EBITDA, and I'm looking at the volumes that you have growing on C-12, is all those -- are those volume proportional to the EBITDA that you're going to be generating over that time frame? That's what I'm trying to understand.
Francis E. Billings
Yes, I think what you're asking is kind of how the -- what's the revenue streams?
Faisel Khan - Citigroup Inc, Research Division
Francis E. Billings
I think what -- it's hard to go gather volume to EBITDA, because you have the NGLs. We have other revenue streams that we start to create over time, we have NGLs, fractionation, transportation and NGL handling, so there's revenue streams that are associated with those that are going to show up, so not every gathered -- not all gathered volume is equal in what it's value contribution can be to the EBITDA growth.
Faisel Khan - Citigroup Inc, Research Division
So on -- if I'm looking at 2015 adjusted segment profit and DD&A, how would you divide that between Susquehanna, LMM and Ohio Valley Midstream?
Francis E. Billings
I don't know if I have that right off my chest [ph].
A question on Slide C-15, where you have the CapEx declining very substantially. Looking from 2013 to 2015. Is that just because you don't put something at the guidance until you have a higher level of certainty about it, so that the reduction reflects reducing certainty to [indiscernible]? Or you actually expect the spending to decrease that dramatically, and so you're realistic?
Francis E. Billings
Actually, both. I think we aren't going to put something out there until we know we've got it contracted, but we also know that we're going to have to have some gathering investments to get the gathered volumes, say to Three Rivers, so the processing plant in there but we don't necessarily have the final definition of what those gathering investments are going to be, so that gathering capital is not in that number. So I think we have some things that we have identified that aren't in there. But to answer your question right now, it's really, to your first point, which is if it's really not an identified opportunity, it's not in our guidance.
I might expand on that, and that's consistent across all of Williams, so what we put in guidance is projects that we have a high level of confidence that will move forward, typically contracted with customers, or we have unilaterability like the PDH facility in Canada, where we don't need a customer. So those are very firm projects, where the capital is being allocated. And we expect that the revenues and the cash flows will show up. We have a very large portfolio of prospects, some that are under negotiations, some that are in proposal stage. Many of those will turn into probable projects. They'll be sanctioned, they'll move forward, be moved into our guidance. Some will fall by the wayside, but there are quite a few things that we're doing now that haven't even been in the proposal pie that have shown up because of where we're at. So there's a lot of capital and a lot of business opportunities that are not reflected in the guidance. We provide some visibility. In my financial slides, I'll provide some additional visibility on those. So I'll just paint that picture, so would expect the capital in the Northeast will not decline as expected here as we see some additional opportunities.
Just back on the Ohio Valley Midstream. I guess, what's the risk that you can lose some business here? You've had some execution issues like you said. Is there anything in your contracts with the producers, anything around the acreage dedications that you might run into trouble with? Or is this just a matter of kind of bringing the volumes on? And then the other question is just on the 4-inch line, is there a chance that, that goes up? I mean, do you have issues with [indiscernible] all the condensate?
Francis E. Billings
Sure. It's good -- 2 good questions. I'll say, contractually, right now, we feel like we're working with the producers to -- I'd say no to your first question. I think we feel good that we can maintain the acreage dedications that we have, and we don't feel like we have any contractual leakage. To your question relative to the 4 inch. We have installed 3 pump stations on that 4-inch condensate line already to increase its capacity. And we can install 4 more to get that line up to about 12,000 barrels a day. But we also, at this time, are about -- or we're working on, and we're actually buying right away to put a 24-inch loop, which is in our capital guidance numbers on the west side of the system. And then we would hope to convert the 12 -- 4-inch line. We'd move the condensate up in the 12-inch line, and we'd then have a 4-inch line for other lower pressure service potentially. So we're in a plan to expand the size of the pipelines on the west side.
Your management team has really done a great job of identifying growth basins. And in the Marcellus, you clearly have -- I mean, balanced riches [ph]. I was just curious, between ACMP, Laurel Mountain, Blue Racer, Three Rivers, WPZ and WMB, there are a number of entities that operate in the basin. How do you choose which entity to allocate capital to? And is there, I guess, overseeing command and control through this different entities?
Alan S. Armstrong
First of all, I'd say, Access Midstream has its own separate entity. And Mike, as the CEO has their own dominion. And so -- sorry, let me start over there again. ACMP, certainly, has its own dominion, and we'll make decisions on how to allocate capital within ACMP. Jim Scheel, Don Chapel and myself sit on the board but, obviously, sit there to look at after the best interest of ACMP. And so, and ultimately, then that will add value to our LP units and our GP units. But we certainly understand, and I think bring benefit to ACMP in terms of our knowledge on what's going on in the different basins. So let me set that aside, because that is certainly separate in terms of the way we manage that. Beyond that, in terms of Blue Racer, we certainly have different rights of control within Blue Racer, and certainly, we have the ability to impact how decisions are made in terms of capital being allocated within the Blue Racer JV. And then of course, within Laurel Mountain, which is the other JV that we have up there as well, we have control of that joint venture, and the partner Chevron has the ability to come with us on investment or not come with us on investment. We have a pretty good control there. So overall, we have a lot to manage there, we have another joint venture developing. In terms of Three Rivers, a joint venture will show, but initially, there'd just be a 1% interest there. And so, obviously, we have the control on that joint venture as well. So it is complex, but I would -- the main thing I would want this group to walk away with is that we're not in a position to dictate to ACMP how they might go about in the basin, but we certainly look at it from our financial benefit, we determine whether what we think's in our interest, and we can act on WMD's part to respond to what those decisions are.
Faisel Khan - Citigroup Inc, Research Division
Just a follow-up again. On the -- when I'm looking at your guidance for EBITDA growth, is -- are there minimum commitments by your customers to get to that EBITDA growth? Or am I still tied to the volumetric assumptions that you guys have made on C-12?
Francis E. Billings
We have some contracts that have volume commitments associated with them. Some of the newer businesses are going to be underwritten by more volume commitments than what some of the historical businesses probably had. Did I get you?
Faisel Khan - Citigroup Inc, Research Division
Francis E. Billings
Okay. And then for the Laurel Mountain business, we don't have a volume commitment, but we have some capital recovery provisions in that business that we'll be able to execute on.
Faisel Khan - Citigroup Inc, Research Division
The Ohio Valley Midstream and the other partnership, you basically have some level of volume commitments that enables you guys to continue to grow even if you don't get to a 4.5, 5 Bcf a day number in 2015. I'm just trying to understand like how much sensitivity do you have to the volume growth? And how much is kind of locked in by producer commitment?
Francis E. Billings
Yes, I would say, on the numbers that you're seeing on '15, most of the producers are in excess of the volume commitments that we have in place. And then in -- again, like I mentioned earlier on Laurel Mountain, what we have available to us there is a capital recovery opportunity when a certain amount of time progresses, where we haven't collected a certain amount of revenue.
Any other questions for Frank? Okay, our plan is to take about 15 minutes here and grab a boxed lunch and start back up roughly at 12:00 o'clock noon with Allison Bridges in the Western operating area. Thank you.
Okay. Well, we're at noon straight up. And it looks like everyone was really efficient in grabbing those box lunches, appreciate that. Next up is Allison Bridges in the Western operating area. Thank you.
Allison G. Bridges
Thanks, John. Just hope everybody goes ahead and continue to enjoy their lunches while I go through this. I really appreciate the opportunity to be here to get to share with you some of the insights into our business in the West, and also, highlight some of our future opportunities.
Our Western assets are -- include the Northwest pipe system and our gathering and processing facilities in Wyoming, Colorado and the Four Corners area. To put these assets in perspective in terms of scope and scale, we have, in total, over 7,700 miles of gathering pipeline, which gives us tremendous reach into each of our basins. Those gathering facilities have a capacity of about 4.3 Bcf a day. And then we have multiple large-scale processing plants in each of these areas as well. And combined, they have a capacity of 5.4 Bcf a day processing and treating. And we can produce 200,000 barrels of natural gas liquids. On the Northwest pipe system, we have 3,900 miles of interstate transmission that we can deliver on a peak day, 3.9 million dekatherms a day.
So I think you can see what this scale and competitive advantages, which I will be talking about. We are very well positioned to capture the future growth in the market and supply in the region. And I'm going to talk more about those opportunities. But first, I want to really kind of delve into some of the numbers to give you a better in-depth view of our financial drivers.
So, obviously, in the West, we were impacted by the reduction in NGL margins between 2012 and 2013, so both the lower NGL prices and the increase in gas prices. But as Randy talked about, Williams, overall, did benefit from the lower ethane margins as feedstock talk. And then with higher gas prices, I think we're going to really benefit in the future for stimulating more drilling in the west.
So despite these major commodity changes, the West will continue to deliver strong cash flows and returns. Now I'm going to get into the drivers of segment profit more in a minute, but I think you can see through -- from 2013 through 2015, we will still be delivering a strong, stable segment profit in DD&A.
And then if you look in at our capital expenditures, they're very modest. Our maintenance expenditures are very low and stable. Most of that is on the Northwest pipe system. And then as we talked about -- we made the decision to delay our parachute TXP1 cryo plant from mid-2014 to mid-2016. So that had the effect of appreciating growth capital out to 2015. So combining our still strong segment profit in the DD&A with the low capital requirements, the west is still going to continue to throw off significant amounts of free capital.
We also expect to continue delivering strong volume. Now on the gathering and plant inlet side, we have seen some modest decline in volumes due to the reduced drilling. In general, I'd say around 5% to 6%. The first quarter of 2013 was also impacted by weather conditions. The 2013 winter months were significantly more severe than in 2012 and worse than normal. So we had a lot of production that was bumped off frozen wells, and it takes the producers some time to get the wells back up to full production. So we may see a little bit of lingering effect beyond the first quarter.
Over on the NGL production side, obviously, we had a huge set change when we went into full ethane rejection. Our customers have also reduced some of their ethane recovery, but some producers are continuing to recover ethane, probably not strictly from a margin standpoint, but they may have other downstream considerations that impacts their economics. On the non-ethane front, our volumes are relatively stable, although there is a slight impact because of plant inlet reductions, as well as some slight efficiency reductions due to ethane rejection.
So in summary, we expect continued strong volumes, but we look for this to strengthen in the future with increased gas prices, more drilling. And as Alan said, we continue to expect that the Rockies will be a major contributor to the supply growth picture. So before I move away from volumes, after the first quarter, there were some interests in folks wanting to better understand the changes in NGL production and our equity gallons.
So this chart's a little bit busy, so I'll try to orient you. The 3 bars on the left were the fourth quarter of 2012 and the 3 bars on the right, the first quarter of 2013. Then at the bottom of the chart, the green and the blue bars are what our customers recover and the top is our own NGL barrels.
So what you really saw here was that margins started to move negative in November but really took effect in December. At the same time, again those producers that were recovering ethane also reduced their recoveries. So it wasn't until the first quarter of '13 that we saw the full impacts of ethane rejection. But I think it's really important to point out that Williams optimizes its NGLs based on the value. So each and everyday, we look at the plant efficiency, we look at the value and optimize. So you will continue to see a minimal amount of ethane produced in order to maximize the value of the total barrel.
So while we anticipate that NGL margins are going to be low, our total revenues are really underpinned by strong fee-based revenues. On the Northwest Pipeline side, virtually all of that revenue is reservation charge based, so regardless of what the customers move. We did have about a 7% increase in those revenues beginning in 2013 when our new rates took effect as a result of pre-settling our rate case.
You'll see that between '12 and '13, there was also a reduction in our gathering and processing fees. They are slightly offset by what's called here, commodity based fee. And that is largely due to a contract restructuring and reduced volumes in the Piceance basin, which I'll explain here in a little bit. And then we've already discussed the drivers of the NGL margins. So there's a lot of moving parts on here, but the bottom line is, beginning in 2013, about 3/4 of our gross margin is going to be from fee-based revenues, and that will equate to over $1 billion a year. So as I mentioned, the impact of contract restructuring and reduced drilling in the Piceance.
Primarily related to a contract with WPX Energy that was actually revised back in August of 2011 prior to our spend down, and it was revised to reflect a more arms-length, market-based approach based on the market at that time. But those terms didn't take effect until January 1 of this year. So before, we were -- we charged a gathering and processing fee, plus we retained a percentage of liquids for what went through the cryo plant. After January 1, our gathering and processing fees changed and were reduced. But replacing the percentage of liquids, we now have an additional fee that's based on the net liquid margins.
So when you take all into account, if you look at 2012 revenues under these contracts versus 2013, you'll see there's a sizable reduction of about $76 million. But slightly over half of this reduction would have occurred regardless of the contract restructuring due to commodity prices and volume reduction. So the remainder that's related to the contract is in the form of reduced gathering and processing fees that were partially offset by the shift from percentage of liquids to net liquid margins.
So admittedly, this did have an impact to our near-term revenues, but Williams obtained really tremendous value out of the contract restructuring in the long term, because we went from a short-term contract to a life-of-lease dedication for all of the formation in the area. So that would include the Mancos and Niobrara.
So we think with combined increase in gas prices, it will stimulate additional drilling, as well as the announcement that we have seen on the very successful results out of the Niobrara. We think there's still tremendous value to unlock in the area.
So while the West is in a little bit of a lull period, we have proactively been focusing on working to optimize our gathering and processing operation. So these efforts are really designed around pursuing several things. One, maximize our utilization factors, increase our plant recoveries, improve our reliability and reduce our operating costs. So all of that helped to bring value to the bottom line. But we're also looking to cement ourselves as the preferred provider in our basins, being the most reliable, flexible and cost-competitive.
To give you an example of some of the things that we have done here, in the Four Corners, we are in the process of completing a compression replacement at Ignacio, replacing outdated equipment, some as old as 50 years. So when this replacement is completed, it will significantly improve our fuel efficiency, as well as increases plant recovery, reducing our operating cost but also significantly reducing our air emission. We've already talked about the delay in the Parachute cryo. So it had the benefit of not only deferring capital but also allowing us to maximize utilization of our Echo Springs plant, where we can process some of the Piceance gas. And then finally, on the organizational front, we have taken to create efficiencies there through working smarter, working leaner. And in that way, we've actually been able to transfer some expertise from these mature areas up into the Northeast, some of their critical operations.
So we think we are extremely well-positioned to capture growth from these emerging supply basins. If you look at the map, we are really right on top of the Mancos and Niobrara area and we have a tremendous, stable, dedicated acreage. In the Piceance, we have 330,000 acres under dedication. And we are competitively positioned to capture another 350,000 acres there. In Wyoming, we have over 2 million acres dedicated. There's a lot of activity going on in Wyoming right now with several EISs in the process that would cover about 2.4 million acres and some 24,000 additional well locations. And that would include this Continental Divide/Creston area, which is right there in the Wamsutter area. And then in Four Corners, we have over 2.7 million acres dedicated covering the Mancos area. And we think there's opportunities really in the rich gas, the dry gas and even oily plays there. So we've seen a number of successful wells drilled in each of these areas as the producers are trying to delineate the area. And we think that with sustained gas prices north of $4, that drilling will ramp up again. So we believe that the Rockies and the San Juan still hold a lot of promise in the future, and we're in a great position to be able to capitalize on that.
So just changing focus here. I'm going to talk a little bit about Northwest Pipeline. I know you've seen this slide several times before, highlighting of the strength of the Northwest system, including the access to diverse supplies and serving the major market areas throughout the Pacific Northwest. And I also mentioned the new rates that went into effect January 1. We were able to work very closely with our customers to settle that rate case before we actually had to file. And I think it was on very favorable terms, not only for Williams but for all of our customers.
Also in the last several years, Northwest has been very focused on extending contract terms and keeping our capacity fully subscribed. And I think that this chart does a good job of showing the success that we have had over the years. The blue portion of the bar represents what our primary contract terms would have looked like back in 2006 when we started this process in earnest. The orange portion of the bar is what we have been able to extend just since 2011. So we've continued with that success every year. The purple portions of the bar represent what is scheduled to go into Evergreen status. So those contracts would start rolling on a year-to-year basis. But in no way does that imply that, that capacity would be turned back. And in fact, I think, the success we have had on extending contracts really shows that our customers value our capacity. Now I think, in this day and time where a number of pipelines are facing cliff with their capacity or already have significant amounts of uncontracted capacity, Northwest is in a very strong position.
And we continue to work on a couple of major projects. The first one here is the Washington Expansion. And it would be an expansion of our mainline from Sumas at the Canadian border down along our system on the I-5 Corridor. So it could serve not only the proposed Oregon LNG export terminal but also markets in the Pacific Northwest, and in particular, gas-fired power generation, which may replace the TransAlta coal facility, which is intended to be retired in 2020 and 2025. So I think the Washington Expansion is an excellent indication of the value of having existing infrastructure in the region because it allows you to scale your expansions. The Pacific Connector Pipeline is a partnership proposed to serve the Jordan Cove LNG export facility. We continue to advance the environmental and permitting aspects of that project and are making progress. And in fact, in the very near future, we expect to file the FERC application for that project. As Don described, we only include projects in guidance that are fully subscribed and have a very high expectation that they're going forward. These projects are not yet at that stage, so they are not in our guidance. I think they would be very good projects if they come to fruition. At this time, Northwest is not having to fund the development of these projects because third parties are funding those development cost.
So to summarize the key takeaways for the West. We are currently experiencing slow decline in areas where there's reduced drilling, but we are extremely well positioned to capture the new growth opportunities. We continue to deliver strong returns and strong cash flow even in this low NGL margin environment. And we have strong, steady fee-based revenue that will deliver over $1 billion a year. So with that, I'd be happy to take some questions.
On the cost savings in the West, obviously you had much lower volumes and things like that. Can you quantify how much cost savings you could see? Is that already in your guidance? Or could that be outside the guidance?
Allison G. Bridges
I think what we know off now is already accounted in our guidance. But we are certainly continuing to look for more opportunities. Four Corners is probably a little further down the path, so we hope to bring some of those learnings to all of our areas.
When you provided the gross margin kind of forecast on D-6 for the West, you talk about the various different sources of where those margins are coming from. And then on D-5, you talk about the amount of third-party ethane that was embedded in results through March 2013. Is there any third-party ethane margin associated with the forecast on D-6? Or does that assume that the contracts have converted to more of a fee-based?
Allison G. Bridges
Yes. On the third party, we are not collecting -- we are not retaining those liquids, so those would be based on fees.
I know it's not necessarily your direct projects and outside the forecast period. But the LNG servicing on the West Coast could be helpful for you. Do you have any sense for how truly viable that is and whether some diversity in terms of location is important in terms of approvals since we already have 2 out of the Gulf?
Allison G. Bridges
Yes. Well, again we do have a couple of projects that are related to LNG export. And I think it's a good sign that at least they're maybe moving -- the DOE is maybe moving on some of these LNG facilities. I think that on the West Coast, we're going to have to get through the approval processes before we get the markets to commit to them. I think there's a lot of interest. I think the economics are there for these facilities, but they still have some hurdles to go through. I think that while the government up there has been maybe more supportive of LNG exports than we have been in the U.S., I think they also are facing some hurdles with respect to infrastructure. And they require significant amounts of infrastructure more so than we would require here on the West Coast in the U.S. Okay. Thank you.
Next up, it's Rory Miller with the Atlantic-Gulf operating area.
Rory Lee Miller
You hear me back there? All right. Good. I tend to wander a little bit, so I wanted to get to a lapel mic if I could. I want to thank everybody for sticking around. I've got some exciting assets to talk about. Also those of you that know me know that I'm a big baseball fan. And I got to tell you, Alan, I've never get cleanup in my life. I was always the leadoff guy. But I'll see what I can do today. We've got some fabulous assets to talk about. And I think you'll be glad you stuck around.
I think everybody's aware that by now we've reorganized. So I'm just going to hit real quickly this map, so you can get a sense of what is in this new operating area that we're calling Atlantic-Gulf. We've got the kind of our traditional deepwater assets down the bottom of the map in the Gulf and then associated processing facilities and fractionation facilities that go with those assets onshore. The blue line that runs from the Gulf up to New York is obviously Transco. The red line there is Gulfstream. And it may be a bit difficult to see, but there's a green line right up there at the top. That's our Constitution project, and I'll be talking a little bit more about that as we move through the slide deck.
So let me start off first by talking about the supply side of the story around these assets. And it's a fantastic story to tell, one that's easy to tell. These call-out boxes that we're showing up and down the map there, those are reserve forecasts. I realized the numbers are probably a little too small to read. But those are from Wood Mackenzie, and they're forecasting the volumes that they believe are going to be available from 2012 through 2022. And a lot of good movement up into the right, that's kind of what we like to see. The Eagle Ford obviously is one of the great returning basins or project return basins in the country right now. And we are getting some supplies out of that area. That's being forecasted to be up about 4 Bcf a day over that time period. Likewise, moving up a little farther up the line, we've got a couple of large pipes that deliver in Transco's
and we've been putting them as they come. And I think with this map's regulation, we'll see that pace pickup. If you're an owner of a coal-fired or oil-fired power generation facility, you've got to do something between now and 2015. You don't have the option of doing nothing and you either have to make new investment in that facility or you have to take it out of service. So we think that the pace of opportunity, the pace of new gas-fired generation up and down the pipeline is going to be accelerating. The other thing that I would say, if you remember back, when you looked at that pie chart, it showed that we had about 37%, I think it was, of our new projects were supported by LDC growth. Well, this just represents opportunities for direct connection to gas-fired generation. Downstream of the LDC city gate, there's a whole another collection of plants that look just like this. And so I'm very confident that as power generation owners decide to react to the map's -- regulation, we'll be in a great position to win our fair share of the business.
Maybe just a little more detail on what's happening on Transco. I mentioned 2 forms of gas-fired power generation that we serve. One was the direct connect and 1 was the piece that was downstream of the LDC city gate. What this -- what these volumes, that shown here on the slide represent is just that portion that's direct connected. We really don't have transparency in, or behind that city gate, so it's hard to tell what's going on there, but if we just look at the direct connected power generation, we see these 2 spikes now, the time period here is the calendar year 2011 and the calendar year 2012. And those 2 shaded areas, those are the -- those overlap with the summer of each one of those years, and this represents the cooling load that we're now seeing on the Transco system from electric, or from gas-fired power generation. And you can see, averaged in '11, about 1.3 Bcf a day and in '12, about 2 Bcf a day. And we think that will continue to ramp up, and we're very optimistic that we'll continue to see new projects to drive that.
The next 3 slides that I'm going to go over highlight some of the projects that are in guidance. If you'll recall, we looked at that pie chart that showed the sum total of the projects that we had in guidance. I'm going to step through some of those here on the Transco system, and I don't want to go into detail, in each and every one of these, but again, there are a mixture here. Northeast supply length was basically a producer-driven project. The Northeast Connector and the Rockaway delivery lateral, those 2 kind of go in tandem, that was a deal with National Grid and so that would fall under the LDC category, and in then, Leidy Southeast is a little mixture of both. But I will say the Northeast Supply Link and the Leidy Southeast project have been directly driven, I believe, by the big ramp up in Northeast Pennsylvania of the Marcellus production. We've got a lot of new meters that have been established on that Leidy line. Meters of capacity far in access of what the pipeline can take away. And so many producers have made connections, gathering companies have made connections and people want to see the capability built to take that gas away.
This next Slide, this is moving a little further south from that Transco line. Our Mid-Atlantic project is actually in service now. It went into the service first month of this calendar year. That's serving some power plants with Virginia power and BG&E. Mid South project is also being designed to serve some new gas-fired power generation, and I believe that is scheduled for, and in service in, I think it's 2013 this year, as well. Mobile Bay South III, that's a new project that we're undertaking, and probably the last expansion that we have there, on that system. That's scheduled to be in service in 2015. And Virginia Southside is also a project that was put together to serve some new power generation load.
This next slide talks about our Constitution Pipeline project. Frank Billings mentioned this project when he was speaking. This project is a direct result of Cabot's success up in Susquehanna County. And they basically were succeeding so wildly that they single-handedly almost had enough to support a major new interstate pipeline out of the area, and that's exactly what happened. When you do a project like that, you're forced to go to an open season, and we did that and Southwest Energy also came on board for a chunk of this capacity and off we go. The project, as you can imagine, going through the state of New York is not without its challenges, but we've had a lot of stakeholder involvement. We probably had a more significant outreach project with stakeholders on this thing than anything that we've ever done. And it's moving along well. We're still on schedule. We're still on budget, and we still think we can make our original end-service date, so. Won't be without its challenges, but we're still stepping through it and feel like we're in good shape on the project.
Gulfstream, probably something you've all heard about a lot. This is a -- the little train that could, here. They were probably out of expansions on this system, unless we were to put compression out in the Gulf of Mexico, which currently does not exist, but the pipeline is fully subscribed. We've got average contract life of 17 years on the project, and it's a great income producer and one that served us well. I'm going to start to move on to something completely different now. I've got the Transco asset responsibility, as well as our Gulf of Mexico Midstream businesses, which are predominantly deepwater, oil discovery driven, and to get discoveries, you've got to get out there and drill. So we had a pretty big setback back in June of 2010, when the Macondo event took place. The moratorium was imposed, and it's taken quite a while to get back up to speed, but I will say, things are -- have ramped back up, as you can see by the pictures on the slide. The success rate of new producers drilling new prospects out in the Gulf of Mexico has been above what we've seen in past years. So things are moving ahead nicely. Projects are coming into the market, and we're competing aggressively. The projects that we think meet our internal standards. This slide here is just an out picturing of the producers that we work heavily with in the Gulf of Mexico. You can see it's kind of a who's who of international oil, given the relatively manageable water conditions in the Gulf and the -- at least on a worldwide standard, the very known, fair and repeatable process that the federal government has in place. Most major producers see this as one of the top places to drill for oil on a risk-adjusted basis, and so that's why you see the big names here. That's why the rigs came back in, and that's why they continue to pour a lot of money into the area. I'm just going to hit this real quick. This is a bit of an overview of our Gulf Coast Midstream business. The -- we've rolled up some of these numbers, just to give you a little bit of a flavor for the scale and scope of what's going on out there. We've got about 2 Bcf a day of gas processing capacity, about 3 Bcf a day of gas gathering capacity and just shy of 500,000 barrels a day of oil gathering capacity. And then, probably the biggest earner on the map of potential earners is the one is the middle of the top, the production handling capacity of 188,000-barrel of oil equivalent, and I talk a little bit about -- a little but more about some of that here in a few slides.
I'm going to walk through and talk about each quarter, and I'll give you an idea of some of the main drivers of our guidance period in terms of projects and execution. And then we'll talk just briefly about some of the upsides out there. The -- this map, that orange system, and I don't know if you can see it all the way in the back, but the orange system that runs on-shore there in Louisiana, is our existing Discovery system. I think it was last year, it could have been the year before, towards the end of the year, we entered into a deal with producers to build what we were calling our Keathley Canyon connector, and this is a line that starts on the shelf and runs out pretty close to Mexican waters and to pick up the Anadarko's Lucius discovery and Exxon's Hadrian South discovery. And then, if you remember, is was a bit of a interesting come together, and they decided to codevelop. And the fact that Hadrian South was a pure gas discovery, allowed us to put some over sizing into this pipe, and as such, it will only be needed for a couple of years, but it makes for some ready-made backfill opportunity for this great neighborhood that we're in. I'll talk just a bit about the neighborhood. I know that map is probably too small for any of you to read those names, but just talking generally about the end of the pipe down here, these original discoveries were Miocene. There's also some lower tertiary wells that have been drilled out here. Phoboswas just announced as a discovery in the lower tertiary, but the thing that's really interesting there is that producers have come a little further inland, and in this area, that's just north of the end of the pipe here. They've started drilling into that's called the lower tertiary inboard play, and the success rates have been very high there. We, in fact, have got 3 or 4 that we think are going to be targets for us, to go out and compete for, to bring into this system. And I might add, there are a couple of things that already have been added to the mix. Hadrian North is a discovery that Exxon had. It's already dedicated, and assume, once space tanks, and that will be becoming into the pipe, and then at Heidelberg, which is an Anadarko discovery, is dedicated, and we got the contracts done on that a few months ago, and that's dedicated to the system as well. So a lot of good things happening here. We were able to build a lot of back end capacity, if you will, just about 3 to 4 years into the life of this system. And the neighborhood looks fantastic, and we think we're going to be able to add a bunch of low-cost opportunities into -- to get the cash flows up and without a lot of additional investment. Heidelberg, for instance, was a -- was the project that I mentioned we just contracted for. We have no CapEx on that, so once you've got the main piece of infrastructure out there, it's a little easier to allow the producer to tie to you, and so you get a nice chunk of revenue without any additional capital expense.
Over in the Eastern Gulf, I'll just hit a couple of things here. The big story is not listed on the call out here, but for this area, the tubular bells floater, and I'll talk little bit about Gulfstar in general, on a subsequent slide, but that's the big opportunity here for us, in the Eastern Gulf. The project is going very well. All that's being built here, at least the major pieces that are being built here in the United States. We've got the hull under construction down at Ingleside, near Corpus Christi. And the top sides are at Gulf Island fabricators in -- near Houma, Louisiana. The project's going very well. We're looking at an in-service date of mid-2014, and we'll be starting our offshore campaign here in just a handful of months. So everything's looking very good on that. That's a very significant mover, in fact we'll look at some of the EBITDA numbers here in a minute, you'll be able to see the impact that some of these projects have on our earnings. Also, a lot of other exciting things going on there. We've got a number of potential tie-back opportunities. Nice thing about tie-back opportunities is, they usually come with a pretty healthy rate per barrel. You're normally talking about something and I just happened to throw out a really wide range, about $5 to $15 a barrel, and so it adds up pretty fast. And if you got the existing floating production system there, you probably can get producer to pickup the capital. So the best kind of contract of all, creates a lot of revenue without capital needing to be spent. So Kodiak, is a great tie-back opportunity that we're pretty far along on. Gunflint is -- could be a tie-back, also could be a new Gulfstar application, it kind of depends on this well that they're drilling right now. Big Bend is right out here, on the end of the pipe. Big Bend and Troubadour, which hasn't been drilled yet, but Big Bend has, and it was an announced discovery by Noble, that's a possible tie-back for us. And then probably, the biggest opportunity on this map is over in this area, this labeled the Northwood play. The -- this is actually all Jurassic aged potential in here. And the only place we've seen this Northwest produce is up here in Mobile Bay. This is the first time that we've seen people drill it successfully down the Gulf of Mexico. But Shell has several discoveries there, primarily in Appomattox, and they are in the process of putting their development plans together and we certainly would like to be part of that as well. So another big opportunity there.
Last but not least, I'll hit this real quick. This is our Gulf of Mexico corridor. This is where our Boomvang, Nansen prospects -- or excuse me, discoveries that we tied in many years ago, producing and our per-DO -- pipeline ties in as well out here to the Shell fields rights near the US-Mexican waters. A lot of other exciting things going on out here, Anadarko has a prospect that they're drilling at their -- below their existing Nansen discoveries, it's called Nansen Deep. Again, that would be great discovery if they hit something there, there's a floater already in place, and we've got a number of the blocks dedicated as well. So again, that could be something that provides pretty near-term cash flow, and it doesn't require any capital on our part. The other thing that's happening is -- down on this map, is down here in the Mexican waters. We've been talking about PEMEX for a long time. They -- we all knew that they had this acreage, that they had prospects. The big difference now is that they've drilled them, and Trion, and Supremus, are both announced discoveries. Maximino is drilling right now and is supposed to be the biggest prospect that they have in the play, and then they also drilling a prospect called PEP, but we couldn't find the location of that on the map. But so there's 2 aspects drilling out here. We think we're in a good position to participate, once they're ready to come to market. And again, this is nothing but thin guidance, but just these things that are out there. And we see coming.
Maybe I'll finish up here with some of the Midstream-specific discussion with our Gulfstar product. But Williams having a product is kind of an unusual thing. We don't typically do that, but we saw the need out there. We saw producer after producer start with a clean sheet of paper every time that they wanted to bring a discovery to market. And they would design generally the same thing, and it's really hard to guess exactly what you're going to get from the initial data you have. So it usually wasn't quite the right size, and they didn't usually have quite the exact mix of gas to oil, and the gas content or the NGL content was always off, and so even though they spent a lot of time and energy making it perfect, once the production got up, it's usually wasn't very perfect. They just, they're that accurate, and so we thought a speed-to-market solution, Design 1 built many kind of concept, made a lot of sense and we were lucky enough to sell one of those to hefs and Chevron for the tubular bells field, and I think so far everything is going great on the project. We've gotten a lot of interest as well. We talked to probably a new party every other week about an application. Now I'm not saying we're going to sell that many, but we're looking hard to find the next place that we wanted to deploy one of these GulfStar facilities. And as Alan mentioned, part of the romance is tying it into our existing infrastructure, getting those downstream coupons. In the case of tubular bells, they're collecting coupons from the dry spot here, in the Gulf of Mexico all the way to New York city gate. And that gives you a lot of leverage on those investment dollars. The other thing that we did here, that Alan mentioned, we did sell off half of this asset to Marubeni, and it's a great investment, they'll do great on it, but that further leverages our investment dollar with 100% of those downstream coupons, and get just the kind of returns that make a pretty big impact on the company bottom line. So we see more chance to do these in the future. I will note that there's 1 typo on this slide, that water depth of 4,040 feet. That should have been down here on GulfStar 1. The actual design of -- our generic design is good to 8,500 feet, which would cover just about anything in the Gulf. In fact, those PEMEX prospects that we talked about on the slide before at 8,200 feet, just to give you an idea of what really deep is. Maybe just a chance to -- we'll just take a chance to go over some of the projects that we've talked about. These are the things that are really going to be driving our guidance over the next 3 years, the things that we're focusing on intently to deliver those results. We talked about the -- the only one that doesn't fall into that category would be the Dalton Expansion, that is not under contract yet, but everything else in the blue colored boxes is under contract. It's well underway, we've got -- we have a couple of projects on there that are over budget. We've got a couple that are going to be a month or 2 late. We've got 3 or 4 that are going to be under budget, and we've got a few that are on budget. So in general, I'd say it's a pretty good performance out of this area, and it's something that we're hoping to replicate. If you think about that, that cash flow and how it relates to these projects, that we've been looking at, this just goes to show our adjusted segment profit, plus DD&A, over each of these years, and above each of the bars, you can see the projects that would come on each year, that would add to that, and that takes us from that, somewhere around $900 million of EBITDA, up to over $1.4 billion in that 3 year period. So a lot going on, but a lot of this work is the work of needle movers. These projects do add up, and we think that's pretty strong performance from these assets that have been the backbone of the company for a long time. I might also add, just to be clear, that royal blue at the bottom, that's kind of the base business, other than the colored tranches stacked on top of that, and that last year, 2015, that's just a partial year of '15. So if you went out to '16, you'd see that would be above that 1.4 as well, just from getting a full year of those 2015 projects on. I think this is a slide that everybody has had a chance to see. We've got segment profit, plus DD&A shown here from '12 through '15, and you can see that's a compounded annual growth rate of about 16%, and that's even with taking a dip in '16. So a lot of strong growth. It gives you a sense there of our CapEx, we've had pretty steady maintenance capital out here. Don't really see that changing much, but anyway, we're very satisfied with those results, and intend on delivering them.
Just some key points here, to wrap up, I talked about Transco being a -- the nation's largest interstate pipeline system. I think it definitely fits the moniker that Alan threw out, about a -- premier assets. We think this is definitely a premier asset. I talked a lot about the power generation growth. We see that continuing, but probably at an accelerated rate, given some of the regulation that's out there, that putting some wind into the sales of people's time lines. We see the royal discoveries in the Gulf of Mexico, being a big driver for additional infrastructure in the deepwater, and associated infrastructure on shore, and we've got a nice portfolio of contracts that are well underway, and we're intent on executing on those. So with that, I'm going to pause and be happy to take any questions you might have.
Thanks. So what's the net impact from -- so you talked about a little bit in your prepared remarks there, what's the net impact from customers that are using long haul capacity on Transco? Slowly, kind of -- shutting from that long haul capacity and then the new producer-customers picking up the capacity on a short haul basis? And then Marcellus, is there a number that you guys can come up with?
Rory Lee Miller
We haven't seen any of that yet, but it's conceivable, I guess. It will take a while to see if there's any movement in that direction. Right now everything's fully contracted on the system, and as contracts roll off, we really don't have any experience of not being able to resell the space. I guess it's possible that, as we're reselling space, you could see different players come in and taking that space, but the good news is, the markets are there, the markets aren't going away, and they'll need to take space from 1 end to the other, and a lot of our strongest-growing markets are kind of in the middle of the system. So we -- as I showed those projects, a lot of them are being designed and oriented in a way that are causing us to make investments in the system, so we can actually flow gas from north to south. So we're building a lot of flexibility into the system, and as we get things rolling off, I'm confident we'll continue to be able to sell that space, and I can say the markets aren't going away.
Alan S. Armstrong
Actually, if that happened, which I don't expect it will, because the rate from the long haul is a lot cheaper than the rate, just coming out of Leidy, for instance, into, sort of the new transport capacity is 50% to 100% higher than the long haul capacity. So I think it'd be pretty strange for somebody to give up the capacity they have today into the market, to buy more expensive capacity to serve that same market.
Okay, got it. Just on the Gulfstar opportunity. You talked about how the project works in -- at water depths to 800 [ph] feet. So have you been pushing more into the lower tertiary? Are there lower tertiary projects that -- now kind of fall into this Gulfstar, sort of opportunity? Or is the -- my understanding is, this is always kind of a lower Miocene, sort of 100 million barrels of oil sort of resource, sort of project, and being that, as you push into those -- you'd hire these deeper water depths you're talking about, 200 million, 300 million, 500 billion barrels of oil equivalent, so.
Rory Lee Miller
Yes. If you start getting up that 500 million-barrel range, something like that, you're probably talking about a bigger class of facility. Even in the lower tertiary, they're not all that big. The other thing that we've seen is some producers -- and there's a big dog out there right now that had this problem, started designing topsides for a major facility and before long had 37,000 tons of topside capacity, which takes 4 offshore lifts just to set the topsides on the whole offshore. I think the result was they canceled the project and now we're seeing an opportunity to go back in and possibly sell several smaller floaters, sell several GulfStars, and actually build something that we have the capability to install. It's like a lot of things. There's economies of scale as you make something bigger, they become more and more efficient. And then at some point, it breaks over and everything gets so big and it starts exceeding the size of your lifting equipment and what's easily done and everything is custom ordered and then it starts to break over and you actually become less efficient. And so we're starting to see that. I'm not suggesting that we're targeting GulfStar after 500 million-barrel discoveries, but I'm just saying we are finding interest in places that we didn't think we would. I think the lower tertiary application though will work in some places. Other places where the lower tertiary is found in much shallower water depths, they're not going to have enough reservoir pressure to push all the way to the surface and so they're probably using some kind of submersible pumps and a sump system and then drive it, overcome that hydrostatic head, drive it to the surface with the pumping suite and sump. Some of those are probably are a little exotic and wouldn't be good application for GulfStar, but we're planning to do fit.
In your Deepwater business, who do you typically find yourself competing against? And what sort of returns on investment do you targeted in that segment?
Rory Lee Miller
Yes, there's definitely less third-party players out there competing in the deepwater space than there are onshore. Enterprise still has some activity out there, Enbridge has a little activity out there, but they've been pretty selective, as have we. We tend to chase the ones where we think we're very well-suited to win, and I think they've done something very similar. But the main competition though in most of the things we've gone after recently have been the producers themselves. They'll always use -- and self-building is kind of their baseline for going forward with a project, take a look of what we'll do, what our ideas are and how we might price the business. And so I would say that's probably the main competitor today. In terms of returns, the returns are probably in the mid to high teens on something that have a lot of demand or fix payment associated with it, with upside pitched into the 20s or something like that.
Looking at Pages E-22 E-23, why is the segment adjusted -- adjusted segment profit plus DD&A down in '13 and supposed to go down for the base again in '14, but then grow in '15? And whats the full year impact of the projects that we're going to -- for the year '15, what would be the full year profit when those fully ramp?
Rory Lee Miller
Yes, let me pick off a couple of pieces. That some of the base is related to NGL margins. We do have some exposure there on NGL margins. And as we've seen in a lot of the areas, that is going away to some degree or is lessening. And so we've got some of that there. We've also got a rate case that we're going through and so there's some assumptions in there around that. And those are probably the main drivers on the base. I don't know, Don, Alan, can you think of anything else? And then I don't have the exact number on '16 and Don, I don't know if we we're going to release that anyway.
Donald R. Chappel
We would not provide a guidance by the project, but I think you can take the capital schedule, it's in my section, where we do detail. It's on G15. We detailed the projects that are in Rory's section and you can take the amount of capital and assume a rate of return. I would warn that in certain cases, the early returns can either be stronger than the average or weaker than the average depending on the shape of the production curve and I don't know if Rory can shed some light on that, but these are not necessarily level investments. They really fit into the portfolio nicely, but each of them has a shape to it.
Rory Lee Miller
And it tends to be a little more front-end loaded. So the first full year is pretty meaningful. Looks like it. Okay. Thank you.
J. Michael Stice
Good afternoon, everyone. I'm Mike Stice, CEO of Access Midstream. We're going to tag team this a bit. I've asked our CFO, Dave Shiels, to come and take a few of the financial slides and highlights. I'll get started with the baseball analogy. If Rory would clean up, I guess, I'm at the bottom line up. I hope that doesn't mean that I don't know how to hit, that's generally what gets reserved to the bottom line up. But anyway, I am excited to be here. Our new partner, Williams, it's a great story, great relationship. We're obviously benefiting from this wonderful relationship, which I've had with Alan since the school days. So we won't go to that far back, but that's how these things always get started.
But let me just begin with the forward-looking statement, it's important that we have to repeat. You guys, I won't read this, of course. What an amazing year we had. I mean, I go back to April-ish about 1 year ago and a lot has changed for Access Midstream, including its name. I'm awfully proud of the accomplishments that we've had over the past year. With those of you who aren't as familiar with our business, I think it's important to highlight some of the things that have occurred.
First, it was the transaction. The transaction that I'm referring to is not only Williams purchasing GIP's interest in the General Partner and openly 23% of the LP units which divested GIP's Fund I interest. It was also the $2.2 billion acquisition of the remaining assets that was in Chesapeake. Chesapeake Midstream Development, which gave us the basin diversification that you're going to hear about here shortly. Pretty exciting deal for us. It meant that we keep our organization together that was executing on the tremendous capital program in 2012. But in addition to that transaction was the transition, and we're using that term to define the fact that previously, we were connected to the hip with Chesapeake. We had all of our back off of accounting, everything around IT. If you could imagine, if it could be leveraged, we were leveraging it. And so there was an enormous undertaking, which is still underway since July 28, separating ourselves from Chesapeake.
And we took it in stages. As you can imagine, Phase I, we completed in September, which is around identifying the people that we would need, both in the front, mid and all to read [ph] back office services. By the end of the year, we had our own benefits program, everything was isolated and by January, we had physically moved, and so our pipeline control center had left the basement of Building 13 on Chesapeake's campus and moved over to our newfound building over on Lincoln. And then we were engaged in the next quarter business, which was the IT side of the business. And we're right now engaged in a very important 90-day exercise in transitioning all of our IT back office from the new data center to application, et cetera. We're roughly 75% complete with a transition. The things that we've yet to be done are the things that you would consider to be SCADA or information exchange from the field, how we get data from the well head into the field -- or into the headquarter's location so that we can automatically deal with all that data. So we still have some work to do. We're targeting being finished by the end of the year, but it's been a major undertaking.
All of that, the transaction, the transition, took place while we still executed flawlessly on over a $2 billion capital program in 2012. And I combined the Chesapeake Midstream Development with the Access Midstream Partners' portfolio because we were operating both through the end of the year. So it's an enormous undertaking. We accumulated 6,000 miles in pipe, almost 8,000 wells were connected and we have an average throughput of gathering assets of 3.6 Bcf a day. Those are net volumes, if you look at growth, but my weekly report that I look at everyday, is roughly 4.7 Bcf a day. And to Frank Billings' point, roughly 2 Bcf a day of that 4.7 Bcf comes from the Bradford and Susquehanna Counties off the Marcellus. So I can reiterate the confidence that he has placed and the success that we've seen in the Marcellus dry gas play.
The opportunity are -- well, let me just go to the unit price performance. Hopefully, this is self-explanatory. We've shown here in green kind of our performance since IPO. The blue is the Alerian performance and we're really proud that we've got a total annual return of 36% as compared to the Alerian at 13%. And I think it's something that we're appreciative of the fact that people can see the promise in our contracts, in our business model. We're 100% fee based and the combination of that fee-based structure with the unique access to growth that's driven by these unconventional basins is what's leading to this return.
So the opportunities that we see, obviously there's an enormous amount of additional capital that has to be deployed. You heard the conversation that -- with Frank, we're no different, we have kind of a lognormal capital program, we have an upfront spending in each of these basins. Over the course of the next 3 years, we have a $3.5 billion capital plan. We have the addition of the Chesapeake assets that we acquired in December, the transaction driving the growth immediately. There are various stages. If you can imagine, dry gas plays, the growth comes, the capital is almost immediately followed by the EBITDA. In the liquids-rich plays, the capital is delayed as you open the land, put it in processing, in fractionation, et cetera. And so there's a lag between that upfront capital and opening that EBITDA.
This has been the year of the Marcellus. Marcellus is connected in a number of wells and achieving new -- every week, we get a new goal. Next year will be the year of the Utica. You could also argue that this year, we also have the year of the Eagle Ford. We're blessed with a lot of growing basins and growing opportunities.
One of the points that I'd like to make that's happening in our business is the expanded services that [indiscernible] is looking for. I'll show you some slides here and talk about it. But as you can imagine, no longer are they just looking for dry gas dehydration and compression. Now they need some additional services and in some cases, have to get injection and treating, they also need processing and fractionation in the Utica. And that's an exciting thing for us, because it's more the same with regard to our business model. It's more fee-based business, non-commodity priced business that we can attached to our broader extended services.
The third opportunity we're seeing and it's actually being accelerated now, is the bolt-on acquisitions. What I mean by that is that we have these, what I would consider, large scope and scale footprint as a result of being Chesapeake's midstream service provider. A lot of the advantages of being Chesapeake's midstream service provider is that they have the largest acreage position dedicated to us. They were the most aggressive and most active. So our footprint, we not only have the first-mover advantage, it had the largest scale. So in every unconventional basin that they were there, there we were. And so that's giving us an advantage when it comes to bolt-on acquisitions. Smaller positions were taken in and around largely, like Rory was talking about, by the producer, and then they finally decide to monetize that and we're the natural consolidator in those conversations. So we're seeing a number of these bolt-on acquisition surface and we're excited about what that role could mean for us in the future.
The transaction itself, its greatest benefit to us was the increased diversification. Not only increased diversification across basins, but also the fact that some of these basins are gas and some of them are liquids. And so you have this different economic motivation that's driving the drill bit and that's beneficial.
In addition, we're getting enhanced exposure to non-Chesapeake. Today, 77% of our revenue is tied to Chesapeake. Something [indiscernible] comment to from time to time. We're busily engaged in reducing that number and have a commitment to get it down below 50% by 2015. And that's going to happen in a number of ways, many of which are being driven by Chesapeake's divestment strategy. And once they divest, our contracts travel with the land, and then we get the new producer as a result. You may have seen that happen in the Permian when they sold to Shell. A number of transactions when they sold to Total, et cetera.
The last point on this slide for the opportunities is leveraging our sponsorship. Obviously, Williams brings an enormous amount of wisdom and experience on board, but we're able to go beyond that and actually leverage some of the experience that Williams has in the engineering standards and technology. We're obviously a very young company. Williams is a company that's been around in this business for many, many years. And every chance we have to go and develop something new, we always touch base with Williams to make sure that it hasn't already been done before and if there's a way to leverage that so that we can get smart in executing whatever those are. We've seen benefits in the standard size, we've seen benefits in emergency response, we've seen benefits in data center. It's just been an enormously positive relationship and we're very excited about it.
GIP, at the same time, is continuing to do the things that they do best in helping us analyze and value some of these bolt-ons. They're very rigorous in analysis and very helpful in trying to create contracts that stay consistent with our business model to mitigate the risks. So these are the opportunities that we see at Access Midstream and they continue to be something we're going to be able to take advantage of for some time.
So let me get a few slides very briefly. This is really a map of our basins and you can see our total investment capital is almost $7 billion. We have almost 9 million dedicated acres. There's no other midstream company that's got that kind of dedication and the kinds of contracts that we have that are designed to create a win-win relationship between us and the producer. The concept is, we get a mid-teens return in a cost-of-service-like structure where the capital risks and the volume risks are included in the fee setting mechanism.
We're 1,300 employees today and growing every day. Probably planning to be around for hundred 1,450 by the end of the year, given that we are able to hire all the people that we need to bring in. We're also proud of being the largest gathering and processing MLP from a throughput standpoint. That's a lot to say given the fact that we didn't exist before July 2010. So a very young company.
When you look at the Eagle Ford , you can see that already in a very short period of time, we put in the ground over 687 miles of pipeline. We have 228 million a day of throughput. You can see the footprint here is fairly diverse. It's an exciting play. We've got a number of construction crews out there, 7 as we speak. We have almost 1.4 million acres dedicated to us. So we have a lot of opportunity yet to play. And all of this is under a cost of service contract with one added contractual feature, which we put some volume tiers in it, so that it can ultimately get early recognition of EBITDA in the Eagle Ford.
Dos Hermanos is one of our compression facilities. Thought we'd mix it up, show a few pictures so you can see kind of what we do. This is one of the compression facilities on the south western end of the Eagle Ford. One of the expanded services I commented about. Most of you don't appreciate, the Eagle Ford is a sweet reservoir. Unfortunately, there's some communication between the Buda and the Eagle Ford, which make some of the wells almost randomly sour. So as a result, we're having to deal with, in some cases, 20,000 parts per million of H2S on some of these pads and for those of you who aren't familiar, that's a lot of H2S. You have to be very careful the way you're doing it, dealing with that kind of quantity.
And so were covered in aiming systems and ultimately we're going to provide an extended service with an acid gas disposal well. This is the rig that just completed drilling, our acid gas injection well. And so that would be one of the services that we'll be providing to producers, not just Chesapeake but basin-wide.
In the Utica, a lot of questions were asked of Alan and Frank earlier. The way I look at it, that Alan's got multiple horses in this horse race, a good way to win a race. I can only speak to one, it's a thoroughbred, Alan. But I think, one of the things that I can appreciate here is that our Utica strategy has really 3 different components. As everybody is aware, the Utica has got a dry gas zone, it's got a wet gas zone, it's got an oil zone. We have got the bulk of the Chesapeake acreage, Total acreage, dedicated to us in the wet gas zone, okay? And so we've tag teamed our relationship in the wet gas zone where it's Cardinal, which Access owns 60% to 76% interest in, and as the operator gathers all of that wet gas. And then we turn it over to Utica East Ohio, which is operated by Momentum, and they're building out the processing and fractionation infrastructure. For those of you who are in our business, it's kind of a household need to speak about Mount Bellevue. It's household name to speak about Conway. This is where a large amount of NGL hub. It won't be long, you'd be speaking about the Harrison hub in the central of Ohio. That's how meaningful this investment is.
So Utica East Ohio is our 49% owned, operated by Momentum processing and fractionation business. You can see here the kind of facilities and storage we're putting in and why I think it's going to be such a meaningful asset for the industry. And if you want to just see some of the facility that's already on the ground, and if you're not -- I'm a project guy, I build a lot of projects, this is a world scale facility. This is the Kensington plant that will be the home of 600 million cubic feet a day of gas processing, three 200 million a day plant. This is the Harrison Hub near Scio, Pennsylvania, which will be that famous place for storage. What you can see in this picture is the rail facilities that are built. It's an enormous amount of storage and rail offloading and onloading for all of the various products that you've heard more about today, propane, iso/normal, natural. Lots of opportunities for bolt-on projects as we meet the local needs for those heavier hydrocarbons, even the potential for some condensate upgrading there at this facility.
So Harrison hub is really coming along well and we're excited about it. We're bringing these plants off and on in phases. The way to think about it is bringing the first gas plant and the first fractionator on. That's roughly a 200 million a day plant, 36,000 barrel a day of fractionation requirement. Bring that on and then 6 months later -- that will come on late this summer. And then every 6 months you bring on another train of gas and another processing and another train of fractionation.
The Utica Gas Gathering System, that's the dry gas component and in blue there, called UGS, where we also have a Chesapeake dedication, and we're gathering that gas. We're seeing some real promising activity out there by the industry in general, not just by Chesapeake. And then the green is the dedicated area from Cardinal, which we're doing the gathering and then redelivering to our friends at Momentum.
Here's the Corridor, that's a 24-inch and 12-inch diameter pipe. That's the Bergholz/Kilgore Corridor that runs north and south. It ties the 2 facilities together. Here's the Carrollton compressor station. It's hard to believe that this is in the very early stages of the Utica development and look at all the asset that's already on the ground in preparation for this grand development that's going to take place all over Ohio Basin.
Niobrara is an even younger asset, but one that's very exciting for us. RKI and Chesapeake have a 50-50 joint venture. We acquired Chesapeake's interest in the midstream and got their acreage dedication as a part of that transaction I talked about earlier. It's been announced that RKI has entered into a Letter of Intent with Crestwood who will be our partner, a non-operator. We'll be the operator of this facility.
We're just getting started here, but it appears that the producers are just now getting traction. They cracked the code. We're seeing excellent wells. We have 2 gas gathering systems, the Jackalope gas gathering system in Stage Creek. It's only -- we've got 100 miles of pipeline in place, but it's just now ramping up. And so this is going to be an exciting play, so stay tuned.
I love the fact that every one of these areas have a different view. Here's the scenic Niobrara. As you can imagine, it's got a construction window you have to be very respectful of. Williams has a lot of experience up here. We will be able to leverage some of that knowledge, I'm sure. Here's the drilling rig at the Wagonhound Ranch. That's on our Jackalope gas gathering system.
Here's the Antelope compressor facility. One thing I'd point out, up in this weather, you've got to put everything under a building. Otherwise, you had to operate in the kind of cold temperatures and winds that we do. It's a little different application.
And then I'm going to turn it over to Dave and let him share with you some of the financial results. By the way, they challenged me to go fast. Am I doing good? Okay.
David C. Shiels
Thanks a lot, Mike. Before I get into the details of the financial slides, I just want to mention our non-GAAP reconciliation is on accessmidstream.com if you're interested. So there's far more interesting information on accessmidstream.com than the non-GAAP reconciliations, but you're welcome to go check that out at your leisure.
Okay, so on Page 21 I get to present really a fabulous slide. This shows Access Midstream's performance -- financial performance, over the last 10 quarters. And needless to say, it is extremely impressive. So as Mike said, we're less than 3 years old, so over 10 quarters, in the top left you can see the adjusted EBITDA growing at annual rate of 51%. We were very excited to report first quarter earnings, $184 million of adjusted EBITDA. Really it was investors' first opportunity to see the business in its new form with the new assets from the December transaction. And I think everyone was delighted with that result. So tremendous growth quarter-to-quarter in the business since day 1, July of 2010, when we launched the IPO.
On the right-hand side, equally as impressive is the enterprise value growth. So we kicked this thing off with the $2.6 billion enterprise value at IPO in July 2010, and as of the end of the first quarter, over $10 billion. So just remarkable performance as we've grown the business here in a few short years of existence.
In the bottom left-hand corner is the distribution growth, and Mike in the board has reached consistent distribution growth since day 1 and I don't think it could get any more consistent than what you have on the slide there. We have grown distribution almost precisely 15% annually every quarter since the first quarter we reported. So we continue to do that through first quarter of 2013.
And then the result is the distribution coverage. So when you're growing EBITDA at 50% annually and you're growing the distribution at 15%, clearly, you're going to have improved distribution coverage growth over time and lo,, and behold, that's what we have in the bottom right-hand corner. So 1.4x covered in the first quarter results, a quarter removed from the biggest acquisition in our short history. And even if you back out or you cash pay on the PIK units we used in December to fund the transaction, you're still at 1.3x. So really, just fabulous financial performance in the last few years and it just continues to get better.
Last week at our Investor Analyst Meeting in this very room, we launched our 2015 guidance that we've laid in the page here. So no change in 2013 and 2014. Continue to be confident and have good line of sight to those numbers. We have added 2015 EBITDA, $1.2 billion to $1.3 billion. So roughly 20% growth over and above 2014 performance. Growth capital, another $800 million to $900 million of growth capital. All these numbers on the page are organic. So it's all based off of assets in the portfolio today, right, so there's no M&A included. And we love the fact that we can go out 3 years with what we think is really good visibility with our no-commodity exposure, low-risk business model contract structure that Mike talked about. We feel very comfortable going out over a 3-year period and giving the investors some line of sight to where our business is headed.
Okay. We want to talk about cost of service model a little bit here. Back in the earlier drop-down model, we didn't talk much about how the cost of service models work and how growth is embedded within the cost of service models. But now as an organic growth story with cost of service models in Eagle Ford and Marcellus and Utica, some of our most important basins, it's really important for investors and analysts to understand how the cost of service structure work. So not only does the cost of service model deliver mid-teens returns, low-risk structure over a 15- or 20-year period, which is the length of our contracts, but it also has in it embedded growth.
So we have a little diagram here that's representative of how a cost of service model will look when it's initially built. So within the cost of service model, of course, you have a CapEx profile represented by the bars that are obviously built with upfront CapEx, right. The CapEx is primarily at the front end of the curve. Then the resulting volume in EBITDA deliver a levelized fee. So that levelized fee is used as our throughput fee in the first year. And at that point, as volume changes, as volume forecast change and volume history changes, we relook at this calculation every year. So if volume is a little lighter than what we anticipated, the fee goes higher and the EBITDA curve, the green curve on the screen, is protected. So either way, whatever the case may be in terms of how the volume comes out, how the capital comes out, the EBITDA curve is protected. And within that is embedded growth. So the business will continue to grow through the cost of service model structure, even after the CapEx starts to decline. So as we get out 4, 5, 6 years into our future, what we have is relatively light CapEx burden, right, with growing EBITDA as delivered by the cost of service model. A very important element of our business because it's a cornerstone of how the contracts are built in some of our key basins.
Okay, the funding plan. We have maintained basically the same funding strategy since day 1. So on the IPO Road Show we talked about funding strategy, maintaining strong liquidity, opportunistic market timing, prudent sizing of offerings, deleveraging profile, all the elements you see on the left-hand side. None of that has changed. What we've done here is just taken the numbers that are available to everybody through our guidance and put it on the right-hand chart just to show you how much funding flexibility we have over the next 3 years.
So if you look at the blue bar on the left-hand side, these are funding requirements. So the funding requirements fundamentally is very simple. It's the organic growth capital on the guidance, less the $400 million of equity we issued in the first -- at the end of the first quarter 2013, less the cash coverage that's going to come from the strong coverage that we have inherent in the business. So when you do that math, you get roughly $2.5 billion of funding requirements left in 2013, 2014 and 2015.
On the right hand-side in the green is the debt capacity at conservative leverage. So what I mean by debt capacity is not covenant capacity, right, this is incremental debt capacity at conservative leverage. So conservative leverage delivers $2 billion to $3 billion of debt funding capacity to cover the $2.5 billion of funding requirements in the blue bar. So if we choose to and we want to delever it at one pace, you can 100% debt fund the 3 years here of funding requirements. If you want to delever faster, of course, you could do that with more equity as part of the capital structure. So we have put ourselves in a position exactly where we want to be. Tremendous funding flexibility as we look over the next 3 years.
One of the tenets of our funding strategy is conservative liquidity. Just last week, we announced we expanded our revolving credit facility to $1.75 billion, up from $1 billion previously. So we continue to build upon the same theme to maintain very conservative and flexible liquidity. The credit facility obviously is a huge part of that. And we put this chart together just to show you our discipline in managing liquidity over our short history. And you can see the spike at the end which is just a tuck-on of the liquidity associated with the revolving credit facility that was just closed last week.
And lastly on the financials, strong credit metrics are extremely important to us. Since day 1, we have endeavored to manage with investment grade credit metrics and we continue to do so. If you look at the chart, I think it's pretty remarkable. We've come off the largest acquisition in our history, essentially doubling the size of the company, levering up beyond where we were previously to get -- to fund that acquisition. And even with that, when you look at the first quarter annualized debt-to-EBITDA ratios and compare ACMP to all of the other G&P MLPs, we have the most conservative leverage amongst all of them. So again, one quarter removed from the largest transaction in our history that doubles the size of the company, we have the most conservative leverage amongst our peers. With that, Mike?
J. Michael Stice
Thanks, Dave. Sorry, Don, but I think I have the best CFO in the industry as well. But obviously, we're doing really well from the standpoint of our financial strategy. The organic business that we have now developed, which is granted it shift from the drop-down model, is giving us line of sight to the execution that we have. Now joining us here today is Bob Purgason. His youngest daughter is getting ready to get married, so I think he wouldn't actually prefer to be here, but I'm sure he's having a good time there. But Bob is the one that deserves a lot of credit for the execution of this capital program and we're really excited about the team that is delivering on these results.
So I just wanted to close with a few takeaways. Hopefully, I can get this last one. So from a financial standpoint, Dave shared with you that we've got a 38% -- approximately 30% EBITDA compounded annual growth rate over the period 2011 to 2015, which includes our guidance, not too shabby. And then we've got at that sustained 15% distribution growth. And that line of sight to that is driven by the fact that we have so much certainty in the contract structure, and so much understanding about how the capital is being deployed and the volume is coming on.
From an operation standpoint, we're executing on that $3.5 billion organic CapEx plan, no longer do you have to be concerned with, "Well, how is that next drop-down going to be priced? What's going to be associated with the new transaction." The transactions are all behind us. It's in the portfolio today. So we're focusing on expanding our services and they have a lot of implications to the organization. We have to have processing capability, fractionation capability, organization that can deliver on that aiming, treating and asset injection, et cetera, services frankly that Williams had been providing for years. But it's new to us, and so we're having to build the organizational capability as we execute on that.
I'm awfully proud of our environmental health and safety record. We're leading the industry within the gathering processing. Our first quarter was a 0.35 TRIR, total recordable incident rate. We have some room for improvement on motor vehicle accident. Our average age in our company is 27. Have you ever seen a 27 year-old behind the wheels? It's shows up in our staff. So I'm telling you that we are committed to doing better there. But in generally, we have a culture that's committed to delivering triple 0. When we say triple 0, we mean 0 motor vehicle accident, 0 recordable incident rate and 0 environmental incident. And I happen to have this week's support and had this week with a triple 0, which is very exciting and that takes a lot of organizational commitment and we're really excited about our EHS performance.
So with that I'll stop and answer any questions that you might have. There's one right here on the aisle.
Hey Mike, as you look forward and beyond the $3.5 billion CapEx program, can you continue to sign on new customers and do new projects with the cost of service model and how flexible might you be?
J. Michael Stice
The answer is, yes. I think it varies depending on the basin. So when you get 5 midstreamers in an area, it's likely that the risk transfer is a more difficult challenge. So if for example in Western Oklahoma where you have multiple parties competing for that business, then the midstreamers will usually do a fixed-price deal, so not cost of service, and in the fixed priced deal, you still have the fee-based business, but the transfer of capital risk and volume risk shifts from the producer, generally to the midstreamer. And I'm still very comfortable with that as long as you do the right due diligence and understanding the reservoir and frankly, their drilling plan. Sometimes you can get minimum volume commitments with that to the extent that it's really early. But I still believe the cost of service has a role to play in all development, especially these unconventional plays where they're brand new. So when you get in a brand-new structure, it is actually a good mechanism for keeping the risk with the producer, the risk that they're most capable of managing, and limiting the capital risk and execution risk on the midstreamer. And so it's a balance of risk reward that's designed to do it. Cost of services is a great methodology for MLP structures because you get that line of site and understanding. But I do believe there will be a continuation of cost of service mechanisms forever. Of course, that mechanism has been around forever, so I think it will continue to be one of the tools that we use.
And if I could just follow up, could you just discuss real quickly the mechanism in place for resolution of any conflicts between Williams and Access as you both might go after new deals?
J. Michael Stice
So the real only overlap we have is in the East, somewhat in the Marcellus, but frankly, we're far enough removed that, that hasn't been an issue. In the Utica, obviously, you have 3 Williams members on our board. They're completely firewalled off and are not a part of any of those conversations, we are effectively competitors in the Utica. We -- they recuse themselves from any conversations around that. So that's how we manage that in the area where we are in conflict. In most other areas, this marriage fits like a glove and we actually are cooperative and collaborative in the way we address those areas. But we're not obviously able to do that in the Utica where the competition is direct.
Just on the asset sales that Chesapeake is making to some of the majors and other producers. Generally, are the other buyers kind of happy with the existing gathering and processing feedstock that you have in place or they ask for renegotiations in some of those terms?
J. Michael Stice
No. I mean, our contracts are long term. The recontracting risk has been illuminated by the fact that these are 10-, 15-, 20-year contracts. And these are not just with Chesapeake. I mean, in the Marcellus, in Statoil into the Anadarko. So these are agreement that multiple producers and parties have engaged in, and the answer to your question is, no, there's not a contractual opportunity for them to renegotiate, but also no one's asked to see those renegotiated. Any others? Right over here. John, yes. And always expect a zinger from John. Let's see what he's got.
Mike, just you'd mentioned kind of bolt-on acquisitions, looking at some the overlap in your footprint with Williams in the Northeast. Niobrara is still kind of finding its roots. Where do you think the most realistic kind of tuck-in "acquisitions" would be? I mean, are we looking at Eagle Ford, which is kind of the obvious answer?
J. Michael Stice
Right. Eagle Ford would be one. The way to think about it, John, is anywhere the producer has decided that initially it's best for him to go ahead and build out the initial infrastructure, that's a great short-term solution, but it's not a good long-term because they'll never get the scope and scale they need to get the cost effectiveness that they need. And so those things tend to come back. Another area is the Marcellus where there's been a number of those type of opportunities and I see those -- they're actually intertwined in the Marcellus within our footprint. And we're seeing -- normally, I would expect those conversations to begin much later, like maybe 5 to 7 years down the road. But we're actually seeing the capital requirements for the producer being so high that they're looking to monetize some of their midstream footprint and then of course we look to be the national consolidator in every one of those conversations. So I think you can see that happening in the Eagle Ford and the Marcellus at least initially, and then there are some things that will take place like that in the Utica as well down the road. But consolidation is already moving as a foot. Two more right here?
Could you please go back to your comments on the Buda and Eagle Ford and the existence of sour gas. Is that a revenue opportunity in the sense that it wasn't captured in the original contracts and you can make good margins and returns off of that? Or is that a negative in a sense that you have to pay something back in your cost of service model?
J. Michael Stice
We actually identified it. It's got a separate treating fee associated with it. It's not new that the Buddha was sour. It's always been known. It's not new that some of the wells that are penetrating the Eagle Ford has this random concentration of H2S. We've actually been planning for this acid gas injection. Well it took 1 year to get permitted. So we're just now executing on that plan. And the fees associated that are incremental and they do represent an opportunity, it's just another expanded service, and there's a margin associated with that.
What are your coverage look like in 2015 based on your plan?
J. Michael Stice
Well don't guide on coverage. So I can't provide that, I can tell you that we're going to maintain strong coverage and I think as you look at our growth profile, and the growth rates in the EBITDA, you can see that we have a lot of horsepower to deliver the 15% annual distribution growth and that would like lead to very strong coverage. So we're in a great position to grow the distribution going forward.
That was kind of the way I was going. Your coverage today is quite high. Your leverage ratio is the low end of the peer group. You're fee-based percentages are 100%, what everyone is trying to get to, and you have EBITDA growing substantially faster than distribution that may [indiscernible]. So what is the thought process on holding distribution growth at 15% and presumably allowing the coverage ratio to increase further versus to growing it faster within the next 3 years?
J. Michael Stice
Obviously, distribution cover or distribution policy is set by our board. What you've highlighted is we've got a very, what I consider, a very favorable situation setting up. It would argue that there could be distribution discussions at our board level that would be different than 15% in the future. But obviously, we don't guide to that. We obviously feel confident in the 15%. But that's the board's decision at this point. But you've highlighted exactly the same math we see, and we think it's a great problem to have.
David C. Shiels
And I'll also direct you back to the page on the funding flexibility. So it's part of that funding flexibility math, right, that we have strong coverage, and excess cash goes into the contribution to that funding math that I laid out. So that's another important part of next 2 or 3 years where the CapEx acquirements are heavy. It really allows us, right, the flexibility for on funding plan.
J. Michael Stice
And we're not in a very different position that what you heard Alan talked about. The opportunities are now. And so we're going to be there taking advantage of those opportunities. They're not going to necessarily be there 3 to 5 years from now. Your time to capture opportunities is today. And so we prefer to be very conservative in what we're telling you is our distribution guidance, we're going to be aggressive on these bolt-ons, we're going to try to capture as much of the opportunity that presents itself. And for that reason, we want to see how it plays out before -- none of our bolt-on opportunities are in any of our guidance. So you're looking at a very simplistic view, something that we can easily deliver on. And of course bolt-ons are designed to be accretive and obviously improvement to our overall business. So there's upside from here. One at the back?
Just had a question on the goal to get that -- just the low 50% for our revenues for it. Does that include Chesapeake asset sales that you expect to be may have bought in?
J. Michael Stice
Yes, sir. And in fact, without that strategy, I don't think we can get there that quickly. I mean, it's -- there are several things going on right now. There's the first strategy is that Chesapeake's in the businesses of divesting some of their assets. And when they do, the dedication and the contract terms transfer with the new party. And so that's going to give us some lumpiness, but some step change in that exposure. The second strategy is, most of these bolt-on opportunities come with a new producer with much higher volume than -- ratio-wise than Chesapeake and all the other existing assets. So you get the opportunity to dilute your exposure there as well. And then there's the old-fashioned way, which the old fashion way is to get the gas fires out in the field. We've just now built that organization capability around the first of the year, and we are connecting anything that we can that's within the infield into our gathering system. They like to connect to us because we're there and sort of we're the lowest-cost option to the market. We generally have multiple connects and so we can offer good services to those producers. But frankly, that degree of infield development is slow. And so that's going to take some time to happen. There's a fourth strategy, which I think would take place over time and that is there'll be different buyers buying wellhead gas from Chesapeake and when they do, that will allow them to offload some of the FT requirements that they have. And that move could happen absent any asset sale. And so there's 3 or 4 things working in our favor. All of them working together, it's what I'm counting on to achieve the 50%. Okay. I'm going to turn this back over to our good friends at Williams.
Donald R. Chappel
Mike, Dave, nice job. There you go. Is this your pen? Oh, this is a laser pointer? There we go. Well, good afternoon. I'll run through these slides fairly quickly since you've had a pretty good dose of the business. I think you'll suck this up pretty quickly. And it's also very consistent with what you've seen before, so I won't dwell too long on anything.
In terms of our commodity price assumptions, these are consistent with what we announced earlier in May, but you can see here, we feel pretty comfortable with these assumptions based on where we see the markets today, as well as the fundamental outlook. So we think while there is always some downside risk, we think the upside opportunity is as great as the downside here.
Let's first take a look at WPZ. WPZ, this is some of the key financial statistics here. You can see adjusted segment profit and DD&A or cash were growing by $1.2 billion or about 48% over this guidance period. This is all 2015 versus 2012. As well, distributable cash flow up also $1.2 billion, about 83% during that same period.
Distribution coverage ratio, we're forecasting to recover from this year's $0.9 million, and I would remind everyone, the $0.9 million is supported with potential Williams IDR waivers. Williams has made a commitment to waive up to $200 million of IDRs over the next few quarters to support WPZ during this period. I would just also highlight the fact that Williams enjoys about 75% of the cash flows that come out of WPZ. So waving these IDRs was not nearly as hard as it might appear on the surface because about $150 million of that just stays in WPZ and will ultimately flow to Williams in future distributions. So about $50 million would be what we consider to be the amount of real support offered to public LP investors.
So again, about $200 million important Williams support for WPZ because our futures are linked. WPZ is our primary equity financing source, as well as debt financing source and we believe on having a healthy WPZ and thus, our decision to commit to an IDR waiver to achieve this $0.9 million coverage. Cash distributions per unit also growing in a nice rate, up $0.75 during this period or about 23%. As Alan mentioned, up about 9% this year and then at midpoint of guidance, about 7% for each of '14 and '15.
Just turning the page here and this just summarizes the cash flow growth by business per segment that you saw earlier in the segment presentations. But you can see very strong growth in the Northeast, the Atlantic Gulf, NGL Petchem Services, and then a step down in the west here from '12 to '13 and then relatively steady through 2015 with strong prospects beyond some of the new formations and as gas price moves up a bit.
Turning the page here, and this is a different presentation of information we've provided in the past. We've segmented the Northeast into the various business units out there and we've also dashed the line to depict. This is not one large project in any of those basins. This is many projects, as you saw frank outlined many, many compression, fractionation, cryogenic processing plant, expansions that will come in over time. So this is a continuous growth program and I've just referenced you back to Frank's presentation to provide that kind of more granular view of that. But you can see a large amount of capital is dedicated to the Northeast here, either in our directly owned Ohio Valley, Susquehanna supply hub, as well as our joint ventures.
To step down in the Atlantic Gulf, I think we've got 5 major projects on Transco that Rory spoke to, as well as a couple of major deepwater projects and then one brand-new pipeline, the Constitution Pipeline joint venture up in the Northeast, of which WPZ will have their 51% stake.
Moving down the NGL and Petchem. You can see Geismar expansion going into service later this year and then in the west the Parachute plant expansion which is now in service date of '16. I'll also note here that if you look at this, you can see that our guidance period kind of ends here in the fourth quarter of '15, but in terms of full year effect, there's a lot of projects that are going to service in '15 , you really won't see a full year of earnings on those until 2016. So you can kind of draw a line at the end of '14 and see how many projects and how much investment, even today where we have visibility, is not going to provide a full year of earnings in '15, but really be out in '16 before you see that full year effect.
Alan spoke to the rates of return, and again, kind of targeting low teens, where we see low risk and that's typically in the regulated gas pipeline business. And then up into the mid-20s or north of that where we're taking commodity price risk, the Geismar expansion, the PDH, targeted returns are much higher than that. So $6.8 billion of projects placed into service through 2015, with many more projects on the proposal and negotiation phases.
Turn the page here. We expect the fee-based revenue to grow to about 79% of our business by 2015, while at the same time, the pie is growing from $3.8 billion to $5.1 billion, again, up $1.3 billion or 34%. I would note that if you take a look here at ethane margin, it moved from 3% to 0. So again, assuming no ethane recovery through 2015, as Alan mentioned, there'll be spurts of it, but at this point we don't think it's all that material. So again, we forecasted going from 3% to 0 through 2015. Non-ethane margin as well is kind of -- seeing that from my pointer, from 16% to 6%. So again, the fee based growing quite dramatically as you look at those projects on that prior schedule, those are the big drivers of our growth and the fee-based growth.
This slide illustrates the economic hedge that we have between Geismar and our processing business, and this assumes we hold ethylene and natural gas price constant and really only change the price of ethane. Our guidance assumes about a 0 frac spread per gallon, so we're kind of right here on the 0. Everything to the left of that $0.10 or once we get to 0, we're assuming full ethane rejection. So you see no ethane margin here in yellow. And as we move to the right into positive margins, you see ethane recovery. So that's full ethane recovery; to the left, it's full ethane rejection. Geismar is short, about 750 million gallons of ethane per year following the expansion late this year and so we're full 750 million gallons short when we're in ethane rejection and then if we process fully, it's about 450 million gallons. So we have a net short position of about 300. However, we can certainly grow our ethane position if we felt that, that was the prudent thing to do, as well as our fee-based business tends to grow as ethane is recovered. So Overland Pass is an example, lost ethane transportation revenues in our guidance assumptions from 2013 to 2015 as a result of ethane rejection. So we have a number of other ways in the fee-based business to further flatten this out. So you can see we're relatively insensitive to the movement in ethane price and in fact, a bit short.
Just turn to the prospects and what's in guidance. So again, we've got about $6 billion -- $6.9 billion, call it $7 billion for round numbers, of projects in guidance, 2013 through 2015. Again, largely fee-based. Specifically, WPZ has $3.75 billion of projects in capital investment and guidance for 2013 alone. And if you move over to the right, this includes what's in the guidance as well as what's under negotiation and otherwise identified as potential. We're actually doing work on these projects. That's a $16 billion number over that 5-year period or about $3 billion a year. And as I mentioned earlier, I think there'll be some projects in the proposal stage that will fall by the wayside but there will be plenty of other projects and investment opportunities that will come in to the portfolio. So we think that's a pretty good way to think about it. And this is all without any acquisitions. So this is just really all organic growth right down the fairway of our strategy. So really nothing outside strategy, no acquisitions.
Turn to cash distribution growth, and this is important to all of the us. We have a very strong history of distribution growth, have been growing distributions at about an 11% rate, 9% most recently as a result of the heavy capital investment that we're making along with lower commodity margins. We've lowered our guidance on the 2014 and 2015 growth rate to about 7%. But we think it's still a very healthy growth rate to take a look at the yield on WPZ plus the assumed rate of growth. It's a very attractive return, we believe, for infrastructure assets that are increasingly fee-based and with much growth beyond this guidance period as well.
So just maybe to wrap up on WPZ. Again, very strong growth in distributable cash flow. Growing fee-based business almost 80% by 2015. We certainly have a deep and diverse set of investment opportunities over the next 5-year period and we also have continued strong distribution growth. We've got support from Williams in terms of IDR waivers. Our fortunes are linked and Williams is very supportive of WPZ and take good care of WPZ as well. We're committed to maintaining our investment-grade rating. WPZ has about $2.4 billion of liquidity, as well as really no debt coming due for a number of years. So the maturities are spaced out quite far and we have ample access to the debt and equity capital markets. WPZ will be financing its growth through those debt and equity capital markets transactions and we think that the market will be quite supportive of WPZ as it does it. We talked earlier about the fact that Williams has a growing portfolio of assets that could be dropped down. We think those are long-term options for Williams to exercise and potential backlog of opportunities for WPZ, as well.
Let's turn the page and take a look at Williams, much of this is similar with some differences. Again, cash flow growth about 61% or $1.6 billion over the 3-year period. Capital spending, I would note, again ramps down here but we would expect that to be flat or between '13 and '15 as we see some of these additional opportunities. Bluegrass might be one. Again, Bluegrass is not in our guidance. We would expect CapEx as we see more opportunities to be more steady from '13 to '15 than this graph depicts as we firm those up. Dividends per share growing about $0.91 between '12 to '15 or 76%, with a 20% per year growth rate. Again, 20% per year growth in the dividend per share equates to a 76% increase over the 3-year period from 2012.
Adjusted EPS up nicely as well over the forecast period. It's up $0.44 or 40% from '12 and if you take it off the new lower base after commodity prices rolled back, it's up 112% versus '13.
Again, just looking at cash flows here, expect cash flow increase to 61%. And to provide little color on that, you can see it by segment here. Williams Partners certainly is the lion's share of that, you can see the strong growth from '13 to '15, as well as the increasing contribution from NGL & Petchem Services and ACMP. I'd note that the ACMP numbers are after financing expenses and all expenses, so it's coming in as a distribution rather than before financing costs and the like. So it's much larger business than this slide would depict given the way it's accounted for. But if we move over to the right, even there you can see that WPZ's equity investments in blue which would include Laurel Mountain Midstream in the Northeast, discovery services, producer services and the Gulf Coast, and the Overland Pass Pipeline, you can see that moving up very nicely from '12 through '15 based on the projects and the outlook. So a very large project on discovery to keep the Canyon project and then increase in volumes, especially at Laurel Mountain. And then ACMP, Mike just spoke to, and that's our expected growth related to our equity investment in ACMP, which was pretty volatile. I will speak more about that in just a moment.
Let's turn the page, the slightest very similar to what we just saw at WPZ, we got the first 4 boxes are all WPZ projects. But then we moved down and we pick up at Williams, right here, the WMB, NGL & Petchem Services that are held directly by Williams and that's the Canadian projects and some of the Gulf Coast projects, and you can see the capital by year and again, I ask you to take a look at the projects going to service beyond the end of 2014, as they go into service in '15, you won't see that full year of earnings in '15, it will really be out in '16. And then you can even see that there -- a couple of projects there that are expected to go into service in mid-'16. So the first full year of earnings will be '17. Final point here is it excludes Bluegrass, given that the project is not yet sanctioned. And as well, this does not include ACMP because ACMP is funding its own capital, and that's accounted for and viewed separately. But again, a lot of growth in ACMP as well as in Williams and WPZ.
So on the Williams basis, as we spoke, WPZ is moving to 75 -- 79% fee base, Williams 75%, and that excludes the ACMP which is about 100% fee based. So we feel that our base cash flows are becoming more and more firm as we continue to contract more and more fee-based business and the volumes on these new systems continue to grow on the back of fee-based contracts. But that's up $1.5 billion or 38%. Again, I'll note that ethane, 3% goes to 0, non-ethane margins go from 16% to 6%. And olefins margins, with the great fundamentals that we see over the extended period of time going up from 7% to 14%.
This slide -- and I'll just kind of walk through the components of it to make sure we're all in the same page. But we have a very rapidly fee-based business and a fairly steady commodity-based business with some movement there, but NGLs are down 55% from 2012 through 2015. However, that's offset somewhat by the ethylene and propylene margins that are more firm and growing. So you got a 51% growth in the fee-based business as a result of, again, building volumes on our new systems, as well as all these new projects as they come into service. And again, extending beyond '15, into '16 and beyond. The first column there with [indiscernible] is the fee-based business broken down between regulated and unregulated. The second bar is our commodity risk or commodity margin, broken down between WPZ and Williams, NGL & Petchem services. So again, you can see a 51% growth in the fee-based business and that's really supporting our dividend growth strategy.
Turning the page, this is a similar slide to which we saw at WPZ. The only difference, I would note, is over to the left here, there is some ethane recovery and that's in our Canadian operation that has the benefit of an attractive floor price through its contract with NOVA. So even under current and assumed margin environments that we've assume that would cause us to reject ethane in the U.S., our Canadian business assumes ethane recovery because NOVA needs it and we have a contract that provides an attractive floor price with upside.
Turning the page. Much as with WPZ but with the added benefit of NGL & Petchem Services, owned directly by Williams, as well as the corporate opportunity which is Bluegrass, and you can see that in blue, and maybe some others in there as well, has a prospecting target here of $22 billion over 5 years or about $4.4 billion a year. Our capital this year in 2013 is $4.4 billion. So that -- assuming that those moved over, on a ratable basis, we'll be fairly steady at about $4.4 billion without any acquisitions. Again, some projects may fall by the wayside, others will replace those, but I think that's a fairly good level of spend for us through this point in the cycle, which is, as been mentioned, period in which attractive positions, competitive advantages that will be enjoyed for decades, will be seized. So we believe that this is the time to see such opportunities, particularly when we have the opportunity to do so with fee-based contracts with attractive counterparties.
Just turning to WPZ distributions, what those distribution means to Williams. Over on the left side of that graph here, you can see WPZ's cash flow or segment profit and DD&A growing at a 14% rate, and the distributions to Williams going up 19%. That's combination of LP distributions growing at 12%, and again, how you might think about that is on a per unit basis, growing at about 9% from '12 to '13, and about 7% from '13 to '15 -- 7 to -- I'll get it down the years, plus 7% in '14 and a plus 7% in '15. Plus some additional units being issued causing the total dollars to go up to 12%. That translates to a 30% growth rate in the GP cash flows with the benefit of the IDRs. So very powerful lever there that is a big driver of Williams cash flow growth and supporting our dividend growth.
And this now turns to the dividend growth story. And again, we've been very clear, we expect 20% annual growth rate in dividends in each of '13 over '12, '14 over '13, '15 over '14, as well as an expectation of strong growth beyond given the visibility we have to all of our businesses and investment opportunities, both captured and perspective.
If you look to the right there, you can also see that we have very strong coverage through this period, and this is calculated a couple of slides back, you can see 1.3x the planned level of dividend, 1.34x and 1.33x. So again, very strong growth and very strong cash coverage on the dividend that we believe makes it quite secure.
Let's turn the page and let's look -- kind of look at his graphically. And I would note that there's a little color below in your books, it's been corrected on this slide. And it's up in the legend up here. I think in my book, anyway, things got flipped around a little bit but I'll just kind of walk you through it. So the first line, distributions from WPZ after-tax, and you can see there in 2013, that totals about $1.3 billion, as well as the next item there is a contribution from Williams NGL & Petchem Services, right here, of about $60 million, and that's after some coverage in that business that we calculate. And then finally, distributions from ACMP, right here, which we have in our guidance about $88 million. And then offset with some corporate interest and costs and the like to give us a planned cash flow of $1.278 billion as compared to our $983-million planned dividend. So you can see the coverage there, it's quite strong. And that's where the IDR waivers in this year, you can see by 2014, that moves up nicely at WPZ, boosted by growth in PZs [ph] business, the growth in the distributions, and a lack of IDR waiver in '14. But as well, the NGL & Petchem Services growing nicely, so the distribution that we expected or the, I'll call it, distributable cash flow from that business after coverage, was about $60 million. In '13, it grows to $105 million, in '14, and then by '15, it's up to $175 million, right up here. So then again, this is distributable cash flow from those businesses, which really, a net cash flow before growth CapEx that we would expect to be able to be distributed. For an MLP form, that will be the number that we would target. And that's again growing nicely. ACMP is well growing from, as I mentioned in 2013, $88 million to $120 million. And then up to $187 million by 2015. So again, you can see the components of the growth that drive us to this $1,945,000,000, we'll call it, distributable cash flow at Williams by 2015 compared to a plan dividend level with a 20% per year growth rate of $1,459,000,000. So you can see that we've got about $500 million of coverage out there. So very substantial coverage, and that gives us a great confidence in our ability to continue to drive the dividend at industry-leading levels. We will reinvest that capital in a number of ways. Obviously, we're growing our NGL & Petchem services business and we've got some excess cash flow that we can reinvest in other things like the Bluegrass pipeline.
The next couple of slides have a lot of numbers. I'll just point out a couple of numbers here. Let me go back to ACMP for a moment here. And if we look at the $88 million in 2013, again, we paid about $2.2 billion for the investment we made that gave us 50% of the GP with the IDRs, plus what is now a 23% of the LP units, it was 24% at year-end but ACMP issued equity so we were diluted down a point, but again 50% of the GP with IDRs and now, directly owning 23% of the LP units gives us this $88 million distribution. If we capitalize that at, just call it, 4% yield as a GP, because we're not putting any capital in to grow this, you got a $2.2 billion value right out of the gates here, just the first year after the investment was made. If you use something a little sexier like a 3% yield, that many GPs enjoy, that have high-growth and fee-based business, you get a number that approaches $3 billion. If we look at the value of the LP units that we acquired back in December and compare them to today, $46 million -- the 46 million LP units that we required are up about $11 a share or nearly $500 million. So again, we think this evidenced that this is a terrific investment for Williams and Williams' shareholders.
If we fast-forward to 2015, it gets really big numbers. And if you do the same math that I did a moment ago, in 2015, you take that $187 million in capital as you add in 4% you get $4.7 billion value or double what we invested in. And if you capitalize it at that more sexy 3% loan, you get $6.2 billion or about a $4 billion gain. So again, we feel -- we're very excited about our investment at ACMP, as well as our continued investment and operation of WPZ, as well as our NGL & Petchem services. We think they all combine to produce really industry-leading dividend growth rate with a lot of extra security around that extra cash flow which we can reinvest to produce strong dividend growth well beyond our guidance period.
And with that, I'll just wrap it up and we'll move to Q&A, and Alan will join me for Q&A session as well as our other leaders, who spoke here today are still with us and can take questions as needed. But again, we're in the middle of a natural gas supercycle as Alan described and I think as you know, thus creating enormous opportunities for Williams and ACMP and WPZ as major providers of infrastructure in this space, including the Petchem space. We have large scale positions with strong competitive advantages, and we're taking full advantage of those, and we're building even more competitive advantages as we speak. We have a diverse deep set of assets, as well as a management team that is very much focused on creating a competitively advantage business and driving value for investors in each of these entities. And again, we think we have industry-leading dividend growth rate. I think we're confident of that, that extends many, many years, and as well a very attractive distribution growth rate at WPZ, and as well at ACMP. So with that, I'll just close it up and say thanks for everyone coming, and take your questions.
Don, just a very quick question. G7, example, you had a circle that shows fee-based revenues for PZ pointing to 79% in '15, and similar one for MB. Could you tell us what 2016 would look like with that which you have again those bars that extended over to the right side of all those projects that are not speculative but confirmed? How are those fee-based revenues look in '16?
Donald R. Chappel
Good question. I don't have, at the tip of my finger, your answer, but we can at least take a quick look at some of the projects that are extending further to the right. Well, up in the Northeast, really, all of this is fee-based. So a lot of that growth will extend well beyond, so that's all fee-based. All these Transco fee product projects are really largely fee-based. The Geismar expansion, that's done in '13, the Parachute expansion is largely fee-based, with some commodity. And then probably the -- down here, the NGL & Petchem Services, the Gulf Coast pipelines are all fee-based, but kind of the PDH is commodity, the CNRL upgrader is likely to be more commodity than fee. And then Canadian ethane recovery has a floor price, so it feels like fee with commodity upside. So I don't have an answer offhand, but the percentage is increasing for both WPZ and for Williams. And we'll come back for some additional information on that.
Don, when you look at your guidance, what was pretty good first quarter results. It looks like you kind of kitchen sink the guidance for '13 with pretty low commodity price assumptions. But when you kind of go through that and tilt that back a little bit, you still have relatively aggressive ramp up in the onshore East segment when you look at that. And taking into consideration some of the operational challenges there, what are you -- how do you feel about where you sit today in your guidance, and looking at this operational challenges in that ramp up in the onshore east? Were you pretty comfortable with that, is that possible it slips further? Or how do you balance that?
Donald R. Chappel
I think by if I kick it over to Alan. Do you want to?
Alan S. Armstrong
Is this on? Yes. Thanks. Well, if you look back at that slide that Frank showed, I think we show an average volume of 2 85 or 2 89, I think, for the year. And so, and we're starting off at 1 95, and I would say that we're making pretty good progress on that. If you looked at it at volumes and where we are today, that's been ramping up pretty nicely. Part of that is just because the weather's been warmer and so we're less likely to have the producers, or are less likely to have freeze offs. And so, if we can keep continuous flow going in the pipeline, we tend to have a better sweeps on pipelines. And some of that improvement is just because the weather is a little bit warmer and we'll enjoy that here through the summer and end of the fall. I think in terms of what's required to meet that, were not really relying on whole lot of new production there. We're relying on getting the production that's there, up and flowing which means getting those gas liquids projects that Frank described online. And I think we've got a very robust team up there. We brought in a lot of folks from out West, we've got experience with this. And so it's a matter of executing on that. And I think we're well-positioned to do that. But I guess I would feel pretty nervous about it if it was volumes, it was outside of our control, in other words. And it was a lot of volumes, but the vast majority of that volume is within our control and it's a matter of getting the production up and running. And as Frank said, another element -- so that addresses the volume. Another element that shouldn't be misunderstood there, is that we've been missing out on a lot of revenues that were contractually ours, but we won't provide any [indiscernible] fractionation service. And so we weren't gaining all of the revenues off of every Mcf available because these facilities weren't up and running in the first quarter. So not only will we get a pretty dramatic run up in volume associated with getting liquids out of that system, but we'll also increase on margin per Mcf pretty dramatically. And so I would just say it's pretty invisible but it's going to take execution on our part, and Frank and his team are very confident in their ability to do that.
2 quick ones to Don. What's the thought process on the propane price bump in 2014 and the forecast to $1.15. Your gas, ethane, actually staying flat. So just if you can put some color on that and if that were not to happen, would that change your distribution forecast at WPZ?
Donald R. Chappel
I'd say that our view is at -- would be, with export facilities that are being placed in the service, we expect that to help to balance out the market as well as PDH. So I think we expect the combination of increased demand through things like PDH, as well as through export to bring the market more and balanced, certainly still oversupplied relative to, I guess, long-term fundamentals. But less oversupply than what we're seeing here this year. So that's the assumption. In terms of sensitivities, we do have the sensitivities in the appendix to my section here. And let's just go forward and look at 2014 at a WPZ level. And then a $0.10 change -- excuse me, a $0.01 per gallon change is $2.5 million, so I guess for a long buy, $0.20, that's $50 million. So I don't think that's a big enough to change distribution policy.
Okay, thanks for that color. And the second one is, you have cash taxes going at the end level from 2% to, I think, 14% for '14 and '15. And then you mentioned in the footnotes, it goes up to 26% in '16 and '17. Does this assume Bluegrass in this guidance for '14 and '15?
Donald R. Chappel
No, it is not. And I think a point that I'd like to make is, the 26% would be based on the fact -- of the CapEx that we've guided to you through 2015. And as you can see, there's a very sharp fall off on CapEx in '14 over '13 and '15 as well. So to the extent that we add projects and we continue to invest, let's call it, a 4 billion to 5 billion level, I think you'd see that effective tax rate be dramatically lower.
Don, on the dividend. When you guys think about all the sources of cash at the company and the dividend today and the dividend growth over the long run, how do you guys think about what funds the dividend? Is it certain assets that are of fee-based structure or is it everything including all the commodity sensitive sort of assets, too, and I have a follow up to that.
Donald R. Chappel
Well, I think, I mean, practically, it's all of the assets. But certainly, we put, I'll just call it, a heavy discount on our commodity-based assets. When we think about dividend level. So obviously were in the trough already in some cases, so there's probably not nearly as much downside as there upside on that. But nonetheless, we think that fee-based business is the most reliable and that would be, obviously, the heaviest weighting. And then the commodity-based business is also a contributor, an important contributor, but we think at, I'll call it, a discounted commodity price assumption.
So one more question. On Bluegrass, given your kind of timeline when you want to get that project into service or would like to get into service. What would be the minimum amount of contracting that you would want on that system to sanction the project?
Donald R. Chappel
I'll take that. First of all, I'll remind you that, that system is set up with 200,000 barrels a day of initial capacity, and then 400,000 barrels a day when all the pumping is on. And of course, we have a partner in that, and we're not really in the position today to reveal what we think the commercial terms will be between us and that partner in terms of going ahead. But I would just say that we think that somewhere in the 200,000 barrels a day initial volume would be enough to give us kind of a pipeline kind of return. And we'll decide at that point in time if we go ahead with it or not.
Thank you. If you look forward and appreciate the maturity of this supercycle, then I guess, the opportunity to invest is between now and the next 5 years, where would you see peak years for investments? Is it still ahead of us, I mean, the acquisitions excluded, as we go forward, as you go to more to the right, you'll continue to grow your CapEx budgets, but just when do you see the peak?
Donald R. Chappel
That's a great question. I wish I knew that for sure. It just doesn't seem to be letting off, but I will say that areas like the Marcellus, we're so under -- so lightly infrastructured, if you will. And so much need to increase that, that is going to take a lot of the cost. Say it in another way, it takes a lot more to go in initially and the infrastructure established than it does to add on and continue to increase capacities in an area because that area was so lightly developed. It's taking quite a bit. On the other hand, if you look at the Rockies and you look at where we're showing the growth in the Rockies being at 63% over that 15-year period, that's going to take a whole lot less infrastructure because it's already sitting there. And so, the infrastructure is there, there's a lot of infield drilling, it's just a matter of keeping, expanding those existing systems out there. So I would say, I can't imagine it for us anyway, I can't imagine it getting a whole lot heavier because I think people have staked their positions pretty heavily in these various basins. But on -- so on the basin and supply side, I think it's hard to imagine it getting a lot more intense. But on the demand side, whether it's the Petchem side, in particular, I think the Petchem side has not really even gotten in the stride yet in terms its development. And then the demand side, building out for gas generation, power generation and then continued industrial demand, I think we are just on the front end of the curve in terms of building that out. You saw what Rory's picture looked like and how steep that ramp is through '15. But I'll tell you, there's just a tremendous amount of people trying to take advantage of how low-cost our energy is here in the U.S. around natural gas. And so I think the demand side is a step behind the supply side right now on infrastructure. And as you get in NGLs & Petchems, it is way behind. And I think that's what we're going to see a lot of investment over the next 4 to 5 years, is in the Petchem plants, by the industry in general. I mean a lot of the infrastructure by companies like Williams to support all of that growth.
At -- one of the other Midstream companies, the GP provided a direct commodity hedge to the LP which is an indirect way of doing ideal railworks. What is your thought process on the same with WPZ having it a clean exposure?
Donald R. Chappel
Well, there's a number of options. There are some tax rules related to that, that are -- you have to do it at market. So that's key to getting the right tax treatments. So I think that's always something that has to be very carefully navigated so as not to screw up your MLP qualifying income. But we look at all the options and from time to time, something like that we do examine. So I wouldn't try to indicate that anything like that as in the future for us. But we're certainly mindful of the many opportunities to hedge and we'll continue to evaluate them. But right now, we're comfortable with that the fundamentals are solid at WPZ, and with Williams standing tall to provide some support, we think that WPZ is very, very well-positioned to continue to grow and whether or not commodity prices storm by really building those fee-based business enormously over the next 3 to 5 years.
As you think of -- ACMP, you showed a slide earlier, about $2.5 billion of debt capacity just for organic growth which, if we think about Williams, as you go from $2.8 billion to $4.3 billion of EBITDA over the next few years, will grow by $1.5 billion. I know you want to go to a fourth turn of leverage. But that does give you $6 billion or $7 billion of debt capacity as the first sort of choice as you think of funding some of these projects just organically or as your business gets more fee-based and -- so there's never a lot of debt capacity to fund some of those growth.
Donald R. Chappel
Yes, I think that capacity will be growing. I think right now we're pretty full because we had a capital structure, debt structure pretty well set up when commodity prices rollback. So it cost the credit metrics to be higher than they were initially designed to be. So it's going to take a little bit of time to work through that. But nonetheless, by 2015, 2016, we're building, I think, a very, very large amount of debt capacity at WPZ, Williams and ACMP for that matter.
So then the second question is sort of the same ACMP question. If you execute on your plan and you roll forward to '15, and get through some of the growing pains in the Marcellus and that's through the opportunity set. Do you imagine staying at 1.3x coverage or would the view be the path through the cash? Meaning, understanding you have a lot on your plate but is 1.3 the right number over time? Or do you view that $500 million as sort of additional available capital?
Donald R. Chappel
Yes, at Williams. The 1.3x. That's a good question. That's -- '15 is out there couple of years, and certainly, we like to have the excess coverage so that we can tell you that we feel highly confident in that dividend growth and the like, we'll reinvest that capital in these very attractive return projects, and we'll continue to look at dividend policies. So I think it will be a function of the opportunity set to the extent that the opportunity set to invest continues to be quite high. All that excess cash can be clawed right back in. Or we can do a financial transaction in WPZ and do a drop down. So I think we have many options to ensure that, that cash and cash flow is utilized to create the highest, both combination near and long term values. So we want to create long-term value, but we're also mindful of -- that we keep score every year and that we like to create value in the near term as well as in the long term.
Alan S. Armstrong
I'll just say one thing. The ability to pass on with the same 4% math is very powerful.
Maybe as a related question for Alan, in light of the excess coverage in the backlog of projects. What's your conviction that you can sustain the growth rate in the 20% range for years beyond 2015?
Alan S. Armstrong
Well, I would -- first of all, that seems almost ridiculous, to think that you could do that for the long-term. But I will tell you, given that the kind of investments that we're making right now, which are, as I said, a while ago, I will take full responsibility for sometimes being a little too strategic and thinking too big a picture, and sometimes, certainly loading our balance sheet, particularly in MLP balance sheet. But the positions that we're taking right now are going to be paying off for a long, long time. And so, provided we maintain this kind of robust environment where the market is continuing to expand on volumes both in GLs and natural gas, I think we're in the right spots to continue to grow the business pretty dramatically. So certainly, we're not providing guidance beyond '15 right now. But the fundamentals remain intact, and I would say, as it relates to some of the basins weren't even getting better as we look forward. So I think we're -- it seems ridiculous to think you could maintain that for very long, but it looks pretty good right now.
Alan, this slide up here shows $10 billion of projects. And you talked about maybe turning down some things yet you got the pie charts that show more opportunities down the road. At what point do you feel like you're too stretched to say, "I just can't deal anymore." either operationally or financially? How much more capacity do you [indiscernible]?
Alan S. Armstrong
Yes. Well, certainly today, I would say we are strained, obviously at the PZ and on the balance sheet side. And so that certainly has its allocating capital. And certainly, on the people side as well, people say, "Well, gosh. There's all kinds of people that need jobs. How can you say you're human-constrained?" Getting the A-team in place to execute on all of these projects is one thing, when you start deluding yourself and you wind up having the C-team in place, to execute on this projects, you just add risk. And so I would say were very, very mindful of our human resource and our ability to execute on these projects. One of the reasons that the ACMP acquisition was so attractive, from my perspective, was because we knew that management team, we had a lot of confidence in their business and we had a lot of confidence in their model and their people, and the kind of leadership that Mike has imposed there. And so it made a really nice fit for us, both strategically and financially, but it -- there's only so much more we could do with our organization. And knowing we had A players and weren't taking on a lot of human resource or talk risk, I should say, as we develop the project. So, as you see though, if you look at each of these areas, the capital is coming down in '14, '15, again, not because we're running out, not because we don't think there's going to be opportunities, but because we haven't contracted that business yet. So I think we'll keep the pipeline, the project managers and the E&C side of the organization loaded up for some time, but I don't see escalating it beyond what it is today.
Donald R. Chappel
And just a follow-up from a financial standpoint. We're tight here this year in terms of our financing plans, but quite a bit less on next year and '14. And then we have enormous capacity by 2015. So I think '13 is the tight spot at this point, '14, we have a lot of capacity. So we can sign organic business this year whether there's a modest amount of capital this year, more next year and a lot after. So I think we can continue to do quite a bit of organic development this year, where the capital is fairly light in the year of which we signed. And it gets a little heavier in the next year and quite a bit heavier the year after that. So I think that's kind of what -- how I think about in terms of our funding capacity that's natural to us.
I had a question on the -- for the WMB ratings. I guess kind of getting around the financial flexibility and whatnot. And do you still see a strategic advantage in having investment-grade ratings up at the GP of WPZ? Or given tight levels from the high-yield market now, so what advantage of being a BBB- versus BB land [ph]?
Alan S. Armstrong
We think there's still benefits. Again, we're positioning ourselves with major customers like Shell, Chevron, Exxon, BP, Anadarko and the like. And they're all investment-grade, and they're putting us between their resource in the cash register, and I think one of the differentiators for us is we know how to do large-scale assets, and we have the financial credentials to go along with that. I think that's quite attractive to our producer customers, and as well -- well, money is pretty cheap and easy right now, we all know that in more difficult times, it is not quite so cheap and easy. And the first to suffer are the sub-investment grade companies and we think that in that period, Williams will have even more opportunities to really seize opportunities that perhaps companies with weaker credits cannot see. So we're committed, the board is committed to maintain investment grade ratings at both Williams and WPZ.
Don, I have 2 questions. I'll ask the second one first since it follows on that. It's how are -- how is your management? How is your board preparing for a little bit high interest rates?
Donald R. Chappel
Well, I think, we'll adopt all of our debt -- virtually, all of our debt is fixed-rate debt, so there's no immediate impact. Certainly, the cost of capital and cost of financing will go up somewhat. Our long-term, I'd say, studies of interest rates and MLP capital, they don't correlate entirely, I mean, so that, that spread tends to narrow as interest rates go up, and particularly for companies, they'd have a lot of growth. So if we were low growth, dividend or distribution but low growth, I think we have a pretty significant impact. But with the combination of a cash distribution or dividend with high growth, we think we should be less effective than industries where the growth rate is much, much lower. So we'll adapt to that, but we think we'll be among the haves, not the have-nots.
And then Alan, I think you are one of the first people to predict the pipes going Gulf to Midwest being challenged in the world of Marcellus production. And I'm just trying to put together your -- let me get the come out on your strategic viewpoint, Bluegrass from the blue picture -- or from the big picture. You bid on Southern Union, Southern Union seller clearly saw the same rule. But you did and wanted out, no way they'd build around that. You used to own the Boardwalk pipeline -- it's not called Boardwalk, whatever it's called, Texas order? And so now that's a second pipe that's going to be taken, in effect, out of it's original purpose for the same strategic reason that you predicted many years ago. Just give us a picture, I think that helps Transco no matter -- whether or not Bluegrass gets built or not. But maybe you can just comment on whether or not this was something that you saw when you are bidding for Southern Union, by the way ACMP is a substantially better investment than Southern Union, and just kind of put it all in the big picture in your strategic thinking.
Alan S. Armstrong
Well, it's a great question. And certainly, we realized that pipes going south to north on the gas side were going to be better, some of that was going to be better utilized to the degree that it's only value is really long haul pipelines. Now, I'll tell you, Texas Gas, for instance, still is going to have an important role in serving distribution markets into its area, but it doesn't need the long haul capacity. So in other words, it will still probably be contracted on the segments that go into their end user markets. Transco, on the other hand, is a very, very different pipeline than -- you hear the triple T pipeline sometimes, which is Tennessee, Texas Eastern and Transco, the difference is that Transco sits in the middle of those populated areas and distributes right into those major LDCs and right in to those power generation markets on that side. And so if you're sitting as Tennessee or Texas Eastern where you come up the order side, the western side of the Appalachian basin and then you have to cross over into those markets, you don't have the benefit of all that direct connection and distribution growth. And so, really, Transco winds up just being a big network system and really providing the high-pressure to all those markets along the Eastern seaboard. And it's just so expensive today to build in those populated areas, there is just no way that you can -- you couldn't duplicate that system today, I'm not sure you could do it for any amount of money literally from a permitting standpoint today, to build through all those populated areas. But it serves such a critical role because of that. So I don't see Transco kind of in the north-south business. I see it in the distribution and network business. And the more network plugs we get in from the north, that just means they can serve that next to many more volumes because it can serve gas in both directions. And so, I would just tell you, I'm -- we're really, really blessed to have Transco position where it is today and as you saw, it's really not a -- there's not much of an end to that. The only bad news about it, I would tell you, is the regulated pipeline and you only make so good of a return on it because if you could charge market base rates on it, there would be a lot more value to be head out of it. But it's a regulated asset, and we're going to get a regulated return on it. And so that's what it is. We do have the ability to continue to invest at we think nice return in and around the asset. But they're not going to be the kind of barnburner returns that we enjoy in some of the other areas.
Donald R. Chappel
Do we have any other questions? All right, very good. I guess it's time to wrap up.
Alan S. Armstrong
Let me just wrap really quick for you here. Thank you, all, very much for coming to see us today. And we are very excited about our future. This is -- and present at a time, and we are -- we're not going to back down on the commitment to our strategy, to continue to grow in these areas and we think we're very well-positioned to capture a lot of value now and very much into the futures. Thanks for joining us today.
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