Targa Resources Partners LP (NYSE:NGLS)
Investor Day Conference Transcript
October 18, 2012 9:30 AM ET
Matt Meloy - SVP, Chief Financial Officer and Treasurer
Joe Bob Perkins - Chief Executive Officer
Mike Heim - President and COO
Danny Middlebrooks - VP, Gas Supply and Business Development, SAOU
Clark White - VP, Permian and North Texas
Hunter Battle - VP, Logistics and Marketing Assets
Scott Pryor - VP, Liquids Marketing and Trade
Rene Joyce - Executive Chairman
Vincent DiCosimo - Vice President, Products & Crude, Storage & Terminaling
Okay. Good morning. Let’s get started. Welcome and thanks for joining us everybody to Targa’s Investor Day here in Houston, Texas. We have a lot of interesting and exciting news the Targa to go over today. We are going to be going over lot of our growth projects and some of the financial guidance and we've got a kind of full team here at Targa to review new updated investor presentation that you’ll find available on our website.
So first I just like to just welcome everybody and say, thank you for joining us. With us here today we have Joe Bob Perkins, Chief Executive Officer, he will be giving a company overview. We have Mike Heim. He is the President and Chief Operating Officer. He will be going over short business description and then setting up the further discussion for the Gathering and Processing business. Danny Middlebrooks and Clark White will be reviewing. And then Hunter Battle and Scott Pryor will be going over the Logistics and Marketing.
So turning to page four, just quickly I want to go over the 2013 annual guidance that we released yesterday in the press release at the end of market close. A couple of things I want to hit on, the 2013 EBITDA, we provided a range of approximately $540 million to $570 million of EBITDA. That results in approximately 7% growth over where we see 2012 shaken out.
The 2013 is an interesting year. The run rate of the business is really is kind of come in different in the first half versus second half of the year, as well as the growth projects we have really come on line mid to late in 2013.
We have as you’ll see in several pages later, in outline of our projects, they’ll be coming on in 2013. We have $800 million or over $800 million of projects that are going to be coming on mid or late 2013. So we are going to be existing the year with a much higher EBITDA and we are going to have in the front part of the year.
And so as a result of that the distribution coverage, although we pointed to you in the press release is going to be closer to the 10% range in the first part of year as we are spending a capital for these projects, but don't yet realize the benefit of EBITDA until the later half of the year and then from there the distribution coverage we’d expect to continued to increase.
And with this projects ramping up throughout 2013, it sets us up for even further growth in 2014 and that’s why we felt its important to point everybody’s attention to really the 2014, when those projects that come on in ‘13 have a full year run rate benefit in 2014, there’ll be the CBF Train 4 in North Texas Longhorn plant and then the export terminal.
We also pointed the 10% to 12% distribution growth in 2013 as compared to 2012, relatively in line, although a bit tighter range than our guidance this year of 10% to 15% and that’s lead to TRGP dividend growth of 25% to 30% plus.
And I won’t go over all the operating stats but as you can see we do expect meaningfully higher volumes throughout most of our systems. And the commodity price assumption we used to drive this guidance, in our view relatively conservative commodity price view. It’s approximately where commodity prices are today with $0.87 the weighted average NGL barrel, $350 gas and $90 crude and that includes the $0.35 per gallon ethane, which is approximately where we see ethane now, its in the low to mid $0.30. And then the ethane price sensitivity, we gave you a 10% -- $0.10 per gallon change in ethane, its about a 3% move in our EBITDA.
Okay. Moving quickly to Targa Resources, we have two ways to invest in Targa. The first is the mastered limited partnership, ticker NGLS. It’s about $3.8 billion market cap, traded about 6.2% yield and excuse me, based on the annualized distribution rate of $2.65 and investors in this area will be receiving a K-1, so these are limited partners in the MLP.
Then the other way to invest in Targa Resources is in our C-Corp, the parent company that owns the GP in the IDRs. Through the IDR ownership it has a higher growth rates in the dividend then the partnership, it trade about a 3.4% yield and its about a $2 billion market cap.
Moving to the Targa Corporate Structure, I’ll start at the bottom of this page and see all the assets, are broken out here into our reporting divisions and segments. But all the assets are owned by the partnership, the parent company Targa Resources Corp. owns the general partner and the IDRs.
And just important to note, we have more detail on some financing activity we just closed in the first week of October. We refinanced both the partnership revolving credit facility. We increase it from a $1.1 billion facility up to $1.2 billion credit facility extended into five-year maturity and lower the pricing, on page 50 you’ll see more detail of the updated credit facility at the partnership.
We also redid the credit facility at Targa Resources Corp. We now have $150 million revolving credit facility up there. We repaid the $89 million term loan and we now have $75 million outstanding at Targa Resources Corp. and again you will see more details on that financing on page 50 in the back of this book.
The other point to note here is the Warburg Pincus ownership. You see here they own about 14%, that number has been coming down over the last, really over the course of this year, as they’ve distributed their ownership position to their LP unitholders and as they do that it increases liquidity at TRGP.
And so, with that, I'm going to turn it over to Joe Bob Perkins, our CEO and he is going to take it through executive summer of the presentation.
Joe Bob Perkins
Good morning, everybody. My team believes I’m probably in trouble here, trying to stand behind the podium and talk to you all could raise me up, I like to walk around a lot more and I do that.
I won’t be able to see the screen, right.
Joe Bob Perkins
And Sean can’t see the screen anyway all the way back there. This is our one page Targa story and only about the first three rows can even read it. So, I’m going to have to reach into a book so I can see it too, and I hope that everyone got a copy, they are some at the back, so see the print on desk.
I want to see how the one page story works. Really Shale and Resource Development underlies our growth story and we break that into pieces. We start with a footprint in multiple Shale and Resource plays, a leading position in Mont Belvieu that drive Targa’s growth. We’ll talk more about each of those on this page and then time as we go through the day, but that’s the story and it’s a pretty good story.
You start with the footprint, we’ve got a leadership position in the Permian Basin and you really can’t read that map in the top left hand corner, but I’ll tell you what it says. The takeaways are that Permian Basin leadership position, a leadership position in North Texas in the oily part of the Barnett Shale, assets that are very well-positioned in Louisiana for potential Gulf Mexico resurgence and from resource plays that are developing onshore Louisiana.
So a great Gathering and Processing footprint and a leading position in Mont Belvieu, you know that Mont Belvieu is NGL hub. The liquids coming from U.S. shale and resource plays largely come into Mont Belvieu.
And in Mont Belvieu, we have to build capacity to help those liquids to taking care, that capacity starts with the second largest fractionation position in Mont Belvieu and Lake Charles. We are behind that other guy across the street, we are closed to both Targa and Enterprise right now. We are proud of our relative position, as well as our aggregate position. And we will have one of only two commercial import export facilities in the downstream part of our business.
So footprint in multiple, basins, a leading presence in Mont Belvieu and Galena Park drives our growth. We’ve got $1.6 billion worth of capital projects that are going to be completed in 2012 through 2014. We are adding processing. We are adding fractionation. We are adding to our export project.
A terrific growth story, just on the approved projects that Joe have on the radarscope. And all of that leads to the investment highlights that I’m going to talk about on the right hand side. Two new organic projects that will give you more detail about, a total about $450 million of additional capital expenditures.
Increasing scale and diversity, a increasing fee business, we have said, Matt just said, 10% to 12% distribution growth for 2013 at NGLS that translates to 25% to 30% or more this dividend growth at TRGP.
We said our adjusted 2013 EBITDA is growing up because -- growing because of all those projects and we should put on here that if you look to 2014, 2014 will grow 25% plus EBITDA on top of 2013 that would have been the final highlights. Nice highlights, we’ll talk through all of that story in the next few pages.
This is the mandatory shale map for every equity presentation. I think ours is better than have all those purple colors that DIA map has, little more tasteful. And of course, we are circling where we are. You know that advances in E&P technology, drilling and completion technology are game changing for the United States.
I won’t tell you that story again, but we’ll tell you that if you look at our Gathering and Processing facilities, we’re nicely positions. 21 plants, 12,500 miles of pipe, first in the Permian Basin, second in North Texas and third in the Gulf of Mexico.
Permian Basin has Spraberry, Wolfcamp, Avalon, Bone Springs all of those stack multi-horizon pace underlying our Gathering and Processing systems. North Texas is the wet part of the Barnett Shale and the Gulf of Mexico.
The story is, if you look at our Field Gathering and Processing, we filled our existing capacity and/or adding more, both little pieces and big pieces. If you look at all of our stuff disposition for additional development.
And those shale resource plays are driving an increase in liquids. When you know today, at today’s price environments, E&P companies are drilling all wells. They are drilling reach natural gas wells.
Now forecast the chart here shows how natural gas production top of those colored bands and particularly from the back you have to believe me that’s 2005 to 2017 have increase to meet demand and the forecast shows them flattening out, natural gas U.S. production flattening out over the next several years, natural gas liquids are not flattening out.
Look at the red bar, the red bar is charting gallons per million, pay the richness of the natural gas, continues to increases as you have more and more oil wells, more and more rich gas wells, that increasing GPM and you have lots of liquids even as natural gas is flattening out liquids continued to increase and the liquids have to be processed and they have to be fractionated.
Targa’s Gathering and Processing in the field is essentially full, three of our four systems are full, essentially full. Our fractionation is essentially full. So we have been building more and that’s what we are talking about.
Let’s look at the Permian Basin specifically as one of those areas, Wolfcamp, Spraberry, Avalon, Bone Springs, multiple stack, producers have shifted to drill for oil. Oil production in the Permian Basin has increased 32% in only the last five years and look at the slop in the last couple of years, the slop of that curve.
Oil production increasing rapidly, I was born in Midland, Texas, the boom in the Permian Basin is unlike anytime in my lifetime. Look at the Permian rig count. Its increase to 178 rigs just since 2010, that’s more than 50% increase. It share of U.S. rig count is now 27%. It is a boom. That oil focus drilling is creating more liquids.
And the same thing that’s going on in the Permian Basin where you can see Targa has a present from the east side of the Permian Basin to the west side of the Permian Basin, West Texas and Southeast New Mexico. Our systems, we are not the largest but we are the leading provider of Gathering and Processing services in my opinion in the Permian Basin. And I think producers would tell you the same thing. We don’t have rolling ground out of their E&P activity.
But it’s not just the Permian Basin that same kind of increased activity, increase liquid is happening in North Texas where we are very well-positioned, the Eagle Ford, the Granite Wash into the Mid-Continent and even Marcellus liquids are coming to Mont Belvieu.
All of those liquids have to be taken care of, Mont Belvieu’s capturing most of it. Currently NGL pipelines are constrained going into Mont Belvieu. The chart at the bottom right hand corner shows pipeline capacity in blue increasing particularly in '13 and '14. The red line represents fractionation increases for the industry at Mont Belvieu with increases coming on in '12, '13 and '14 announced projects.
Those increase in supply of natural gas liquids come to Mont Belvieu, drive much of our growth and Galena Park has been help with the exports. This is Targa’s one page petchem story and that’s probably even harder to read than the one page Targa story. And Targa doesn’t want to be the petchem expert, but we should do business with a lot of them.
If you look at this chart it shows the map that reds says that 80% to North American petchem is located along the U.S. Gulf Coast, that’s why the natural gas liquids complex is headed in that direction. Much of the U.S. NGL supply is connected to the U.S. petchem right at U.S. Gulf Coast, a whole lot of it right at Mont Belvieu.
If you look at it Targa’s infrastructure is very well position to serve that interconnection. We have fractionation capacity at Mont Belvieu and Lake Charles, and we connect Mont Belvieu to Lake Charles. We’ve got seldom storage and network of feedstock connections to the petchems that is really second to none and one of only marine import/export facility.
The current pricing outlook says that petchems in recent past and today are doing everything they can the bottleneck can convert and the longer-term outlook is going to put in place longer-term new build petrochemical facilities.
Now we’ve borrowed the chart in the bottom left from Envantage. What Envantage shows is the dark blue based ethane cracking capability but if you went back a few years before the first quarter of 2011, it might have been in the 850,000 barrels a day range, then up to a million and slightly increasing from 2011 to 2018 on this chart.
What they then show in light blue is the conversions and debottlenecking that have been going on. Obviously, it was going on before 2011 but it is shown in the dark blue at that point. That’s driven by economics and also driven by economics, they are showing the probable by probability medium, fair probability, low probability, probable plans that they have on their radar scope, increasing ethane cracking capability in the United States.
If you don’t look at just their probabilistic views, we know that four new world class crackers have been announced. We know that quite a few others are being studied and we know that the global economic advantage of ethane to ethylene for this country relative to the rest of the world is what’s driving it.
Just as ethane to ethylene is globally advantaged, so does propane and butane demand for exports increase overtime. This chart shows first the red line on the top, propane pricing differentials to the Saudi Arabian contract price been increasing since 2005, favorably priced on a world global scale.
That resulted in the export bar shown in dark blue increasing since 2005 to current level. Butane has a very similar story. The U.S. Gulf Coast propane exports have increased tenfolds since 2008. Gulf Coast import-export capability between ourselves and the other guy, we estimate to be a conservative 12 million barrels a month by about 2015. By the way, the 12 million barrels a month is just a little bit of propane in the world market, not very much at all.
The Panama Canal continues to drive this and has people to petchems and people who are exporting propane look at it. That's part of their long-term view because it will lower the shipping time and transportation cost to be comparative with the Middle East to the Far East.
Targa’s announced project goes from million barrels a day today to four VLGCs Q3 2013 or about an additional 2 million barrels per month at 10 million barrels per day, a million barrels per month now, 2 million barrels per month 3Q 2013 and another 1 million to 2 million barrels a month in Q3 2014.
The incentives to exports are pretty large and we expect them to continue to grow. All of that that I have talked about so far results in this capital investment chart. This set of Board approved announced official project is now $1.6 billion.
We’ve organized at this time, gathering a processing projects on the top, downstream projects on the bottom. The two highlighted items light blue are the two new projects. We’ll get some more detail about in a minute. If you look at it, about a third of that $1.6 billion is on the gathering of processing side. About two-thirds is on the downstream side and most of its fee based, the downstream check marks you see on the bottom right hand corner.
A few words and you’ll get more later, in fact our teams at Joe Bob are already telling about this. I said you can tell him again and you’ll get it right. First 200 million a day plant at SAOU spend about $225 million to put that in place. Board approved it in September. We expect it to be completed mid 2014.
I should admit that we ordered the plant in May and the Board approved first the steel and then the installation. Expected GPM five to seven GPM are greater. That new plant you can see is located to the North West of the primary SAOU system but the way will be plumbed in is to create capacity across the entire system because of a nice back bone that Danny will tell you about.
It’s an advantaged position relative to multiple plays with client, still the CanyonSans, the Wolfberry are incredibly active here. And it’s advantaged relative to the NGL and residue takeaway. You can’t really read the map on that, top right here but you get to see again in a little bit.
Bottom left international export project, before we finish the project that I was talking about having four VLGCs in the third quarter of 2013, we've already got an approved expansion of it. Combined this, we spent $480 million, we’re adding additional pipeline and dock to make sure that we can keep up with the million barrels a month that we’re already doing on small and midsize ships. We’ll add additional propane supply. We’ll add additional refrigeration and by Q3 2014, we’ll be able to add another one to 2 million barrels a month, another two to four VLGCs.
The chart on the right shows total capacity being put in place in the U.S. Gulf Coast that builds to about the 12 million barrels a month that I was talking about or the corresponding thousand barrels a day over on the left hand axis.
All of that together you know that our fee-based margin is increasing rapidly. If you look just back to 2010, it’s grown from 19% to 39% of our overall margin. More importantly, at least more importantly to me, look at the dollar increase, $23 million growing to $66 million as of the Q2, 2012 and all of those projects, we just told you about, getting the full run rate by 2014 takes the dollar millions up, we had to break the bar. That is what creates the diversity and growth regardless of commodity price for Targa Resources.
In CBF Train 4, international export project and the petroleum logistic expansions are coming owned in ’13, fully-owned in ‘14. You know that’s complemented by our hedging program. We’ve talked about it many times.
We hedge equity volumes from our field GMP and that program now has about 60% to 75% of those commodities hedged for 2013 and 45% to 55% hedged for 2013. I’ve told altogether scale, diversity increasing fee base. The hedging program create a lot of stability and mitigation to commodity price changes.
I really love this chart. If you look at the top right hand corner, it shows our EBITDA since 2007. They’re actually growing and then more rapidly growing because of the capital investment programs that we put in place, that we started even during the dark times of 2008 and 2009.
The red graph, the red line is crude oil price. Going way up, coming way down, going up and down after that, not impacting the EBITDA. Really take the same EBITDA platform that you can see. The locked-in growth in ‘10, ’11 and ‘12, ‘13 and ‘14 against first rapidly rising then continually falling natural gas prices, not impacting the EBITDA.
Then, if we focus on natural gas liquids pricing, same story, up and down and up and down and down, not impacting our EBITDA. That diversity, that stability is really pretty impressive and I think the past is furlong. If we’ve got and we will have prices going up and down, our stability and diversity have a lot to say with what will that future EBITDA look like. And that fee-based operating margin coming on via Gathering and Processing E&P in 2007 with only the North Texas assets.
So you’ve got to drill bit in that, right. My finance team knows I love this chart and I’m not the finance guy. So let’s get over something. How that happens? Okay. So we’ll go back to page 18. Was I talking about stability with page 18, (inaudible)? Good. Okay. Just double click. Okay. It’s hard to look over my shoulder and look down at the book at the same time. I really don’t like this room.
And I really would be screening up if I get this chart, because all of that diversity, stability, fee-based increases that help drives strong distribution growth since 2010. I love this chart too. It started up into the right as it get down. The up into the right had a 11% compound annual growth rate since that time for the TRP distributions. We’ve already told you that, if we look forward to 2013 that’s going to continue to grow 10% to 12%. I guess you can make implications about the 25% plus EBITDA growth rates for 2014, but that arrow is going to continue pretty nicely that’s the TRP piece of their own.
If we drew the same picture for TRC, the 11% compound annual growth rate would be a 33% compound annual growth rate. And we say that 2013 will grow 25% to 30% for dividends at TRGP, and you have the same kind of implications for nice EBITDA growth rate in 2014 for the dividend growth of TRGP. That’s all being done with really good distribution coverage.
Second quarter was 1.34 LTM. Our long-term target ratio is 1.2 times LTM and we are proud of that. And just as we are proud of equity coverage, I’m really proud of our management of the leverage ratio. Financing those, this is one of my favorite charts but I already said that. Finance guys will have to do this chart. The operational and commercial guys are really glad that this is the way we manage the company. I like telling debt analysts, equity analysts but more so employes about this chart.
If you look back to 2007, you can see that it’s 2007 back there. But what you can see is the ranges in dash lines of three to four times leverage, and we exist always towards the bottom end of that range. Snapshot today is as strong as ever, but managing it in a conservative solid consistent basis, allow this to invest in businesses and grow. It truly is a foundation for growth, and it also gets you through times like ’08, ’09 and you know what ’08, ’09 look like.
Look at our leverage ratio I don't have liquidity there, but our leverage ratio and liquidity in ’08 and ’09 were great. We were adding people and working on the capital investment projects. We’ve got great liquidity now and the rating agencies are recognizing the story. You can imagine that we show this chart to them every time we visit to them. That really is my part of the presentation. These are the investment highlights. This is what I’m supposed to that I have already told you. That’s a pretty good set of highlights, and we will talk about some more at the end of the program.
All right. I’m just going to be up here for a few minutes, because what I really wanted to do is leave a lot of time for the four guys sitting over there with Joe Bob to explain our business in detail and all of our growth. What I’d like to do right now is really give you a couple of highlights, and talk about some of the business functions that we aren’t going to highlight today. It’s not that there is anything slow in those groups, but we have limited amount of time here.
So, I’m just going to give you a few highlights on this. First starting with the Gathering and Processing. Joe Bob has gone over part of this, but if you look on this chart you see the two red stars on here. These are the two new plants that we talked about. It's amazing. When we bought Conoco assets in 2004, we had a hard time finding the drilling rig working in the Permian Basin.
Today, you have a hard time getting on the highways and the county roads because there is so many trucks, whether they're hauling and gravel to build locations or if they are hauling their frac sand or Water Act frac jobs, it’s amazing place today. It’s not a unique place. I mean, the Eagle Ford is just like that and if you go up to the Bakken, it’s just a -- it’s a frenzy in the E&P world right now. And it is really, really good for the midstream business.
Jumping over to Louisiana with our LOU and coastal straddle plants. One of the things that Joe Bob talked about was potential growth in the offshore. We are seeing permits coming back. The Obama administration after the BP problems really retarded the approval on the permits. It’s finally starting to happen again. We see the, Gulf is a great place for future gas. We think we are very well-positioned. There is some plants that are shutting down. There is some consolidation going on. When the drill bit gets really going, active in that Gulf, again, we think we are very, very well positioned to get our share of the gas. It’s going to come onshore going through these plants.
In our press release, you all probably saw that we were going to permanently shutdown the Yscloskey plant. It was damaged during Isaac, not a bad thing. It’s a lean oil plant. It doesn't recovers much of the ethane as much as the propane. Most of that gas is not only all of that gas will end up in our Venice plant.
We have connections with Tennessee Gas and that's what the Yscloskey plant straddled, and we are working with the producers and with the Tennessee people to get all that gas move over to Venice. So we will be able to process the gas. We will be able to segregate that gas over there that is the richer part of the Tennessee strength and we will be able to recover much more of the ethane than the propane.
One thing that you might see is there is another red star on this map. That a plant that we just bought from Copano in the Lake Charles area who was originally built for LNG, that was coming into that trunk line receiving terminal there. They replaced it and it’s being processing gas off the trunk line systems for the last couple of years in conjunction between Copano and with Targa with our fractionation facilities.
We bought that facility from Copano. We really think that there are three possibilities for all of these plants. Not only Gulf of Mexico, but the onshore production, the Wilcox, the Tuscaloosa Marine Shale in the Louisiana and several interstate pipelines who have lines, multiple lines that go into the Marcellus and Utica are talking about reversing part of those lines and brining them the gas back to the Gulf Coast.
It’s going to find whole I mean all of these plants. There is processing available. There is fractionation available. There is distribution of products available. So, we really say that that is a very good area and it’s going to be part of Targa’s future going forward.
The biggest growth that we’ve got right now, basically where we are spending the most money is in the Mont Belvieu, Lake Charles area, we are very busy there. We are very proud of what we are building. I think that we go out retail area audience that we can find, that you have to have a viable Mont Belvieu in order to keep production going on in the Rocky’s, in the Mid-Continent, in the Permian Basin, in Barnett Shale.
It’s kind to hard sometimes for some of the people to understand that you may not be able to turn a well on in the Permian Basin, because they can’t move their liquids. That’s why we keep building and I think that is a very, very important to our growth and to the growth of the whole, midstream and E&P industry in the United States.
One other things it’s going on is a fight between the Taxes Government often and EPA in Washington. And it is slowdown greenhouse gas permit. We are -- we have two permits in front of them one for Longhorn plant, North Texas and for the Train 5 fractionator at Mont Belvieu. Hunter’s going to go into great detail on Train 4, where we are, what is going to do, but Train 5 is on our horizon.
We filed for the air permits at the end of last winter. We expect a permit to be issued by the EPA end of this year early next year. We are well on our way to building a Train 5. We have customers. We’re going to be one of the biggest customers with Longhorn plant and new plant in the Permian Basin.
We’ve got the land. We’ve got the engineering done. We’ve got a contractor. The only thing we need right now is a permit rider with EPA to finish the permit and issue it. And when we do that then we go to our Board and our Board will very, very happily approved Train 5. So, it’s on the horizon. It will get done. You have been hearing us talking about Train 5 and a possible Train 6 for a year now. So, it is coming our way.
I want you show you a couple pictures. One other things that Joe Bob showed you was on Gathering and Processing growth for '12 was the processing plants been small plants that we’re putting in at both Sand Hills and at disturbing plant in SAOU.
This is the Garden City plant that we’ve owned for quite sometime. We’ve bought it from Conoco. This Midland at we took it in, took it into shop, we refurbished the whole thing and it is a -- in the process right now being installed our Sterling plant. So that add 30 million a day of capacity.
This is the De-ethanizer for Train 4, it looks like a big vessel, when it stood up, it’s about 150 feet near, its about 30 feet diameter. There is lot of steel there and that’s the backbone of the Train 4 facility along with the about four other columns and bunch of compression.
These are couple guys working on the refrigeration system that allows us to load HD5 and semi-ref condition on to mid-size ships at Galena Park that was finished earlier this year. And these are new storage tanks that are under construction. Several of these have been painted already and are being pressured tested right now at Tacoma at our Sound facility.
We are in the process of building a new pipeline to Olympic Pipeline back to this facility we will use this storage tanks and we will basically move refined products and crude oil through our facility, they can be loaded on to ships, barges, railcars and trucks, and it will -- the customers are the refiners on the West Coast.
I want to jump back for a second, because I want to go back to the overall map. You see Sound up in the Pacific Northwest we’ve got a square out here in Stockton, California. We have agreement with the Port of Stockton right now to lease there some of the facility out there docks, there is the unit Train facility already built out there and we are moving along doing due diligence and one of the requirement is that we do a very, very detailed survey of the dock its an existent, say that California want to make sure that is very sound before, he gets put back in service.
We’re moving that long. Our intention is drill the unit Train, handling facility there to distribute Bakken and crude all up and down Pacific Coast. We also are working on a unit Train receiving terminal in Tacoma.
We already have one contract signed with the major where we will bring -- they will ship in and deliver unit Trains for offloading there, again to go in the multi-delivery modes to brief redistributed to Pacific Northwest in California refineries.
So, we’ve got a lot going on there. The other thing is, Scott’s going to talk a little bit about the commercial part of the NGL business. We’ve got lot of things going on there.
This past year with the [hub] that opened up between the Mid-Continent because of lack of capacity and the rest of the United States. It’s created a tremendous number of deals that we could do by moving very, very cheap Mid-Continent and NGL to the rest to the country both primarily propane and butane.
We serve about 15 refineries throughout the U.S. We make there propane disappear. We supplying with butane when they need them. So, we’ve got a lot of things going on and these guys are going to give you some more information on that.
Last but not least, we talked about it lot, we are very serious about it, but we want make sure that we have a safe work environment in a very environmentally, healthy situation to work in.
We do that by hiring the best people we can, training them and after they've all got the experience, we expect every Targa employee to have the responsibility to do what’s right and to do what’s safe. We say it at every safety and awards banquet that we have.
Look around, make sure that, when you go home at night the guy stand on either side, when they gets to go home that night too. We don’t want anybody hurt. We want make sure that everybody comes back to next day and we really, really work on this. I’m not going to read you all of the statistics here.
GPA, Gas Process Association is probably the best trade association for keeping up with safety there is. Basically we fall into a group of companies that have 2.5 million man hours or more per year, there is 41 of us, and this table shows you what the average safety statistics are, that’s number of actions near misses all of that, we’re on the low end of those.
So lower the number the better and we always strive to have it zero, but as you all know, when you got as many moving parts and as many people as you have you can never achieve zero, but that’s our goal.
One final thing I’d like to tell you is, it's an amazing statistic to me, we've gone 5 million miles on our propane and butane tankers without a reportable action. So we are very proud of that and those guys did a really good job. Danny?
Thank you, Mike. We decided to change it up a little bit. We are going to speak from here this morning, because we can see the screen a little bit better and we can talk to you instead of read to you.
My name is Danny Middlebrooks. I’m the Vice President of Gas Supply and Business Development for the Eastern Shale of the Permian Basin and operate the San Angelo Operating Unit which you see there.
I’m going to talk to you little bit about the drivers of the overall Permian Basin and then I’ll drill down a little bit more into SAOU specifically, then I’ll turn it over to Clark White. This is the area that I operate here. Clark White takes care of the Central Basin platform, the Delaware Basin and I’ll turn it over to him when I get there drilling down to the SAOU.
The first thing I’d like here to do is to look over the right side of the screen. This is the stratigraphic cross section of a typical well in the Permian Basin, which used to have out here was one of these wells drilled and one of these different 19 formations or the black dots are would be produced. It come out maybe 20 barrels of oil day, 50 Mcf and it would decline from there.
Starting about five years ago some of the newer operators, better operators came in here and they started drilling these wells, they went to the railroad commission and they got it approved commingle all 19 of these zones, now each well may not have 19, it maybe 17, it maybe 15, produce more and prevent waste like a commingle zones.
So that’s what they started doing and the IPs jumped up around 150 Mcf a day and maybe 8 or 100 barrels of oil day. It was the first real step change in the Permian Basin as far as how they are doing this with production. So, again, that’s the first step change.
Now if you look at the overall drivers as what’s going on in the Permian Basin. You’ve got the new drilling technologies. You had the first step, which was a new vertical wells commingle, now you’ve got the producer going in there, always pushing the learning curve like they do and they try in horizontal wells in some of those formations.
In my area they have determined that there are three separate horizons in the Wolf Camp, an upper, middle and the lower. They’ve taken wells horizontal in each one of those and they’ve been successful in doing. That then let to them finding the Cline which is a new emerging play that they are doing and they’ve got the Cline being productive.
So the Permian Basin now has gone from one vertical well in zone to drilling five wells to tap all the horizons that are needed out there. They needed vertical. They need three different horizontal Wolf Camp wells. They need a horizontal Cline well. So you’ve got five wells on the same acreage that you had, that’s step change number two, that’s driving the entire Permian Basin.
Targa’s assets as you saw cover from east to west the entire Basin. We have the opportunity to take advantage of all subsections of including up in Clarks area, , the Avalon, the Bone Spring, as well as the Wolfberry that he’s got drilling on him.
If you look over to the right what we are saying about horizontal wells, you can see that they are keeping up pace in just year and half. There are around 140 rigs now. I can tell you that in 2010 we probably collected -- connected two horizontal wells at SAOU, in 2011 probably around a dozen, 2012 we are somewhere in the neighborhood of probably 30 horizontal wells and I know 50 plus already they are being planned for 2013.
So as they are driving the success is to getting better and better at their 7000 foot laterals, there are 30 stage frac jobs. This again is step change three that is taking place out there. The producers are learning and they are getting better and better added, and we are benefiting from it.
This is an oil play, if you look down at the lower right hand side, you’ll see that about 70% is coming from oil that’s what’s driving the play, 20% of it is NGL’s and about 10% of it is gas.
So it’s a pure oil play. I’m going to tell you when we flip over to SAOU. I don’t look at it is a gas system, it’s an NGL system with associated gas, the gas is so rich there that its just losses around the pipe.
And then again capitalizing on the NGLs. If you look at just dry and see if a gas, and say that is a $3, out of San Angelo we are about 1250 Btus per Mcf and about 6.5 gallons, that takes our value of an Mcf to about little over $8, compared to $3 for dry Mcf, it worth two and half time more, that’s a real driver for the producer and it’s a driver for us.
I want to drill down now little bit more in the San Angelo. Three things jump out on this page, usually when you put a giant red star on the page, it jumps lot at you, so that’s, it had its effect.
It is on the western side of the system. We do have plant site for it. There is a 16-inch backbone, that long line that you see, its going to feed it, so the infrastructure is in place for it.
As Joe Bob said, its going to be about $225 million investment that’s plan alone that’s includes pipelines and compression, and for things that we want to do to set this system up to run like we run it now. I’ll come back to the plant in a minute and I want to explain to you a little bit about how we operate San Angelo.
You’ll see that we’ve got plants to South Mertzon, we’ve got Sterling and Conger to the north, each one of those plant has a different NGL line and there is a good reason for that. We’ve also got multiple residue outlets at each plant. We can push gas to the south to take advantage of lower NGL or higher residue prices and do price optimization.
We can also push gas to the north and take advantage of those same issues up to the north, and we do that and optimize on a daily basis whether its for fracs or another main reason and main driver we have this is our third-party trade partners.
We never know when there might be an issue with them or it might need to take a compressor down, or they may have a pipeline problem that could cause us to shut in the system and producer shutting these oil well, nobody wants that to happen, so we’ve got, as long we have multiple outlets at each plant.
Now when we install the new plant at west we’ll have another NGL line out there. We’ll have additional and multiple residue lines out there. So instead of just pushing gas in north and south to optimize, we’ll be able to push gas north, south, east and west, to take advantage or to overcome all of those situations that happen on a daily basis.
When the producers see that we have the ability to do this and we’ve had to it numerous times when we had hurricanes came in that system is not been shutdown one time since I’ve been here in 2004. We keep it up. We keep it moving. The producers know that. They don’t have to shut in their oil wells, that helps them deliver the guidance that have given to you on what they can do. That makes us a real preferred service provider out here.
The last part about SAOU if you at it, you’ve got this Cline Shale play, this starting kind of in the center of the system and extending to the north and east. They’re really just now understanding learning the Cline. I’ll tell you that there has been around 50 to 55 Cline well drilled, Targa is connected over 30 of them. So we have an idea of what the wells do. They look good. There is a lot more on the drawing board and we are situated right on top of this to take advantage of it.
The other thing is the Wolfberry. It’s starts in the center of our system and it goes out to the west. It’s been a key driver for us for the last couple of years and we are just seeing it continue to accelerate, continue to move forward and the asset is sitting and it couldn’t be in a better place to take advantage of these two plays that’s going on. We’ve got a really, really bright future here to convinced management to put in a 200 million a day plant big step for us, now we need to fill it up.
I’m not going to sit here and read to you the highlight, SAOU, you can read them. It’s got up over 1600 miles of pipes, over 50,000 horsepower fuel compression, so on so forth – both wells that we connected since 2005, you are going to notice and I am forecasting in 2012, but our well connects are going to drawback slightly.
We had an all time record last year. The well connects are going to drawback slightly. I wanted to point that out 2013, I think they are going to be very consistent with 2012, but that’s not the story here.
The producers cannot drill horizontal wells as fastest they can drill vertical wells. So, if you go over and look at the -- at the lower of the left hand side of the slide, our 2012 inland volumes are going to be higher than 2011s.
2013s are going to be meaningfully higher than 2012s. We are connected less wells. How you are going to do it. You’re going to do it, because you've got the vertical wells that have multiple horizons, they push the IPs up on the vertical wells now to around 200 Mcf and around 120 barrels of oil. So they can drill less wells, increase their volume.
Then we are starting to hook in and we are seeing more and more horizontal wells, they don’t need to drill this many wells. We don’t need to connect this many wells to make the system grow. We’re already seeing that in 2012, well connects are down very, very slightly and our volumes are growing. So that’s what I expect to happen for next year.
30 million a day Sterling expansion will come on just in time probably the end of December of 2012 or the early January of 2013. We will need that capacity then. It will be right at the Sterling, which is at epicenter, if you will for us as for the Cline is to the east and Wolfberry to the west.
When we bring on the new plant out west what we will end up doing is since we have other plants that are situate in Wolfberry and Cline, we will immediately pull gas away from all of our existing facilities to help feed that new plant and we will create capacity at all of our facility, so then we can bring it in from the north, east, south and west. It really sets up well for us.
And if you look over the right, I can already mentioned that, you saw where our capacity was around a 20 million a day previously, we brought on the Conger plant in May of 2011 that was a 25 million a day plant. It’s rapidly approaching being full. In December, you see us come on with another 30 million a day Train and then you see the capacity that will create when the new plant comes on.
This is kind of the same slide again. Again, we setup very, very well. You’ve got been (inaudible) to the west. I’d like to thank you for your time this morning and I’ll turn this over to Clark and he’ll tell you about his area. Thank you.
Thank you, Danny. Good morning. My name is Clark White and I am the Vice President of Operations in Southeast New Mexico, the Western Permian and also the Barnett Shale in North Texas. If you look at this graph, you'll see the blue oval to the left that’s the Sand Hills system. The Sand Hills system cover some eight counties and West Texas with some 1400 miles of pipeline in 25 compressor stations.
The Sand Hills system as Danny described are really it reaches to the west into the Bone Springs and if you look at the formations on the stratigraphic, you can see the Bone Springs and Wolf Camp those are the primary formations people are going after in the Delaware Basin.
The Bone Springs, there is actually three different Bone Springs. They call out the first, second and third Bone. But as you can see the Sand Hills system reaches over into the Delaware Basin, it also reaches over back to the east into the Wolfberry Basin, where Danny describe already all the horizontal multi-stack plays that the producers are going in -- going after. We are seeing the exact same thing in the western side of the Permian Basin.
In the middle is our conventional system what we call the Central Basin Platform and as formations like to turb and Washita Albany and the big change is going on there is the horizontal drilling.
In the past, people drilled vertical wells, today these are shallow 5,000 foot wells that their horizontal and get lot better results. So, there is a lot of producer activity in our core area of our system.
The Sand Hills plant is a 150 million a day, high ethane recovery plant, it’s centrally located in our system. The GPM and our system in Sand Hills ranges anywhere from 4.5 to 8 gallon gas.
The graph in the upper right reflects the Sand Hills well permits for the counties that Targa serves. The permits continue to increase in the Wolfberry as shown in the dark blue and in the Bone Spring as shown in the light blue. These are both areas where Targa has competitive as you saw from the previous graph, competitive volume capture in those areas where our gathering system is.
Moving to the outlook, if you look at the outlook down below for Sand Hills from the graph in the lower right, the 2012 volumes are expected to exceed 2011. The 2013 volumes are expected to be meaningfully higher.
The increasing volumes are driving Targa to expand its plant with the 30 million processing capacity expansion. The Sand Hills capacity after expansion will approach a 180 million as shown in a red dotted line in 2013. This expansion is expected to be completed by the year end 2020 in the field today doing installation.
In addition, Targa continues to extend its gathering reach into high -- with high pressure pipeline and compressor stations deep into the Bone Springs and also back to the east in the Wolfberry.
Targa is directly benefitting from this multi-horizontal or multi-horizon horizontal drilling with the new completion techniques that Danny described earlier in these oil plays that are developing.
It’s because of this and the growth potential that you see in the Permian Basin on both sides of the Sand Hills facility that we are evaluating capacity expansion all the way out into 2014 for all of this anticipated growth with both sides of our system sitting on pretty prolific plays the opportunity for expansion like Danny has in the expansion of its 200 million a day Sprayberry plant are available to Sand Hills.
In addition to what Danny was talking about we are looking at bridging from the east side of our system over to the new 200 million a day plant. That’s part of the strategic location being right in the center of our system. We can grow towards his plant, and he can grow towards it. So it gives us the ability to attract and gas it from both sides to this new facility.
This kind of wraps up what we are looking at in Sand Hills, next we’ll move to North Texas.
North Texas has some 4200 miles of pipeline of gathering and reaching some 13 counties with two processing plants with combined capacity of 278 million. And also a 15,000 barrel a day local fractionation capacity that we’ll be able to serve local markets for propane and gasoline.
These volumes are trending higher relative -- with relatively flat well permitting activity as seen on the graph to the right. This is due to horizontal drilling and multi-stage completion which resulting, I say that, Danny mentioned earlier, higher IPs, initial product rates also the permits in our area in North Texas are shifting more from the dry gas regions in the southern areas to the liquid rich region in the North where Targa has a strong competitive position and you'll see that in the later map.
The growth drivers in the North Texas and the outlook for North Texas continue to increase from the graph in the lower right, the 2012 volumes are expecting to be meaningfully higher in 2011. The 2013 volumes are expected to be higher also.
Targa has a new 200 million a day Longhorn plant, which is expected to be completed in 2013 for all of this projected volume growth, all anchored by one producer behind her system who is actively drilling. This is the plan that Joe Bob highlighted what we call our Longhorn plant.
Targa is continuing to expand its reach with high pressure pipelines and compressor stations into the liquid-rich areas of the Barnett shale in counties like Montag which set up on the monster or monster arch where the right up at inset arch is where the really rich shale is in both Montag, Clay, Cook in northern west counties.
In addition, Targa is adding two additional compressor stations to support growing volumes and what we call the marble falls play. It’s because of this volume growth and I’ll talk more about marble falls on the next page. You’ll be able to see it but it's because of this volume growth, Targa is also adding compressors to the existing station to support the continued growth in our core areas in the North Texas region.
Like Danny was talking about that you know the pricing advantage of liquids rich combo plays is really driving producers. The producers are focused on these liquid-rich areas for which Targa's North Texas is well-positioned. The combo play composition and the graph to the right shows a producer barrel comprised of about 16% oil and condensate 42% NGL and about 42% gas in the Barnett shale.
From the lower right graph, this translates into about $6.41 per Mmbtu for process rich gas as opposed to about $3 for Mmbtu for the dry gas process in the southern areas of the Barnett shale.
From the graph in the lower right, Targa’s processing volumes are increasing as shown by the red line in 2012. Even in the low price gas environment and when the overall Barnett volumes have decreased, which is primarily reflective of the dry areas where the volumes are going down but in the rich areas you can see that the volumes are going up.
I took a lot of heed early on in the Barnett shale when the volumes were growing and everybody’s volume was shaking to the roof is because the dry gas areas were highly prized with gasping eight dollars and then the lack of completion technology and horizontal drilling and things like that in the north to develop the liquids rich area, now it’s flip-flop, the guys in the South part of the Barnett shale are not drilling the dry gas but they’ve shifted up to my area and that’s why you see the explosion in North Texas and in the Targa series of gathering because we’re in the rich gas areas and this is all due to the producer focus and what’s driving down is the economics.
Okay. Here's the map which shows how well positioned we are for the growth in the Barnett shale. As you can see the Targa system covers a large portion of the green shaded area, which is the liquids rich area. The black dotted oval is what I mentioned earlier where Targa is expanding into our marble falls play in both Jack and Palo Pinto County.
This is a dewatering oil play similar to several mature the old watering place that are active in Oklahoma today. We’ve recovered GPM range, is running about four to five GPM which s helping drive the producer economics in addition to the oil production in this play.
Due to the volume growth, the Longhorn plant is expected to start up in mid 2013 and you can see the star in kind of the pink shaded areas down in to the right. And like I said that -- and we’ve we can talk about that’s going to start up mid-2013. This is a project that's been working on since 2011.
Along with that, you can see two major compressor stations that reach into the liquids rich areas of the Barnett shale shown by the two black squares up in the green area. The plan was actually located in the dry gas area not because of the dry gas but because the strategic location that has to our system.
This allows for maximum flexibility and optimization on the existing Targa assets. So even though it's shown in the pink, it reaches up into the liquid-rich areas but it has a lot of logistics and optimization characteristics that allow us to really link Chico and Longhorn plant together and access the markets in an effective way.
And that’s the story of door taxes. We’re excited about the new plant coming on. Our volumes are climbing. In the interim, we’ve actually made interconnect to another processor to, kind of, offload volumes to give us the ability to continue to attract new volumes while we wait for our new plan to come online in 2013 and it will give us a combined $478 million of capacity. So we’re excited about that.
With that, Hunter is going to talk to you about logistics.
Okay. I'm Hunter Battle and I run a logistics and marketing assets group. And I guess to start with, what a wonderful time to be in the business. Here in, these guys tell of all the activity in the gas process in area and this is going across the USA. And the late part is most of these liquids are heading down to the golf coast and it’s got us as busy as we can possibly be right now.
It’s dramatic. Our footprint in Houston shown at top left and you’ll see that at Belvieu in this chart below, we’ve got at the large position in fractionation. We’ve got our CBF partnership at Belvieu that expanded last year. We’ve got another expansion coming on middle of next year. And then Mike referenced Train 5. It’s -- we’re just waiting on EPA that gives us a permit and we’ve got many discussions going on with potential customers for that Train 5.
Lake Charles is off in the inset, it’s over -- it's a 55 a day unit, gathering liquids from our (inaudible) plants over that area and some third parties. We’re utilizing that space today to handle overflow from Belvieu and we’re operating this whole system on an integrated basis.
We’re also an owner in GCF that went through an expansion, came back out of that couple of months ago. So net-net, it’s a large position and it’s a growing position. The other thing that’s going on if you look at the piping diagram between connecting Belvieu and Galena Park .There is currently five types and Scott’s going to get into more detail on this but part of the announced increase in the export project. Immediately we’re going to start adding another pipe from Belvieu to undergoing apartment shown with dash line and immediately we are going to start adding another ship dock down at Galena Park facilitate the sports activity.
Complimenting that are the -- at Belvieu drilling new storage wells to facilitate the ins and outs associated with the fractionation. So there is a lot of activity in this area and a lot of growth.
Over to next sheet, the next year in our business is going to be sweeping changes from now to a year from now significant pipeline capacities coming online. That’s depicted over here and the chart on the top right. The good news is the headroom associated with those pipelines for further growth. Same time period about 400,000 barrels a day of fractionation is going to come online at Belvieu. That’s a huge step change.
Our expansion is coming online during that period and then further if we do Train 5, that will be a second half 14 of them. As always, connectivity coming in, going out, it’s critical. The infrastructure behind these assets is critical to account for life’s ebbs and flows, get rid of the products, making those go at the right market, it’s huge. The first step of export projects comes down. The large one in September, October next year and then we’ll further that with the enhancements.
There are two companies in the Gulf Coast that do this, you know them. It’s not the easiest thing in the world. You’ve got to have supply. You got to have storage, you got to have pipelines, you got to have chillers and you got to have dock space. Simply said but aggregate in all those assets in that queue is a wonderful footprint that we’re taking advantage of.
The Gulf projects, I think, we’ve hit on those. CBF expanded last year. GCF came out of an expansion. We’ve got Train 4 coming on and we’ll get into further detail on the export enhancements.
Next page, this is old news but it’s great news. The top graph on the shaded area, you can see the growth and the volume seen our fractionators at Belvieu. What a sharp contrast a decade ago. I won’t show you how those lines look back but you wouldn’t see nearest much color, okay.
You had seen 13 and 14 more angles going out. Again, we’ll come out with Train 4, mid 14s. So we’ll have half the year to see those in a four-year run and 14 on that. These are back with solid contracts that are underwritten for long terms. Markets rates in a high reservation level. So it’s a sound investment.
If you look at the graph below that. With these volumes, with these fees, with these commitments the margin on an absolute basis, and on a pre-unit basis is clearly going in the right direction up into the right. And it’s going to continue to grow in 13 and 14 just with announced projects.
Say this also, there are more opportunities in this area. Right now that you can take your stake out. It’s just when you got this much activity coming from the gas process scenario to a key market hub. It’s an interesting time to be in the business.
Next page, you got to ask question, where all the stuff going. Good question. Lot of variations on this but by volume, the biggest molecule we’re handing the ethylene or ethane. You guys know the price curve, the chemical industry in the U.S. has done a sharp rebound.
If you remove fixed price and then in the Middle East side suggest they are number one on the globe, on the cost to produce an ethylene. Okay. And it’s wonderful position and really guys, it’s back to the 1950s and 60s and 70s. That’s were we back then, we’re back there now maybe a little better if we can continue this story line.
The pipes come under Belvieu. Producers are drilling. You’ve heard it from Danny and Clark who are doing this in multiple shales. Clients are filing up. New pipelines are getting build. Pipelines are getting build. We have none at the Gulf Coast, fractionations expanding, exports are expanding. Key to this is what the chemical company does.
We’ve got some info from Envantage here. 12 and 13, the incremental growth by people have in huge financial drivers to go increase the amount of ethane that they are consuming to produce ethylene is estimated at around 260,000 barrels a day and you guys are probably very familiar with the world scale announcements, the Formosa, the Exxon’s, The Dow’s, The Chevron Phillips Chemical later own the evolution of the cycle.
So it’s key to us. We’re working with a host of these guys. We want them. We need them to be successful and we’re doing whatever we can to help them.
The key point, this incremental ethane demand, world scale is leaning hard and heavy on the U.S. Gulf Coast and we’re well positioned for that.
Familiar picture, I’m going to turn this over to Scott. He is going to give you more detail on what’s driving the export market. I would suggest that Scott in his career have done a wonderful job over the last year or so working to get the export project the way it is today.
Thank you, Hunter for that introduction. I’m Scott Pryor. I’m in charge of our marketing and trade, liquid’s marketing and trade and distribution group here in Houston. As Hunter said, this picture -- we've shown this picture several times. We obviously love this picture. It is key to our organization especially when you look at the downstream marketing side of our business.
Lot of what Hunter and Clark and Danny are doing as well as what Stacy Duke is doing in his area and Vincent Di Cosimo in his area and John Gawronski on the wholesale propping side. We are excited about our business. We are excited about the growth opportunities and the four of us are showing just the small piece of our story but it’s big and close to our heart as we see this opportunity continue to grow.
So you’ve seen this picture on off a lot, maybe we should have taken some of Danny’s tips and put some big red stars in some areas that are here on this map. So I’m going to kind of give you a visual where some of these big red stars should probably be. When yo look at the CBF fractionated that Hunter spoke up. One of the piece of the asset that’s driving the project that Joe Bob described earlier the $480 million that we’re spending.
We announced the year ago and expansion project. We now announced the further expansion of that project for export capabilities. At Mont Belvieu, we will be installing De-ethanizer that will basically take our HD5 propane off of our fractionator and converted into international great propane to feed the export market. So a big red star there.
Hunter talked about this series of pipeline that feed Galena Park. The dotted line that you see in this picture perhaps should have another big red star because it’s kind of help us facilitate additional movements of products from Mont Belvieu down to Galena Park across our dock to load small to mid size and now to load VLGCs for the export market place.
Down at Galena Park, perhaps I would suggest you put two put big red stars there. One of which would be a new chilling capacity to fully wrap the product to meet the international grade at market place. Mike mentioned earlier that we -- earlier this year installed a [semi-res] capabilities to help facilitate more quick loadings of the small-to-mid size carriers for the export market predominantly around the Caribbean to Central to South America market places.
So this large chiller will now give us the fully res capabilities and help us to load product much quicker down at the dock.
And then obviously another red star would be that we are adding another dock at our facility that will have -- be a very reversal dock. It will be able to take small vessels, all the way up to the VLGCs. This will complement the existing VLGC dock that we had today that in past history was used in off of lot for imports. Now obviously we’re going to use that for exports.
So we’ll have two docks that we’ll be able to utilize for large VLGCs and then we have two other docks that would be used for both small and mid-sized type carriers. I am now going to give you the laundry list on the right hand side. Joe Bob pretty well describe that in terms what we’re doing. The good news is at start-up with our movements of the ability to load four VLGCs next year, third quarter next year.
We are already fully contract for that. Four VLGCs under contract per month on multi-year contracts. So, we have that getting us right out the starting blocks if you will and then we will be working hard obviously to fill the additional expansion that will come online net the following year in the third quarter of 2014 that will add another two to four VLGCs a month.
Now, a little bit of the business that we are doing today is really centered around loading these small to mid-size carriers anywhere from 4,000 metric tons to 12,000 metric tons, nominally 50,000 barrels to 150,000 barrels of product, both HD5 propane, normal butanes, again a lot of that’s moving predominantly to the Americas, but we are seeing opportunities that are reaching as far as the Mediterranean marketplaces, Northwest Europe and at times entourage that are coming in, going all the way to the Far East.
So, it’s a great story and we are just building on the blocks that we announced last year and we’re just adding an additional series of blocks that really allows us some great opportunities. When you look at this picture on this page, basically just trying to describe what is happening with the resulting propane its going to come out of all these shale and resource plays.
So, we have a forecast here, again supported by some research that Envantage had done, the lower part of this graph reflects and the dark blue really a very flat, retail and domestic marketplace. We are active in that marketplace with John Gawronski’s business. We market all across the U.S. and we compliment that with also refinery services businesses.
The next block above that is propane that is price sensitive to the petrochemical plants. In other words, propane that is used as a feedstock into the petrochemical plants as opposed to other feedstocks. Our belief is what showing here its probably normally around 350,000 to 360,000 barrels a day. To give you an understanding of what we've seen this as we saw tremendous overhang in propane inventories coming out of the season, where we saw the highest inventory, we’ve seen in 10 plus years.
We’ve seen a lot of propane that help reduce that a little bit of that inventory that was cracked in the petrochemical plants. First four month to this year they were cracking around 375,000 barrels a day in those crackers. Over the last four months its probably averaged around 450,000 barrels a day. So, there is a broad swing as to how much propane would be cracked in the petrochemical plants.
The next sliver above that albeit small on this picture, it is growing is a propane that would be used to feed propane dehydrogenation plants, plants that would produce on purpose propylene. As the petrochemical plants continue to focusing on expanding their ethane cracking capabilities for ethylene it somewhat reduces propylene that is produced out of these plants. So, that creates an economic incentive to build PDH plants to take propane and create propylene.
Now, there is one plant existing today that’s operated by PetroLogistics. There has been three other announcements by Dow, Formosa and Enterprise. So, this is a growing marketplace. Question would be how much propane does that takeaway from exports, my belief is it really is dipping into the propane that is price sensitive into the ethylene crackers. It doesn't really takeaway from the overhang of propane that would be used to feed the export marketplace.
When you look down to lower left hand box, Joe Bob described the variables if you will the wrongness relative to the contract price, CP price which is driving really the marketplace that is East of the Suez and how that stacks up against the U.S. OPIS price.
We've seen a tremendous growth curve in terms of that price built over the last several years. Its really odd, when you look at this picture and you see that, when you look at the light shade of imports against the dark shade of the exports, there are mirror image of one another from 2005 through 2011. So, it’s a dramatic picture when you think about it.
So, that gives us from 38 million barrels of imports that came into the U.S. in 2005 to 38 million barrels of exports that went out in 2011. And now we are forecasting nine plus through forecast looks closer to 45 million to 50 million barrels in 2012 and this is going to continue to grow. So, it’s a wonderful story for us and great opportunities.
Touch base just very quickly on the Panama Canal. The Panama Canal, our belief is with everything that we are reading its probably early 2015 when it will become operational. There is a lot of hope by Panama officials that it would be opened up in 2014 to meet the 100 year anniversary of the Panama Canal, but likely it is that’s going to be more like in 2015 timeframe.
The good news is though once that opens up, it's a massive project. You are basically creating two new channels. Each channels is going to have two new locks or excuse me, its going to have two new locks in each channels, its going to have -- or each lock is going to have three chambers to help facilitate the movements of larger vessels, vessels that we would be servicing out of our dock we will now be able to transverse the Panama Canal. It will basically double the throughput capacity of the Panama Canal beginning in 2015.
So, what does that do in terms of looking at international voyage days for product that would be originating from the U.S. Gulf Coast. Well, today if you take a cargo out of the U.S. Gulf Coast and VLGC in this case and you run it around South America, Cape Horn and you try to place it into the Far East marketplace Japan, China regions. It takes about 41 days.
When the Panama Canal opens up that’s going to be reduced to normally around 25 days. So a tremendous reduction in the number of trended days on the water. And how does that stack up when you look at other global competition that is feeding the Far East marketplace, well supply that would come out of the North Sea and supply that would come out West Africa is round 31 day transit times. So we are more competitive in terms of voyage days when you stack that up against the Panama Canal transit versus what you see out of those locations.
Out of North Africa, other places like Algeria, you would be looking at roughly 22 days. So we are very close to that. And then the bulk of the supply that feeds the Far East today obviously the production that's come in out of Saudi Arabian gulf type supply sources that’s around 19 days. So we draw much closer.
You take the freight collapse if you will along with that CP to OPIS price indices. It really creates a huge suction, if you will of supply that can originate out of U.S. Gulf Coast. Moving did not only supply the Americas to supply Mediterranean marketplace but certainly much easier to access the Far East marketplace.
So, the growth in the U.S., the Panama Canal obviously enticements for more supply coming out of there. One other think I will touch base on the kind of last voyage is that when you think about these transit days from a waterborne trader perspective it allows them to better mitigate some of the risk no longer they haven’t hedge that cargo on multiple months and now we are looking at more something that can be hedged from a current month to maybe one month prompt.
This picture here just gives you an overview of how we see the trade sitting up from West of the Suez versus East of the Suez. In simple terms, this picture is basically showing you that production in East of the Suez is not going to be able to keep up with the pace of the demand growth East to the Suez.
So, in 2011, we still saw a still over if you will East to the Suez to help shore up a shot that you had West to the Suez, that over the next few years is basically going to transition where you are going to see supply West to the Suez is now going to shore up shot that’s been created East of the Suez. Just to put it some facts to it. Global waterborne demand is expected to grow by 14% between 2011 and 2015.
Global waterborne demand is around north of 1.9 million barrels a day. Its going to grow to 2.2 million barrels a day or north of that by 2015 and then further growth by 2020 somewhere north of 2.3 million barrels a day. That’s about a 20% increase over that timeframe. U.S. exports are expected or forecasted to increase 130% between 2011 and 2015.
Obviously, our project and our neighbors project will help facilitate a lot of those movements to meet that growing demand that we see in the east. Now, Joe Bob kind of mentioned it, where U.S. supply is relatively small percentage when you look at the globe. We’re about 5.5% in 2011 that is going to double in 2015 to somewhere around 11% and then further growth to around 12.5% by the year 2020.
Far East demand, a lot of that growth is centered around India and Indonesia. And then the Chinese growth story, a lot of that is centered on their own on-purpose propylene producing plants PDH plants that will fed. Now, when you look at China, I would suggest you that some of the forecast that you see above really only reflecting PDH demand growth in China, that is built around eight plants that are currently under construction.
If you look at the number of plants that have actually been announced or that are being steady at the total of about 18 plants. But of the eight plants that are under construction that will come online say mid-2013 to mid-2014, they alone would consume about 160,000 barrels a day of propane and that’s incremental demand for China.
If you look at all 18 plants being built those that are being engineered and plant, you would be upwards of 375,000 barrels a day of incremental demand defeat these PDH units. So, what I suggest you as a forecast above probably only reflects what’s actually under construction and perhaps not, what could be potentially built out into the future with all these PDH plant.
So, it’s a tremendous growth story. In summary, what we are saying here is that East of the Suez, Far East demand is going to continue to grow supply predominantly West of Suez is going to originate out of the U.S. from a growth story perspective and things like the Panama Canal and all the shale resource plays help really facilitate that type of movement.
Appreciate your time. I think now we are going to turn it over to Joe Bob, before we get into the Q&A session.
Joe Bob Perkins
I said, I’d come back to this chart, but after going through it, I don’t think I am going to take you through what we already said, you don’t want that. Instead what I’d like to think is that that’s the list of question types we should be getting for me. Tell us more about our quality asset you might want to ask, you might want to ask about scale, diversity and our fee-based margins. Giving you checklist there, asked about our growth profile and 1.6 billion worth of projects, I loved it if you asked about our strong financial profile, but you probably gotten use to us talking about that.
And then the track record is I hope speaks for itself. But we are happy to tell you about anything we've done or anything we are doing. I think what we are do is because the people online, I’ll repeat the questions, if we can’t get you a mike that’s fine we won’t slow things down. And if I forget to repeat the question, Michael, matter of say repeat the question Joe Bob, because I also need to be reminded.
(Inaudible) the projects that are currently underway. When you look at CB 4 and you are thinking about CB 5 and likewise as you're working on Longhorn and thinking about the new SAOU plant. Are you seeing cost inflation across the industry when it comes to getting these projects done. It’s very busy out there and repeating the question its as we look at all this new expansion projects both the ones that are coming now and ones that are starting now to come of them through 2014, we experiencing cost pressure. That is built into those cost estimates, I should turn it over to Mike, we don’t have. Mike?
We were really concern about what we are going to see and we have really two data points, we have the Longhorn plants that we contracted for last year. And then now the new plants SAOU. The first thing you got to do is look at those plant, the one in North Texas is going to hit process less reach gas, if you put it all on a per barrel basis recovery we’ve seen about a 7% increase in the cost from one plant to another over about an 18 month period.
We were worried that west of demand for both, steel, electronics and labor was going to be much higher than that, but that’s not worry at all has turned out. Actually, when you look at Train 4 versus Train 5, it's going to be cheaper, because is in the same design, the same contractors, the same equipment suppliers. We've got a bunch of the exchangers that we build say for the refrigeration of the exports.
We've already going back out because we are expanding the project basically we said telephone its been cost to build the new refrigeration system for the next two to four ships. And they actually came in at about 5% cheaper than what we are buying the first one for the what we were calling the propane like. And its because basically has that rolled off they are going to start manufacturing in next one. So, if you can put it on a year-over-year aggregate of all the project, we are probably a little bit up or flat to where we are on the first incremental of cost right now.
And Mike, correct me, if I am wrong for the announcements. Right now the SAOU plant we’ve already contracted for the plants has been manufactured. And I believe we completed the turnkey contract for most of the installation involved a lot of long to lead time item. So, we don’t have exposures or upside exposures on that plant. Similarly a lot of the material already is going into the expansion project for Galena Park and we’ve got a good visibility on those delta cost. He was talking about five which we haven’t even announced yet. Turnkey contracts largely.
That’s right they are all turnkeys. They are all with quality APC company who have lots and lots of experience building what, what we want. So we got long track record with all of them. So we are not -- we don’t feel likely we’re going to get surprise at all.
That’s great color and I just have one follow-up on the expansion project, you talked about North Texas processing you are currently using some third-party outsource volumes to handle the kind of overflow you are dealing with today. Is it similar dynamic in the Permian and the kind of question that I am implying here is it sounds like North Texas will come on significantly utilized from pretty early days, would you expect to similar dynamic in SAOU?
We really think that -- we were very fortunate that there was another company that had excess capacity in North Texas. And I think part of that was generated by the fact that some of the gas historically was drilled that was little linear is not being drilled right now. So, we had some space there. So we were able to keep taking gas without having to tell the producer they need to slowdown. So that’s worked out very well. I think if you look at the Permian, the Permian is full. We’ve got little bit of space both pipeline capacity, frac capacity and plant processing capacity. But you don't see that anywhere else. We actually process gas for a few other people, which we can turn off. We do it on a month-to-month basis.
So, I don't think you are going to see really the same dynamics out there on the new plant. It will have a slower buildup and that’s the way we’ve designed the economics and it's just a different world that far out west than versus the north part of the Barnett.
Joe Bob Perkins
The other thing that we are actively doing out at the Permian, at least at SAOU about, if we are worried about running out a capacity, before the new plan is available and we’re not. We forecast our volumes weekly if not daily. We talk to our producers, make sure that we have enough room to do for them what we’ve committed to do form and we believe there is one train purchase before we have another one ready, just like we did with Conger, just like we do in with Sterling, just like we’ll do with the new plant.
We are very proud of what they do there. Mike gets to -- we like communicating with our customers and not letting them down different than the competition to signing people up and having rolling brownouts. That’s not how we wanted to do business with our producers and I think that you talk to them, they’ll tell you.
Sometimes the disappointment is that we are not telling them we can do something that we can’t do. So they’ve got a good idea of when we'll be ready and we’ve got a good of when they’ll be there.
Hey, Joe Bob. Two questions. First question is, as you think about the Panama Canal being expanded in 2015, how do you think barrels are going to ultimately move, i.e. to the Far East, South America and to Europe?
Joe Bob Perkins
Yeah. To all of those but let’s, Scott answer it better than I can. It’s not just one point to point. All of those will happen when the Panama Canal changes the relative timing you saw.
Yeah. All to the above. I mean it’s a combination. We are seeing more and more interest in the Far East. We have spent a lot of time at conferences, assuming myself speaking at conferences. Hunter has spoken here at the Woodlands Conference for Purvin & Gertz. We’ve been to Singapore, we’ve been to Japan. We are going to Istanbul. We are seeing more and more growth opportunity out there. Quite frankly guys, we are missing opportunities today.
We’ve had more inquiries coming into us and that was really what has formed the idea and say look, we’ve got to build on the small side vessels as well as the VLGCs. So it’s going to be a combination of all those things. Ultimately, waterborne trade will dictate where the vessels move to because there is going to be some lot of opportunities created on the shipping side of things as well.
Today, shipping east of the Suez is somewhat sloppy. It’s oversupplied whereas west of the Suez, there is not enough vessels really to lift lot of the cargos. We may have slots available at times but there is not a ship available. So there is a lot of things that we are going to have to manifest out of all of this global growth that’s happening. So it’s going to be a combination of all the above.
Hey, Scott. I mean, obviously pricing is going to dictate and ship movements are going to dictate a large part of this. But as you kind of think about percentages, how much of it roughly would you ballpark in each of those different regions?
Well, I think what you are going to see is east of the Suez, Saudi or Middle East production, what’s call that is it can still be around. In 2011, it was about 1 million barrels a day to 1.1 million barrels a day. It’s going to grow to roughly 1.2 million barrels a day roughly.
Far East demand however is going to grow from roughly 1 million barrels a day to somewhere north of 1.4 million. So east of the Suez production is going to stay east and then it’s going to take Western supply points where much of the growth still is centered around what's happening here on the U.S. Gulf Coast, that's really where those drivers are going to come from.
But it’s not to say that West African times where there is some moderate increases, will now both feed South America, as well as move around the African Horn to move to the Far East as well, so shipping transit times will kind of dictate a lot of that.
Q3 2013, when we've got a million barrels a month of small and medium sized ships and 2 million barrels a month of VLGCs. You are probably going to see some as they go into Latin America, particularly small and medium sized ships in the Caribbean. You are going to see more of the VLGCs go into South America and as well as probably some of that will go into the Far East. That’s the best I can describe it as soon as we open up. And if you look at current waterborne, we don’t have any VLGCs but out of enterprises dock for example, you would see something kind of like that.
Last question. How do you anticipate the economics of the current propane export facility expansion, stacking up with your previous ones? Has the economic environment changed much, has it become more attractive, how do you think about contracting that capacity?
It will be similar but improved. We have seen the fees and our mines continued to increase over the last few years. So we don’t think that there is going to be any missed opportunities in terms of what we contracted for the initial phase. It will be at or perhaps above those types of fees and better than when we first justified it. Much better, much better than when we first justified it.
Danny, a couple of quick questions for you. Just looking at slide 15, looking at where this new processing plant across San Angelo is going to get build, and based on the well connects that you guys have outlined and obviously the GPM with from the production there.
Theoretically, it would make sense if that could get formed up pretty quick. And I would imagine that you guys would probably want to keep most of that POL, POP to get there which would make sense. But looking a little bit west of the formation, you could also make the case that based on the similar GPM uplift and connectivity through the drill bit that you could build another similar plant to capitalize on what’s going on, specifically with the Delaware Bone Spring.
So, how do you think about adding capacity there and also over a longer-term basis, based on your commodity price tag for liquids pricing, how do you think about balancing the contract mix between POL, POP and a bit more fee based?
Joe Bob Perkins
Well, I think what you are going to see is, there probably are going to be more opportunities for plants out there. But I think what we want to do is put one plant out there to moment we can source it from numerous places whether it’s declined in the Wolfberry, whether it’s connected little over to the Sand Hills systems and sourcing from the West.
We will risk averse. Let’s buy one, let’s put one in, let’s start filling it up. And if we see the drilling continuing, the producers keep turning the drill bits to right. We’ve got some other areas to where we would look at and I don’t think that we would have the problem installing another plant. But I think it’s a little bit premature to start looking at doing that at this point in time.
As far as the -- it’s not premature to start looking at it. It would be premature for us to start talking about it. We’ve been looking for quite sometime. As far as getting ready to put it in, not yet. We need to take care of this first one first that gives us a lot of capacity, a lot of room to grow. As far as contract mix goes, I’m not seeing a lot of change from what they were at the moment.
Other companies were adding capacity too. So there is still competition out there. Everybody is working in their own market beyond that way. I think Scott wants to add some.
In terms of the Delaware Basin, our attack has been basically growing our gathering system and moving the gas back to the Sand Hills plant when we have capacity, we have a residue market, liquids market. What you'll see in the Delaware Basin is it's challenged in terms of liquid takeaway capabilities.
There's no real infrastructure out there. It’s kind of like surface will move when you get past packers. It's pretty desolate. So there's not places or places for employees to live. So the development that will occur, the infrastructure has to catch up, plants will get built eventually as residue pipes and NGL pipes that they are bringing go that far to the West.
But that's the challenge today and we are trying to fill up our infrastructure Sand Hills and once that gets full then the next precaution is to put a plan out there to unload Sand Hills for internal growth there and in the Wolfberry. But that’s been our Cactus as far as trying to grow our facilities.
Joe Bob Perkins
It’s obviously he’s been thinking about it.
Yeah. And maybe a little bit beyond thinking about this. So just kind of putting both of those two pieces together, do you guys have any preliminary estimates on what you think the aggregate amount of Y-grade pipe would need to accomplish takeaway out of the [turbulent] processing facilities to move all those incremental liquids to Belvieu? I mean, is it significant? It sounds like it could be rather dramatic, right.
I think it is, but when you look at the capacity owned by the DCP Sand Hills pipeline and also by the Lone Star pipeline. We are going to have plenty of NGL takeaways in aggregate to get it to Mount Belvieu.
But the next question is getting the individual plants tied into those Y-grade pipelines because they come to a point and they stop. They are not going all the way to the Delaware Basin. They are stopping basically in the Central Basin Platforms. So there is still some development to get connections from that point out to the Delaware Basin.
Joe Bob Perkins
Where is the mike? We’ll take one more.
The other thing we have to remember is that enterprises new line that’s coming in out of North Texas has got connectivity to Seminole and to map all and everything out there. So really have three brand new plants -- pipelines coming yet plus you have the lines coming in from DCP from Oklahoma.
So most of those are as you know, deal with diameter first because it’s cheaper. You are not going to have to put in operating expenses, but all of these pipelines have a huge expansion capacity by putting pump zone. And you start off with one in the middle and then you put one at the 25%, right on the either end of that and they have a lot of capacity. I mean, we are going to be really surprised if we find over the next five years we need to add a fourth line.
And you also have a new star out there who has a line that it comes from the coppers field area that comes all the way to Hobby Airport here in Houston. They’ve been talking about that for two years, about converting it from our business and maybe they’re making a couple of sense of gallon to something that could get six or seven sense of gallon for us.
So that’s a kind of the fourth leg in the stool. And I really think that if you haven’t been out there, it’s very interesting. When you’ve, like Clark said, when you get out west [Tapeca] the main things you see out there is jack rig, it’s in Cactus. And if you go back to the 40s and 50s in the early processing plants out in the Permian Basin, the oil companies, gas companies had to build their own camps.
They had to build housing for their people because there was nothing for them when they got out there. They had to bring in doctors. They had to bring in teachers. They had to basically provide all of the things that if you thought about the old company’s story that the company had, that’s the way it is.
Right now, if you want to expand out there you had two choices. You are going to have to go build man camps and man camps aren’t very friendly. If you are out there by yourself, so it becomes then you bring your families and then you have to do all of that. Probably the easiest thing is to build pipelines out there and bring it back to high pressure work avenue.
One thing I would just like to add on that. If you know this management team, if you know Mike, Joe Bob, Rene, Roy, if you think that could let me walk in there and say I need to $225 million to build a plant and that I have got some aspect of that, that is at risk that doesn't happen.
We look into NGL takeaway capacity, residue takeaway capacity. There is no stone left unturned that we build the plant and there is no place to go with the product, that didn’t happen.
Joe Bob Perkins
Nice. You guys like to tell stories like anything.
Two questions I got. One was on the unit trend and crude oil and stocked in. I know that Mike can maybe give some color around size, the number of trains. Is it feasible to rail crude out of the Permian as opposed to the Bakken? It would seem they are lot closer to California. And then also you’ve taken the spread risk there in terms of that business.
I’m going to do something better than that. I’m going to give it to Vincent who’s seen there is a whole lot more about it than I do.
Thank you, Rene. Actually right now that – some of that is still private information that I can disclose at this point in time, but clearly the Bakken has to move east or west. I think everybody agrees with that, analysis have been done. We have a number of constituents if you will that we are already in communication with that we’ve done deals with other terminals but we will move Bakken. It fits refineries on the West Coast. They’ve already done test runs with it.
So to your point, yeah, Eagle Ford makes sense. It comes up from the South, but Bakken also has to find that that kind of mean whether it goes east or west at this point in time. Number trains and capacities, we are not quite there to release that information yet.
Okay. Great. We are going to have a presidential debate here. Question to you, Joe Bob and it’s not on the investment highlights. Maybe you have. To your experienced management team, can you talk about the tuck-in acquisitions, which you made from Copano?
But as you think about M&A, and even if you think about M&A you’ve got two currencies out there, particularly a C-COR currency on the GP level. How do you think about M&A and using both of those currency, which level you might want to do it at and particularly with the C-COR currency out there. Was about that that does your mind?
Joe Bob Perkins
Yeah. Two questions. The first one on currencies, we have equity at two levels. I don't have anything on the near-term radar scope where we are thinking about currencies being used from TRGP. I understand the theoretical possibility, but it is working and pretty doing well to continue our plan to burn these capital investment programs and their large ones, just like we said we would do back in 2007.
50% debt, 50% equity, we’ve raised that along the way and we have a nice sort of leverage ratio and lots of liquidity. We hit an event, we got the liquidity to get us through, are announced in approved projects. So, I wouldn’t say never ever, but I don't have any plans to be issuing any equity at the top end and I hear that more from people like [Alvin] where you hear internally.
On the Copano plant, Mike mentioned it. We think it’s a wonderful addition to the portfolio. We can plum all that stuff together. We move gas from LOU to Lowry that we’ve got two fractionators, and we can move fractionators between the Gillis fractionators and the Lake Charles fractionator. It was a good buy and beyond that I will let – you want to add anything else to the Copano part. It positions us very well. It adds a little bit of EBITDA now and adds some really nice optionality in the future.
Joe Bob, two questions for you. You talked about moving, potentially moving gas for the north, the south and processing at these Gulf Coast plants. Do you envision it being a wet gas coming down or just pipelines spec and then processing out to make it super dry gas?
Joe Bob Perkins
I often forget what I’ve said. From the Far North to the South?
Joe Bob Perkins
Okay. I do believe that definitely. Natural gas liquids are coming from the Marcellus. ATEX is going to bring ethane. Without question, ATEX has the right to bring Y-grade if they want to. There are multiple projects being discussed to bring, I’ll call it Y-grade, but it will be sort of wide prime grade meaning propane will probably be taken out and we’ll have a mixed stream coming from the Marcellus and the Utica towards the Gulf Coast.
If one of those projects does not materialize I will be shocked and I won't understand that economically, but I can’t predict which one will come. And when it comes, it continues to load. We’ll call at the Mont Belvieu through Lake Charles, NGL handling capabilities through different way.
Maybe to answer your question a little bit different. We say that the Gulf Coast Straddles plants and our plants are new in this new Copano plant are ideally situated to move gas that may be developed in North Louisiana south to the existing infrastructure. We’ll be in talk to by several interstate pipeline who have multiple lines in the ditch that are going from the Gulf Coast to New York City, Washington, Philadelphia that the volume is declining everyday, because the Marcellus and Utica gas is displacing it out there.
They are going to get to the point where somebody at FERC says or our customers says those lines are no longer use to use for. You need to take them out of your right base. So what is happening is those interstates pipelines have been proactive and there is same, may be you don’t want to build the plant up there in the Marcellus our Utica, because you create all these other problems.
You’ve got to figure out what you can do with your liquids. So, why not just taking existing asset that we have, turn it around and bring wet gas back down. And remember, what we've got as we've got a series of plants that are connected to all these pipelines, Those are dry gas headers. Some of these pipelines have got multiple pipes in the same ditch that go right by our plants. If some of them can be left as residue pipes from our plant that the other one can be converted to wet gas and that’s what they are talking to us about.
So that goes to my second question which is with that potential along with, you’ve talked about the resurgence in the Gulf of Mexico on drilling, how much spare capacity do you have at those Straddle plant to the Gulf of Mexico -- or just the Gulf Coast plants. And five years from now what do you see is that opportunity to fill some of that spare capacity?
Joe Bob Perkins
If you look at our Straddles plant on historic data and prior to why cost could have been shut down, our net capacity did see percent utilization, Mike. That’s a nice around number for us. That means we got 50% of that capacity that you see on -- forget which page it was -- is available highly interconnected, [Dennis] probably fills up, continues to fill up.
[Dennis] -- you will see increasing liquids from [Dennis] over the next couple of years really just from the Gulf of Mexico in getting liquids rich gas in [Divines]. The rest of that complex being interconnected has the upside potential, we’re not forecasting.
Joe Bob Perkins
The upside potential of processing gas from a Gulf of Mexico from Louisiana onshore and from even Y-Grade from further north.
Mike is right. I did even mentioned and you’ll know we’ve talked about it for sometime. It’ s very public. Shell Mars B is coming to own in end of 2013 to 2014. I recall this very public. They barely slow down due to Mankato and they’re highly public about coming on. That’s all dedicated to us. It make significantly difference at that scope. It’s night rich gas.
Just to follow-up on Gabe’s question regarding the unit train opportunity. Is it contemplated as fee-based investment or one in which you would participate someone in the spread between ANS and dock?
Joe Bob Perkins
I’d handed the mike back to Vincent back but it really is a short answer. It’s a fee-based opportunity. That’s how we are applying, just like we provide docks space on the export. We’re providing manifest now building up to unit train space to our facilities primarily that go out waterborne.
And Mike repeats we don’t intend to own any of their commodity. You’ll probably already knew that about us, he just wanted to make a decision.
Any further questions.
Joe Bob Perkins
We are running short on time but will be around afterwards
Yeah. Just curious on -- you indicated you’ve got $1.6 billion of announced projects. I’m just curious, beyond that yield how much are you evaluating in terms of opportunities being idea for evaluation backlog?
Joe Bob Perkins
The evaluation backlog looks a whole lot like what we’ve announced. You know it wasn’t long ago. We had a $1 billion on the table and I said we got in the -- about that much again that we’re working on very actively with high probability in now get it $1.6 billion on the table and I don’t thank that the things were working on have gotten any smaller or any shorter.
And when I say the kinds of things, you want to know what this would look like?
Last few times, I have looked at the chart. It looks like a third to little bit higher percentage Gathering and Processing in the rest on the down stream, some thing like that 3 to 40% on the gathering in a processing and more on the down stream good sort of anything that I can project.
In it’s not hard for you to see that take one more 200 million a day plan and then you take train 5 involving cares to about $350 million as we said this about like train 4. You can start seeing how amount ratio is up and doesn’t take very long before you’re billion plus.
Okay. Let’s do a one last question here. Okay, Kelly.
Just quick question on report your hand from the producers. So just a quick question on what you gain from producer based on last several months. They are about weaker in DL pricing and obviously the proliferations of these liquids to rich play. Are you seeing any of them starting to think about pulling down their activity as a result of the lower prices? Any comments about on that?
Joe Bob Perkins
If I take a broad reading, look across the United States and reading like yield there. I know some producers have slow down whether in drier gas areas, low liquid’s content. That’s all relative I understand. When I go to our area, North Texas and the exciting combo play are looking to the Permian basin where they are drilling for oil.
They then get the liquids in gas but I think all they have was oil they would drill forward. Of course, they have to take care of that gas, I mean, they are to help, we really not seen slow downs. If there is any slow downs at all, sometimes they are sort of end of year slow downs and then they kick back up. I don’t even think we’ve seen the end of year slow down. So it’s a function of where you are.
Permian Basin first half continued to look like that. We’re getting a large and large share of the U.S. rig count, well across the Permian Basin, we’re getting that share of that.
Okay. Thanks everybody for your questions today and for joining us. For those going on the tour, we will take a 15 minute break. So 10:45, we will meet just right out on here front of the hotel and also of note, in your bags, you will see a flash drive. We have the presentation loaded on that flash drive. So if you don’t want to carry the hard copy back with you on the plane you have that available to you as well. Thanks again.