Welcome to the Kinder Morgan Quarterly Earnings Conference. All lines have been placed on a listen-only mode, until the question-and-answer portion. (Operator Instructions) Today's conference is also being recorded. If anyone has any objections, you may disconnect. (Operator Instructions) I would now like to turn the call over to your host to Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. You may begin, sir.

Okay. Thank you, Holly. As usual we’ll be making statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. We will be referring to Kinder Morgan, Inc., as KMI, to Kinder Morgan Energy Partners as KMP and to El Paso Pipeline Partners as EPB. And we’ll cover all three. Let me kick it off by saying we had a very good quarter and we are on-track for a very good year. We expect all three of our entities to meet or exceed the distribution or dividend targets that they have for the full year. I am going to mention just a few significant matters before turning the presentation over to Steve Kean our Chief Operating Officer, who will talk about the specific performance of our business units and also about our backlog and then Kim Dang our Chief Financial Officer, who will go through the details of the financial results for the first quarter. Let me start just with the high view of our operating performance, three or four things come to mind, we had extraordinary gas throughput during the first quarter and we moved what we think as an all time record for us 33 Bcf a day during the month of January on average. And that’s about 33% about a third of all the natural gas consumed in the United States during that month. In our refined products group, we actually had a pretty nice increase in refined product volumes. We’re actually have up 5.3%, if you count our Parkway project, I think it’s fair to script that out, script that out with 3.7% in refined product volumes, and that’s versus our estimate from the EIA of 1.1% across all of United States. Over in our CO2 segment we had another…

Thanks Rich. I am going to give an update on the backlog and then I’ll go through the segments quickly. So starting with our January Investor Meeting last year we’ve been giving -- we gave out our backlog and we’ve been updating that pretty much every quarter since then. As Rich mentioned we went 14.8 billion to 16.2 billion across all of the processes on a combined basis. So we added this 1.6 billion in the backlog also putting into service over $800 million in the projects. Our project petitions grew, total backlog was offsetting of the process we put into service. On the larger projects we put into service where there is a $100 million KMP swinging lateral to serve the Phillips 66 Refinery there. Almost $500 million with the terminals group projects went in including phase one of our Edmonton internal expansion and expansion in our Pasadena Galena Park facility and some coal export facility expansions. We also had about $150 million of projects come into service in the CO2 segment during the quarter. Now a reminder about the backlog, it consists of those projects that we view as highly probable, highly confident that would be done, not a guarantee but a very high probability. We actually expect to add to this and do more and invest more capital than what we have in the backlog, but unless we have a project that’s highly probable we don’t add. So here is the business unit composition, the gas group is up from 2.7 billion to 4.1 billion that 1.4 billion is by far the biggest increase across the business units. Here the biggest additions were the $780 million expansion for Antero to increase south bound EPB capacity the Utica and Marcellus. This demonstrates again the strong demand for additional…

Okay. Thanks, Steve. Turning to the numbers, first on KMP, today we are declaring the Board approved declared dividend at KMP of a $1.38, that’s a 6% increase over the first quarter of 2013. And this is on the first page of numbers for KMP which is on the bottom of the GAAP income statement. On the GAAP income statement I’ll point out that net income is down -- net income attributable to KMP is down $37 million, but this has all the certain items which we will outline for you on the next page. The largest one being $141 million gain on the sale of Express, that was a benefit in 2013 and obviously not recurring in 2014. So going into the next page and looking at our calculation of distributable cash flow which is reconciled back to our GAAP net income. We’ve produced Dcf per unit of a $1.55 for the quarter, comparing that to the $1.38 for our cleared distribution that is $76 million in excess coverage in the quarter, as we tell you almost every quarter we expect to have excess coverage in the first quarter, in the fourth quarter, and typically we will have negative coverage in the second quarter and the third quarter, and we will have excess coverage for the full year. Right now, our excess coverage for the full year is nicely above our plan as a result of the new contracts that we’ve signed on TGP and EPNG and also as a result of the APT acquisition, which is why you see us guiding to our guidance, which says we’ll declare at least $5.58 per unit. On the $1.55 on a total basis, Dcf is $699 million that’s $143 million increase or 26% increase over the quarter of 2013. Looking at…

Okay and Holly if we’ll take any questions you may have, Holly if you’ll come back on and give them their instructions. We’ll go from there.

Thank you, sir. (Operator Instructions) And the first question comes from Bradley Olsen with Tudor, Pickering. Your line is open.

Alright Brad how are you?

Doing well Rich how are you? Tudor, Pickering, Holt & Company: Doing well Rich how are you?

Pretty good.

A quick question on the Tennessee gas reversals, it seems like you guys have been able to line one of these major by directional or reversal projects up on TGP every few months. And it seems like your projects are generally able to go from planning to realization faster than a lot of the other pipelines in the Northeast. How many more potential reversals could we see out of TGP? And would the reversal or the potential reversal for the NGL Y grade pipeline down to the Gulf Coast impact how much of the pipeline could be used in a gas reversal? Tudor, Pickering, Holt & Company: A quick question on the Tennessee gas reversals, it seems like you guys have been able to line one of these major by directional or reversal projects up on TGP every few months. And it seems like your projects are generally able to go from planning to realization faster than a lot of the other pipelines in the Northeast. How many more potential reversals could we see out of TGP? And would the reversal or the potential reversal for the NGL Y grade pipeline down to the Gulf Coast impact how much of the pipeline could be used in a gas reversal?

Yes I’ll turn it over to Tom Martin who runs our Natural gas pipeline group.

Yes I think we certainly have the opportunity to look at more backhaul or south bound capacity, any other used capacity that we’re creating for the NGL projects that ultimately if that doesn’t go we could use do that for additional gas or as needed. We’re also very excited about our results for the non-binding open season to take additional Marcellus gas ultimately into New England between those two projects we would see anywhere from 1 to 1.2 Bcf a day incremental volumes going into the New England market. So we think both from the demand that we’re seeing southbound as well as the interest to go, to bring additional volumes into New England. We’re very excited about our growth prospects going forward.

Great, thanks Tom and I guess just may be push a little bit harder on that on the northeast reversals. Are you -- is there a number we can think about in terms of potential additional reversals on TGP or is it difficult to give a precise number? Tudor, Pickering, Holt & Company: Great, thanks Tom and I guess just may be push a little bit harder on that on the northeast reversals. Are you -- is there a number we can think about in terms of potential additional reversals on TGP or is it difficult to give a precise number?

Yes, I mean it all depends on what rates the market ultimately will bear, but I think all the -- relatively speaking the lower cost expansion projects have been done but I think we’re continuing to see interest even at higher level, so it'd get hard to speculate on volumes but I think we’re certainly talking to our customers every day and there is still interest for more capacity.

Yes I think that again Brad the key thing here is if you just look at these numbers, the numbers tell the story. Again, we expect across 15 Bcf of production this quarter up there. There is not nearly that much demand particularly this time of the year in the northeast. If you look at this ramping up in fact Wood Mackenzie would show it ramping up just in five years to 22.5 Bcf, so a ramp-up of 7 Bcf just in the next five years and those volumes have to go some place. And of course what we have is we have essentially it’s a little bit of a simplification, essentially a pool of big lines that were originally tended to go south and north. Now we’ve in essence reversing two of them on what we’ve done so far. So there is more opportunity but Tom is right, the further you get the more expensive it gets and we’ll just have to see are there people willing to pay freight. But obviously there is a tremendous need for more capacity to get natural gas as well as NGLs out of Marcellus Utica.

Great. And just one last one from me on the natural gas front, sounds like there is a lot of growth potential coming out of Mexican demand. And I would imagine given the fact that that country continues to import high cost LNG that that could be a real growth market. When we think about kind of how big that volume opportunity could get, are there limitations on the southern side of the border with Pemex’s pipeline system or do you see quite a bit of running room to continue to expand exports south bound? Tudor, Pickering, Holt & Company: Great. And just one last one from me on the natural gas front, sounds like there is a lot of growth potential coming out of Mexican demand. And I would imagine given the fact that that country continues to import high cost LNG that that could be a real growth market. When we think about kind of how big that volume opportunity could get, are there limitations on the southern side of the border with Pemex’s pipeline system or do you see quite a bit of running room to continue to expand exports south bound?

I think they will continue to expand their infrastructure south of the border. And the real test of that is when they sign-up for long-term contracts on our side of the border. So I think we believe that over the next 10 years demand will more than double from the present throughput that goes into Mexico today and the reason is very simple. They are converting electric generation at industrial use from oil to natural gas, the opening of the energy business in Mexico we believe will concentrate primarily on oil not on natural gas and the only alternative as we switch to natural gas is to import LNG which is very expensive and of course that led to I don’t know all the details, but essentially the closing of the Altamira plant which I think was a mutually beneficial thing from both the Mexican importers and shale that could take that LNG and move it elsewhere. So cheaper a source of natural gas is clearly from Texas and the rest of the U.S I think you’ll see some Rockies gas and in fact going into Mexico and of course EPNG is just -- again if you think about Tennessee being ideally positioned in the Marcellus Utica, EPNG is tremendously well situated for the exports to Mexico.

Just one other point there, they are building out the infrastructure south of the border it’s not dependent though on Pemex getting it done, so in Tennessee is or Tennessee’s power plant developments that they’re putting up, they are having private companies are coming into developed and build out the transportation capacity that’s going to be acquired south of the border, you get it from our line basically to the power plant to the vehicle.

Great, and when we think about 800 million of demand on EPNG for those new contracts that you mentioned in the press release. Is it fair to assume that most if not all of that volume is coming from demand south of the border? Tudor, Pickering, Holt & Company: Great, and when we think about 800 million of demand on EPNG for those new contracts that you mentioned in the press release. Is it fair to assume that most if not all of that volume is coming from demand south of the border?

High percentage of it but there is some up [Multiple Speaker] and in addition to that there we think there will be significant additional opportunities. We think the 800 is just kind of a starter.

Great, thanks so much everyone. Tudor, Pickering, Holt & Company: Great, thanks so much everyone.

Our next question comes from Darren Horowitz with Raymond James. Your line is open.

Hey Darren, how are you doing?

Fine, thanks Rich. Two quick questions from me, the first regarding that March announcement that you guys made of additional billion dollars of CO2 investments. If I’m just thinking about that 700 million that’s going to be focused on drilling wells and building out that fuel gathering infrastructure at St. Johns. Can you give us a sense of the average unlevered rate of return across that project set? And I’m trying to think about it with regard to how that compares to the average unlevered IRRs on that 1.5 billion in EOR backlog CapEx that you outlined at the Analyst Day over the next five years? Raymond James & Associates: Fine, thanks Rich. Two quick questions from me, the first regarding that March announcement that you guys made of additional billion dollars of CO2 investments. If I’m just thinking about that 700 million that’s going to be focused on drilling wells and building out that fuel gathering infrastructure at St. Johns. Can you give us a sense of the average unlevered rate of return across that project set? And I’m trying to think about it with regard to how that compares to the average unlevered IRRs on that 1.5 billion in EOR backlog CapEx that you outlined at the Analyst Day over the next five years?

Jim Wuerth?

Yes, I think unlevered we’re looking in the mid-teens on the pipe in the infrastructure there. I think that’s where we’re at as mid-teens.

Okay. Raymond James & Associates: Okay.

We’re building a new pipe from St. Johns over to intersect with our Cortez system just South of Albuquerque.

That’s correct.

And overall, we think we will be in the mid to upper teens on the returns on that billion dollar investment.

Do you think Rich though that just based on the large upfront capital that you spent there that your incremental returns theoretically should get better? Raymond James & Associates: Do you think Rich though that just based on the large upfront capital that you spent there that your incremental returns theoretically should get better?

Well it could, and it just depends on exactly how the contracts work out in the end.

Obviously, if you look at McElmo Dome 30 years ago when Shell and Mobil operated it, they had to make a decision to put in the Cortez pipeline. It’s very expensive when you put that first build-in and the numbers don’t look that great, in today’s world it looks like a great investment. We’ve had it now for close to 14 years and the volumes just continue to go up without not a lot of infrastructure being added on the pipe, so I think you’ll see the same thing within St. John’s and the Lobos pipeline.

Okay. And then last question for me, Steve. Back to the products by segment and that growth in cash flow that you talked about, as we’re thinking about the backend of this year and into the first half of 2015, can you give us an update on KMCC capacity utilization? I know that we talked last time you said it was about two-thirds book but obviously, there is this -- there is big supply growth of south Texas condensate that’s moving east. So I’m wondering from your perspective how you think about if you do changing the scale or scope of that 1.8 billion of capital that you’re going to spend across the ship channel? So maybe some additional ship docks at Colina or more interconnects between Galena and Pasadena. It seems like there is a lot of opportunity and you could spend more money, so I’d love you thoughts there. Raymond James & Associates: Okay. And then last question for me, Steve. Back to the products by segment and that growth in cash flow that you talked about, as we’re thinking about the backend of this year and into the first half of 2015, can you give us an update on KMCC capacity utilization? I know that we talked last time you said it was about two-thirds book but obviously, there is this -- there is big supply growth of south Texas condensate that’s moving east. So I’m wondering from your perspective how you think about if you do changing the scale or scope of that 1.8 billion of capital that you’re going to spend across the ship channel? So maybe some additional ship docks at Colina or more interconnects between Galena and Pasadena. It seems like there is a lot of opportunity and you could spend more money, so I’d love you thoughts there.

I know you’re right. And capacity utilization tends to be -- is still running well under contractual commitment. And so one thing that to understand there is that we are getting cash in now into deficiency payments, but we are not able to reflect that in our current results until we get either they start moving the volumes or they -- their makeup rights expires and. And so that’s kind of holding back the performance of KMCC a little bit, but again the cash is coming in the door. But you’re exactly right, the way that system is now being developed, I mean, it is gone from in a very short period of time -- it is gone from kind of the point-to-point system to being a network. A network that we can build off of and then we can invest and invest at very high returns on those incremental capital spend. And so we’ve got about $300 million worth of laterals and associated facilities like truck offloading and tank facilities that are in our backlogged that we haven’t yet seen the revenue off but they run fairly quick built outs that we can do and we are doing. And I think we’re going to continue to find more of that. And Ron do you have anything to add to that?

I just think there is a lot of option now until you, and once you get to the Houston Ship Channel it can -- no one can move to petrochemical plants. [Indiscernible] I just think there is tremendous flexibility for shippers and so that capacity will go pretty soon.

And the other example of that so we had one lateral that we were able to get into service early but we don’t have the tonnes in the other facility that’s going to be necessary to achieve the full throughput. While we’re unloading trucks into that lateral right now and we just ramp that up over the coming year. So again if you look at that system, it’s now connected to multiple producers, kind of CDPs and also truck offloading facilities, connected to the multiple producers. And we can now take it to multiple markets. It goes to the Phillips 66, Sweeny refineries in South of Houston. It goes to the Houston Ship Channel. And we’re connecting it up with Double Eagle so it can go to Cortez as well, so just a great network that allows high return project to be built off of it.

Thank you. Raymond James & Associates: Thank you.

Our next question comes from Brian Zarahn with Barclays. Your line is open.

Hi Brian.

Hi Rich I appreciate the project backlog update. And what’s the status of the Y grade line of the Marcellus, Utica? Where do we stand? Barclays Capital: Hi Rich I appreciate the project backlog update. And what’s the status of the Y grade line of the Marcellus, Utica? Where do we stand?

Yes, we continue to work on it but we don’t have commitments yet. So we are not putting it in the backlog. There is some indication from the market that people have been very focused on getting some of their dry gas outlet taking care of course and they’re going to turn their focus and attention to additional wet woods or NGL outlets. So I would say that the interest in the project continues to grow. So the update for the quarter is people are interested and more interested than they were the quarter before. But until that turns itself into signatures on contracts again it’s not going in the backlog and we’re not going to call it done. And as Tom pointed out, we do have the ability to use that line. We’re preserving the ability to do both. And that’s our preference. We want to do residue gas outlets on the TGP system. We want to presser the Y grade option assuming our customers are willing to sign-up. But ultimately if they’re not, then we can put that line in residue gas service and put it to good use that way. So long story short, we don’t have the commitments we need yet, but I think interests from the customers continue to grow and we’ll keep working on it.

And then I guess that and the other project that are not in your backlog and how should we think about the potential growth and the inventory now through 2017 if some of these projects are added, maybe currently 16.4, I mean can we got to a $20 billion number or how should we just think of a range with potential outcomes? Barclay Capital: And then I guess that and the other project that are not in your backlog and how should we think about the potential growth and the inventory now through 2017 if some of these projects are added, maybe currently 16.4, I mean can we got to a $20 billion number or how should we just think of a range with potential outcomes?

Hi Brian and as you know we’re being very conservative about that different people take different approaches to how they articulate their backlog. People sometimes put in projects that they think ought to get done or have a good reason to get done, but we have tend to put in the ones that are just very high probability. And so for example UTOPIA I think is a project that gets done but we’re not quite there yet. We got to have an open season, we got to firm that LOI up in to a real firm transport commitment. That's another 300 plus million dollar project there. If you remember from Investor Day, Tom articulated about $15 billion worth of projects in the natural gas sector alone, adding on to what we’ve signed up here recently on EPNG may be getting at a couple of those northeast expansion, both of the northeast expansion projects so we did the non-binding open season in. Those are billion dollar, multibillion dollar moves or additions to the backlog. But again we’re going to continue. I think we’re going to maintain the same methodology here. We’ll identify some of those things for you but we’re going to keep the backlog limited to those things that we’re highly confident we’re going to put in service.

And then turning to… Barclay Capital: And then turning to…

Just to say we’d be highly confident we’re going to put in service.

Okay. Turning to Ruby, it looks like GIP is ready to sell its remaining 50% stake. How do you think about that option? Barclay Capital: Okay. Turning to Ruby, it looks like GIP is ready to sell its remaining 50% stake. How do you think about that option?

Well, we'll just see how that develops. Clearly as we’ve said we’re going to drop -- KMI is going drop its half down to EPB this year and we’ll just see how the GIP sale goes and really don’t have any counting on it other than that.

Okay. And then on the CO2 business, what impact if any is backwardation having on your hedging program? Barclay Capital: Okay. And then on the CO2 business, what impact if any is backwardation having on your hedging program?

Well we maintain the discipline under our hedging program and we hedge whatever the price is and obviously the backwardated market that hedged price in the out years is lower than the front-end. We believe that will probably change but we’re not in the business under our hedge policy of guessing on that, so we stay within our parameters. Obviously within those parameters we try to pick off the days when the out years are a little stronger. But we’re maintaining that as we always do, we have we’re more heavily hedged obviously in the front-end than in the back-end.

And just a last one from me on the warrants how many are standing at the moment? Barclay Capital: And just a last one from me on the warrants how many are standing at the moment?

317 million.

Thanks Kim. Barclay Capital: Thanks Kim.

Next question comes from Ted Durbin with Goldman Sachs. Your line is open.

Ted, how are you doing?

Hey doing well, thanks Rich. Just want to come back to gas here and may be again push a little bit more on -- what’s the sort of incremental capital you think you need to put in two, three ups in other Bcf a day of volumes out of the Marcellus to get to the Gulf Coast? Goldman Sachs: Hey doing well, thanks Rich. Just want to come back to gas here and may be again push a little bit more on -- what’s the sort of incremental capital you think you need to put in two, three ups in other Bcf a day of volumes out of the Marcellus to get to the Gulf Coast?

Tom?

Yes, I mean that’s a tough one. Again it really just depends where the source of supply is and ultimately where we’re trying to get to. I mean I think right now the biggest volume opportunity is going to be the Marcellus supply project into right New York and right New York into New England, those are going to be the most cost effective expansions right now and then we’ll look at -- we’re continuing to look at how we can get more volume down to the Gulf Coast but those are going to be more expensive.

Okay. And then can you give us any more color around whether it’s the most recent supply project, you have done a project with Antero or the future ones, how are you thinking about sort of the option value of the capacity you have. Would you charge max rates? Should we expect negotiated rates that would be higher than what your sort of tariff that is on file with the FERC? Goldman Sachs: Okay. And then can you give us any more color around whether it’s the most recent supply project, you have done a project with Antero or the future ones, how are you thinking about sort of the option value of the capacity you have. Would you charge max rates? Should we expect negotiated rates that would be higher than what your sort of tariff that is on file with the FERC?

Yes, I think you can expect it all on our new projects. These are negotiated rate contracts.

Got it. Goldman Sachs: Got it.

Higher than a non-filed tariff yes they have to justify the capital expenditure.

Right. Got it. And then if we’re thinking about and this is a small one but just the impact of weather on some of the volumes just may be in the gas segment or any other segments. Can you quantify that at all? Goldman Sachs: Right. Got it. And then if we’re thinking about and this is a small one but just the impact of weather on some of the volumes just may be in the gas segment or any other segments. Can you quantify that at all?

The impact of weather was -- Steve can take you through the exact increase year-over-year, but a lot of what we’re seeing now is longer term demand across the whole system and to me that’s much more important than weather. Steve can give you…

I think that’s the key as that when Rich was talking about the 2.8 Bcf of contracts, those were 15 year average commitment or nearly 15 years commitment. So that’s not about the weather, that’s not about a cold winter. That’s obviously -- that’s about long-term need or long-term demand for the capacity. I think we saw benefits from the colder weather certainly on the Texas intrastate we saw it on NGPL, the NGPL asset. On a lot of our other assets, intrastate assets we’re pretty much looking at demand charge, primarily demand charge based revenue received so it’s a little less whether dependent in the short run, I mean, again everybody got a real wakeup about the need to hold firm transport capacity this winter and I think that again holds promise for demand for future capacity and maybe for some of the expansions into the northeast for example, but that’s not really a short-term phenomena, that’s really just driving long-term demand for transportation. And as I mention you know we had record, we got very high storage results on the Texas intrastate and for good sales opportunities for us there as well.

Great. I leave you at that. Thank you. Goldman Sachs: Great. I leave you at that. Thank you.

Next question comes from Craig Shere with Tuohy Brothers. Your line is open.

Great. Craig, how are you doing?

Good. Thanks Rich. Good afternoon. Let’s stay on the potential growth opportunities, can you just update us on the FERC application at Elba prospects you are securing FTA-based export contracts for Gulf LNG and if you are any more optimistic around non-FTA authorizations now that I think Elba six in line and Gulf LNG is seventh and Russia is saber rattling? Tuohy Brothers: Good. Thanks Rich. Good afternoon. Let’s stay on the potential growth opportunities, can you just update us on the FERC application at Elba prospects you are securing FTA-based export contracts for Gulf LNG and if you are any more optimistic around non-FTA authorizations now that I think Elba six in line and Gulf LNG is seventh and Russia is saber rattling?

Yes. [Indiscernible] On the FERC application we have filed the FERC application for Elba now and I of course remember that that’s not contingent, really that’s the only contingent left just getting the FERC approval because it’s not contingent on non-FTA approval, although we think we’d like to have that that would give our customers show a little more of leave way and work loose the LNG out of Elba. But we filed and are moving forward on that so that’s about to grow. On Gulf LNG we and our partner there just primarily GE have now authorized money on a pre-feed expeditor. We have a lot of interest there. And we think that about the time we complete the pre-feed we will have MOU signed for that capacity at Gulf LNG. Now, let me be very clear the MOUs are MOUs and that doesn’t mean they are fully binding on either side because we will certainly want to go beyond the pre-feed to nail down the cost of the project and our customers will want to nail down the cost, the tariff is going to be charge them, I’d say we’ve turned more optimistic on that and we and GE together have decided to go forward with the pre-feed based on the conversations we’ve had over the last two or three months. I think this whole LNG export market has become more interesting, I don’t know if they are going to move up the liquidity of approval on a non-FTA request given what’s happening in [indiscernible]. I would think they should and that as others have said they should use FERC as a clearing agency as opposed to DOE making decisions, they should just approve ever by like FERC started out, and let the contract work started out. But we’ll see how that turns around but we believe that Gulf LNG does have some potential and we’ll count on that.

Yes I think we have a feeling over there that as you know Gulf LNG is the last remaining ground field with the fraction opportunity and I think what our balance sheet I think the customer response and the interest has been very positive so far.

Great. And if I can get Jim for a second, it looks like your oil production fell 1.5% sequentially, but they are obviously out year-over-year. Can you provide any color on the progression of production this year? And do you have any updates you can share about the potential CO2 supply sales in the California, the LNG flooding or ROZ? Tuohy Brothers: Great. And if I can get Jim for a second, it looks like your oil production fell 1.5% sequentially, but they are obviously out year-over-year. Can you provide any color on the progression of production this year? And do you have any updates you can share about the potential CO2 supply sales in the California, the LNG flooding or ROZ?

From the volumes SACROC continues to be strong, month to-date we are so running about 32,000 barrels a day. And Yates, you know it’s a slow decline there we’re trying to do what we can to maintain that as best as we can, the other two new ones are both responding pretty well in a last few days, at Katz we’ve been close to 4,000 barrels a day and at Goldsmith we’re 15,000 barrels a day, so both are moving up. So I think the outlook on the crude side is volume is still really good. As far as potential of CO2 to California, obviously that’s going to be a long haul project, we do have some -- obviously we have some interest out there from some customers, we’ve signed some documents there, but that probably be putting on can you get approval to move CO2 into California, so that’s where we are working today. As far as the Yates had to cover miserable project where we should be kicking that off here this quarter, the test I filled it on that and based on the results of that, we’ll move that forward.

And anything on ROZ that you could share at this point? Tuohy Brothers: And anything on ROZ that you could share at this point?

Obviously we’ve done some additional phase I drilling and continue to be very bullish on what we’re seeing, we’re actually out in the phase I area now drilling, start-up couple of wells out there, so hopefully we should have something that where we’re injecting CO2 by the end of the year.

Okay. And one general question, when you say that CO2 is recycled over many years each time it’s not the same quantity right, because you’re getting 30% to 50% each time. So ultimately like when you buy 100 million cubic feet of CO2 to inject, how many times do you think you’re going to inject that twice or three times? Tuohy Brothers: Okay. And one general question, when you say that CO2 is recycled over many years each time it’s not the same quantity right, because you’re getting 30% to 50% each time. So ultimately like when you buy 100 million cubic feet of CO2 to inject, how many times do you think you’re going to inject that twice or three times?

One ways you can kind of look at it is on a normal field you have to purchase about 6 Mcf per barrel of oil. What really happens is you have about 11 to 13 times that you inject the volumes of CO2. So a little about double, little over double basically it says that rolls to at least twice.

That’s very helpful. And last question back to Rich, if Jim does as well as it sounds, it’s possible and ROZ and EUR still looked at as a negative roll for KMP. Could you see an argument long-term for why the broader CO2 segment may make more sense to trade separately than stay in EPB?

EPB, you mean as a separate MLP?

Yeah, I mean people always ask you once in a blue moon would you ever consolidate EPB. Obviously that makes some sense over time, the question is if it’s getting the respect and it’s laying down the rest of the business and there is other natural interested investors in it. Why long-term when we just have a good portion of CO2 just trade separately?

Well we look at all alternatives certainly there is a lot of issues on what the tax basis would be, spotted out. Lot of issues we’re doing, separating and we’re very bullish on the CO2 business I think right now not being appropriate time to do something like that. We saw at the analyst presentation the kind of uptick in distributable cash flow, we expect from those operations. It’s a unique entity because everybody right now is in love with the Permian basin in terms of E&P activities there; well that’s where we are. But the thing that separates us from most other people is we have our own in house supply of CO2 which we certainly will and can sell to third parties. But we can also use for our own efforts which gives us I think a tremendous leg up and enable to continue to grow things like ROZ if that turns out and certainly sack (Ph) rock is just a big field, things are getting bigger we’re really pleased with the way everything is going here. So we are very pleased with, again we always consider all kinds of alternatives at Kinder Morgan but we think CO2 is a good fit the way it is.

Our next question comes from [indiscernible]. Your line is open.

With all of the opportunities in the natural gas pipeline segment, I was wondering if you could provide an update on investments in the partnerships coal terminals and also by Kinder Morgan resources. And somewhat related I think ‘14 budget called for about 23% increase in coal export volume due to increased capacity along the Gulf. Is that still your expectation in light of the weak met coal pricing?

We have actually a budget of 27 million tonnes as we mentioned at the analyst meeting 25 million of that is under a long-term take or pay. And we were off slightly on tonnage in this quarter 1.3 million tonnes we were actually up $2.3 million over our plan owing to short haul payments from our customers there. We did complete one transaction at Kinder Morgan resources our first one, it was a Blue Eagle and Central App, it was 25 million tonnes acquisition -- $25 million, 25 million tonnes of proven capacity, proven reserves. First one has a very nice high-teen returns and we’re looking forward to seeing others as they progress.

And then also with regard to the BOSTCO, I was wondering how is the market for black oils right now including like micro fuel. And how have your plans evolved with regard to developing BOSTCO as you move into considering Phase 2.

We just commissioned our 49th of 51 tanks last week, it’s ramping up nice, we expect it to be completely online by the end of the second quarter. And we’re looking at a Phase 3 expansion right now. Phase 3 can go one of two ways we can look at more distilled or more black oils there. I personally believe there will be leaning towards the distillate side as we go forward. And the market seems to be very strong we’re looking at expansion and a further expansion at our Pasadena and Galena Park on the gasoline side and strong demand on distillates as well specifically on the export side.

Our next question comes from Faisel Khan with Citigroup. Your line is open.

I had just a few questions, on the broad run pipeline expansion and associated sort of infrastructure investments. What do you guys expect for the revenue contribution from that $782 million investment?

We’ve got effective mid teens unlevered rate of return on and it really comes into service in two pieces. So we have fairly low capital portion of it that will compete in 2015 but that’s a fair amount of revenue associated with that. And then the rest of it comes online in 2017. I don’t know -- I don’t think we have this specific separate number representing what that revenue after that CapEx will be that I think just used the kind of mid teens return, if you guide.

I think fair enough.

And then it’s on the CO2 business with the expansion project you guys announced how much of the 300 million cubic feet a day is for third parties versus yourself?

We’ll see how that turns out what exact mix is. We have lot of demand for it right now and we’re going to see, wait a little bit to see how that ROZ wells turnout before we make a decision on how much to sell to third party. But it will be a mix of sales to third parties and utilization to our self and that’s one of the nice position that we’re as we can kind of make that call as we’re drilling up St. John and building Lobos pipeline.

Okay, got it. And then can you give us a sense of sort of how you’re thinking about the timing on making a decision on whether - there is a potential combination for EPB into KMP?

That would be up to the two sets of independent directors, Faisel. At some point and I’ve said this all along, it probably does make sense to put two together but it’s got to be on terms that both of them agree and so we’ll see how that plays out over the remainder of this year. And again we’re going to complete dropdown to EPB that we’ve agreed on and get that done and then we’ll how see the whole thing plays out. But it will be a primarily decision of the two, the two sets of independent directors.

And the next question comes from John Edward with Credit Suisse. Your line is open.

Just a couple of questions. You’ve talked about the increase to the inventory of backlog projects and I know you sort of had inventory of identified but not put in the backlog yet at Analyst Day and I think it was something like 24.5 billion or thereabouts and I’m just wondering what changes your scene there and if you can give us kind of rough idea of where that stands?

We didn’t really update that since the Investor Conference. So I think as you saw the guidance as anything, I mean, I think we have seen stuff particularly on the GAAP sector I think pop on to the radar screen not going to the backlog, the top onto the radar screen since the conference. And I think one of the things we’ve showed in the conference that had been on the backlog, but sort of jumped from not on the horizon to the backlog with the Magnolia project for example our transport capacity off of Kinder Morgan Louisiana in support of the Magnolia project. But look I think that the trend generally -- we haven’t updated that number but the trend generally is that we’re seeing more opportunities as driven by the things that Rich was talking about infrastructure investment in North America to support all this production. And the demand side which we’re now just speaking and/or kind of on the front with appear on the GAAP side has the tendency the direction on it is to add to that project.

Okay, that’s helpful. And then just kind of following on Brad’s earlier questions on TGP. In terms of say BCF per day available for reversals, what do you have available this point and then I know you negotiate the rates but just broadly speaking about what kind of rate that does it take to ship gas on TGP now from on a reversal type project, broadly not asking to disclose your confidential rates but just kind of in broad terms if you talk about that?

I guess everything they were shipping now will be under expansion project that was going to take additional capital and create more capacity. And as I said earlier, all the low hanging fruits have been picked, so the cost of the next project will be greater than what we had to dispense due to Ontario project with broad one project. I don’t we’re done, but I think as I said earlier, I think the most cost effective next expansion that we do will actually be Marcellus project that ultimately feeds into New England as opposed coming next to Gulf Coast, but we’ll certainly look at it. And we’re seeing rates generally in market from projects out in open seasons to be somewhere approaching the dollar now from Marcellus to the Gulf Coast, so I think in general terms that’s probably a number to be thinking about.

Okay that’s helpful. So just to confirm and when you say the low hanging fruit is now gone at this point, there is not really a lot of available capacity because you haven’t spent some fairly significant dollars to do reversal, is that a correct way to interpret that?

I mean we’ve got everything under contract now to support all these expansion projects and we’re fully sold out.

Okay great and then in terms of you did mention you’ve bought back both warrant and KMI stock during the quarter. I think you said 55 million on the warrant and 84 million on the KMI stock during the quarter, so in terms of weighing those two how you’re looking that tradeoff between buying those back?

The analysis that we do is same that we described you in our quarters. During the quarter, the repurchases of stock were done first and then we completed that $150 million authorization and then you probably saw the 8-K in March where we announced $100 million authorization and we spent about 55 of that and that was all warrant repurchased.

Thank you. The last question comes from Christine Chou with Barclays. Your line is open.

Can we go over the expectation for the four-time that the EBITDA number by yearend 2014 at EPB? The Gulf LNG and Ruby asset will be coming with over $1 billion of debt and I think your budget assumes 600 million of issuances. So taking all that with the EBITDA that the drops will contribute partially offset by lower rate fund SNG and WIC. I get a number close to the 43 now just wondering if something has changed or if there is anything I’m missing.

Ruby and Gulf LNG are joint ventures and the debt will not be consolidated. We do not believe and so the four-time is without consolidation of those joint ventures.

Okay, perfect. And then just following up on the Ruby question that Brian asked and I know you’ve talked about your intent to drop Ruby into EPB, but is there possibility of selling your half on the table at all kind of similar to what happens when the other partners of Express-Platte hold our stakes?

Yes, we look at any reason probably but we’re not actively marketing it Christine. We’re in the process of dropping it down and to good long-term asset with what a good contracts that run out into the next decade. But we wouldn’t rule out any possibilities on it.

Okay great. And then can you provide us any update on the TGP abandonment process for the capacity that you would like to convert for the Y-grade line?

Yes, I can say we have not filed to seek abandonment of it. We would want to see the commercial part of this to make sure further, but we believe we worked closely with good advisors to articulate a clear path to get to abandonment. But we’re not other than sort of getting prepared we’re not at the point of filing.

And then once you, if and when you do file it’s about 9 month, is that the process?

Now we have assessed probably more, more like a year then working on.

Okay and then last one for me. This is just a broader question as we try to figure out how gas flows are going to involve in the next year or two? With respect to the NGPL reversal once the gas gets into the system from racks we should first have the option to go North or South?

On the secondary basis but on the firm basis, the path will be held down.

Okay, great. Thank you.

Okay and that’s it Holly. So we thank you very much for your questions in a good call. We think we had a good quarter and we look forward to talking to you again soon.

Thank you. This does conclude today’s conference call. You may disconnect at this time.