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

Okay, thank you Holly and welcome to everybody to our earnings call. As usual, we’ll be making statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. I’ll make some introductory remarks, then I’m going to turn it over to Steve Kean, our President and Chief Operating Officer who will talk about operations and our project backlog and then we'll go to Kim Dang, who will take you through the numbers. And I want you to treat her respectfully, because we just named her as a Member of Office of the Chairman today. So I know you will keep that in mind. Let me talk about first quarter to third quarter performance. There is really not a lot to report on the quarter or on our projections for the balance of the year. Steve and Kim will take you through it in more detail, except that we do now expect to exceed our $1.72 budget target for dividends at KMI and we expect to meet our targets at KMP, KMR and EPB. Our natural gas pipelines, particularly the inter-state portion of our group leading the year with a strong performance throughout the year. As an indication of the increased demand for transportation on our natural gas pipelines we now have new singed and pending long term contracts since December of last year, December ‘13 of 6.4 bcf/d and to put that in perspective, that’s about 9% of the total U.S. gas demand and that number, that 6.4 number is up from 5.3 at the end of second quarter. So we continue to make real progress in attaching new throughput agreements to our system. Steve will go into more detail on the operating performance across all of our segments. More significant for the future…

All right, good afternoon. So I’m going to review the business segments focusing on year-over-year performance, Q3 of last year to Q3 of this year of each one and the key developments in each segment. Starting off with gas, a very good year. KMP, their earnings before DD&A is up $53 million or 9% year-over-year and we continue to see strong performance at TGP and EPNG, as well as the assets that we picked up in the Copano acquisition. Transport volume on the KMP assets is up 10% year-over-year. At EPB the DCF is up $23 million or 8% year-over-year, really due to the dropdowns of our interest in Gulf and Ruby that were announced in April this year. The gas group added on a net basis $100 million to the project backlog. That’s after putting into service about $270 million. The biggest piece of that was the expansion of our Huston Central plant and some associated pipe expansions around that asset for about $250 million. We had a net add at TGP of about $175 million, about the same number at the mid-stream assets and those were really both associated with LNG markets, as well as Mexico, so a net add of $100 million to the backlog in the gas group. We continue to see strong demand for natural gas infrastructure as Rich mentioned. We’ve seen it in the shale’s, LNG exports and Mexico. Our assets are well positioned for all of that as evidenced by the 6.4 Bcf of signup that we’ve had. So the trends that we’ve been talking about for a long time are now turning themselves into long-term firm transport commitments. And that’s just mostly the supply side and some LNG and Mexico exports. That’s before we’ve really seen the demand side of this picture…

Thanks Steve. So starting with KMP and the GAAP income statement, you could see there today the KMP Board declared a distribution per unit of $1.40; that’s a $0.05 increase or 4% from the three months in 2013. As a result, we will declare distribution over nine months of $4.17 or an increase of 5%. Now you can see on income from continuing operations that we’re up 40%. If you want to look at it on a per share number, we are up 78%. We don’t think that these are the right numbers to focus on, because we don’t think it gives you an accurate picture of what’s going on at KMP. So if you turn to the second page and numbers, you can see that we – DCF per unit for the quarter is $1.31. That compares to the declared distribution of $1.40. So we have about 0.9, 4 times coverage about $42 million short of coverage. As we told you last quarter and we told you on almost every quarter, that we expect negative coverage in the second and the third quarter, positive coverage in the first and the fourth and for the year to have positive coverage. Now, in terms of net income per unit, when you strip out the certain items, we are at $0.57. I’ve seen a couple of notes out there that we’ve missed the consensus earnings. Let me point out that even though we don’t think earnings is the right thing, earnings per unit is the right thing to focus on. We do give you a budget every year of earnings per unit. We also provide a distribution of how that number breaks out across the year. So if you take our number of $2.57 and multiply by the percentage, you would get…

Okay. Thank you Kim and I might add that this will get a lot simpler. Hopefully by the next time we talk we’ll be one company instead of three. And with that Holly, we’ll open the floor for questions.

Thank you, sir (Operator Instructions) And the first comes from Carl Kirst with BMO. Your line is open.

Hey Carl, how are you doing? Carl Kirst – BMO Capital Markets:

Okay, I think we continue to pursue this project, because we continue to see very strong interest in it and each period that we go out to survey the field and survey the market, it seems like we generate more interest from the period prior. But we haven’t been able to turn that into sufficient credit worthy country party commitments to carry the project through and allow us to put it on a backlog and actively pursue its development. Well, we are actively pursuing its development, so the kind of the reset that we’ve done Carl is to say, what does the market really need out there. We think the market really needs about 2018 in service day and there has been a lot of talk for a while about 2017. There doesn’t seem to be much harm in the 2018 in-service date and so we’ve adjusted our spend and our development work. That moves us to 2018 in service, but it allows us to continue the development of the project at a lower coast as we pursue abandonment on the Tennessee Gas Pipeline System. So I think the short answer is it still looks like a very viable project. We are still working it very hard. We found a way to continue to develop the project as the market matures into it and that’s what we expect to happen. We do as you pointed out, always have the option of going to a Southbound Tennessee hall. It’s not a large amount of capacity that this line represents and so I think it’s a much more attractive opportunity for us as a company to pursue the Y-Grade line and so we’ll continue to do that unit its apparent that there is not going to be sufficient commitments coming forward. We think it’s the best long term, most efficient solution for the customers out there and we are counting on them realizing it at some point here. Carl Kirst – BMO Capital Markets: Great and I appreciate the color and maybe just one other question. Looking at New England, I think obviously a very big potential project. Correct me if I’m wrong. My recollection is that at least on the market piece, the LDCs have signed up for roughly 0.5 Bcf/d and you all were just in filing for Maine and I guess depending on if they bite that might be something that could potentially push you over the commercial transom. And my question is how long do you think that process takes for the state of Maine to evaluate that satiation. Is this a first quarter, second quarter ’15, just any kind of zip code you might have.

Well Carl, this is Rich. Its complicated a bit by the fact that the Chairman is leaving at the of the year. That said, there seems to be a great deal of interest by the State of Maine in pursuing this project and we are working with them and pushing them to get a decision just as quickly as we can. We are working there towards critical mass. We haven’t put it in the backlog yet and won’t until we get that critical mass. We are working with a number of customers for additional capacity and that project again looks just certainly something that’s needed for New England and we are also looking very seriously at our ability to reroute certain parts of that to obviate some of the uproar we’ve had in the Berkshires about where our pipeline is running. We think we found solutions to rout the great bulk of it along the light of way, which would not be as disturbing as the original plan was. We think the original plan took into account the needs and issues with the potential neighbors, but we are going back to drawing board a bit on that and we’ll be looking. We haven’t filed the final rout yet. We’ll be looking to do that as we move forward. So that’s a project that again we continue to move forward on, but we obviously have to see the critical mass before we put that in the backlog and announce it as a definite go project. Carl Kirst – BMO Capital Markets: Understood. Those are my questions and meant to pass on my congrats to Kim, so I’ll do that now.

Thanks Carl.

Thank you, Carl.

Thank you and the next question is from Ted Durbin with Goldman Sachs. Your line is open.

Hey Ted, how are you?

Hey Rich, I’m doing well thanks. Maybe just start with the moving oil prices here and can you give us an update on where your hedge percentages are as we look out for the next one to three years. And maybe also sensitivity analysis on say $1 move in oil prices. How will that impact DCF for 2015?

Okay, so for 2015 right now we have about 64% hedged at a price of 90.53, 2016 we are 46% hedged, a price of 85.86; for 2017 we are 33% hedged at a price of 83.14 and for 2017 we are 17% hedged at 83.80. By the time we get to the end of this year, the beginning of next year, we would expect to be about 80% hedged on 2015, which would leave our sensitivity similar to what it has been in prior years of about $7 million in DCF per dollar change in the barrel of oil.

Great. That’s very helpful thanks. Next question is just on the shareholder vote here. Maybe its sounds like its been delayed a little bit more than what we have thought it was going to be, anything there? And then as you talk to the KMP unit holders in particular, where is your level of confidence in terms of getting that majority vote you need.

Well, let me say first of all, its not delayed. We said sometime late in the fourth quarter. We would be happen if we can say we are hopeful. We are moving it forward to get it ready for Thanksgiving. And I’m going to turn it over to David Michaels. David, you want to take them through the analysis of the KMP unit holders.

Hey Ted. The way to remind you, the way with the KMR voters, shareholders will be able to direct their I-units (ph) to vote in the KMP unit holder vote. So that represents about 28% of the total KMP unit quarter base and if you break it down and use some reasonable estimates on how institutional KMR holders will vote and how KMR retail holders will vote, we think that that will represent about 22% of KMPs votes. If you add on top of that KMP insider votes and KMIs ownership of KMP that gets you to about 30% of the total votes that we think is reasonably assured vote for the transactions. That would leave us with about 97 million units needed to get us to the 51% level and that’s 97 million units out of about 300 million units remaining outside of those contingencies that we just walked through. And of the 297 million that remain, and we need 97 million out of, 90 million of those are institutional owners and we think that those are going to turn out overwhelmingly in favor of the transactions. We feel pretty comfortable that we’re going to be able to get there, but we are not taking it for granted. We are going through a very thorough proxy solicitation process once the S-4 is deemed effective.

Very, very helpful. Thank you for the detail. And then if I can get one more in, obviously you had a sort of big sell off in kind of the market here, including some of the mid-stream assets. I’m just wondering if you are seeing any even better opportunities potentially out there now, given some of the asset values maybe a little lower than where they were before.

I think in the long run if there’s a potential, possibly for it to be beneficial in exactly that way, but its certainly too early to predict. You guys see where this thing settles out and of course the mid-stream sector rallied pretty nicely this afternoon and KMI was up about I guess close to 3% or 2.5% as were a number of other energies. So we’ll just have to see where it is, but certainly I think in the long run the outcome of this will be asset values might change a bit, that would give an opportunity for a company like Kinder Morgan to link more acquisitions.

Okay. Thank you very much. I’ll leave it at that.

Thank you, Ted.

Thank you. Our next question comes from Shneur Gershuni with UBS. Your line is open.

Good afternoon.

Hi, good afternoon everyone and congratulations Kim. I was just wondering if you can sort of take a step back from specifically talking about micro issues with KMI. As Ted just mentioned, the markets been challenging in the last few weeks. We had this big decline in oil and just we’ve seen these steep declines in the past. I was wondering if you can sort of walk us through the discussion process that you have with producers before you start the contingent process. Talk us through maybe how they think about short term pricing trends versus long term pricing trends as they establish their CapEx and how they come to you in terms of how you provide solutions in terms of resolving bottlenecks and so forth, and how we should be thinking about CapEx given the short term volatility that we’ve seen.

Well, first of all of course we are talking about a broad range of projects here ranging from CO2 supply contracts on one hand to natural gas and products pipeline projects on the other. With regard to most of our mid-stream pipeline issues, we don’t see much change as a result of lower prices. In fact you could make in contrary an argument that a lower deck of prices on crude and NGLs will have a positive effect on people ramping up petrochemical usage in the months and years to come. So I don’t think that’s a negative on our ability to as you put it, get around these bottlenecks and resolve the issues and clearly so much of it now as Steve pointed out is returning to demand pull for this; the ONG users, the petrochemical users and other users, other users from the demand side. Now I think it’s a different issue on the CO2 side and there we’ve looked very carefully at what we think are sort of clearing prices and this is going to vary widely with who the producer is and what needs they have, but let me start by saying that we have floors on the great bulk of our contracts. So while there is some movement up and down with the oil and that’s part of the $7 million per $1 that Kim was referring to, we do have floors across the board on that. If you then look at, well what does it really take in the Permian Basin for people to longer drill, we think from the standpoint of a flood that’s already going, just incremental CO2, to expand the flood is probably in the $40 to $45 range. We think for instituting a new flood in the Permian Basin and this is based on our own experience at SACROC, we think its probably closer to $60. Now let me say it again, that’s going to vary with the acreage; that’s going to vary with the producer, but what it says to us is that CO2 floods are certainly economic at prices well below where the current price of oil is and so that’s I think certainly something that we will watch very carefully on a going forward basis, both on the S&T side of our CO2 operation and obviously on the OR side. But so far this is not a big issue for us in terms of what’s moving forward with our projects in our view at this time.

Thank you Rich for that perspective. Just two quick follow-up questions. You sort of talked about the closing of your shadow backlog to backlog in the prepared remarks. I was wondering if you can sort of give us a sense of maybe shadow backlogs today with incremental projects added to the shadow backlog or do they just buy what’s beneath the cross.

Yes. I mean if you look at the projects that I mentioned as I went through each of the business units and just added all those up, on an ADH basis that’s about $15 million to $16 million, actually probably $15 billion to $17 billion when you take the ranges into account and that included Palmetto, the Y-grade line, NEB, one other one, what’s that?

Yes, Gulf LNG.

Yes. So I think that’s a substantial part of it. Some of this will have some overlap, but I think in the gas curve we about an $18 billion, a shadow backlog that will double up on NEB and Gulf LNG in that respect. So there are a lot of projects out there that we’re pursuing and they have some reasonably probability associated with them. Its just that they are not high enough probability for us to call them sort of near sure things. But that’s the order of magnitude and we continue to – those are some of the big ones, the four that I called out are some of the big ones. There’s a lot of smaller projects in the terminal sector, things in CO2 that we’re looking at, the products pipeline, there continues to be a number of projects for build out there. So again, I think the environment is just very good for us and I think we are very close to turning a couple more of those on the backlog, moving them from one to the other, but just didn’t quite get there this quarter, but I think may make some progress here in the coming quarter.

Okay. And one last final question if I may. You certainly talked about contract renewals at the beginning all on gas lines. Have you seen any trends towards producers who are going to take the longer-term contract renewals versus what typically would do on a renewal. Is there sort of any lengthening that’s going on, as well as are you seeing that from a pricing perspective.

Yes, I’ll turn it to Tom Martin for that.

Yes, we definitely are. I mean I think you have to look at it on a regional basis, but clearly the activity that we are seeing out west on the AT&G, we are seeing both producers and end users stepping into longer term agreements on existing capacity and also sponsoring expansion projects. Certainly Tennessee Gas we’re seeing much of that driver to this point being producer orientated, both on existing capacity and on expansion capacity. But I think really not to say that that’s part of the expansion and growth we’ve seen in there, but we’re certainly seeing a shift towards more on the market side now going forward than what we had seen over say the last year to year and a half and I think evidenced by really the last two quarters of all projects being sponsored predominantly more on the market side, in LNG as well as Mexico Exports and I think we’ll start to see power and industrial expansion related projects in the coming quarter.

Yes and sort of the symbolic of that is what we announced yesterday afternoon. We have two new projects on the gas group side. 500 a day going to – I still want to call it MGI, its Mixed Gas now, long-term contract. That’s on top of – in excess of 500 a day that we signed up several months ago. So that’s a little over $1 billion a day going into Mexico on long term contracts, just to cross our systems and then we also announced yesterday, associated with that on that Lone Star project another 300 a day, which we have an end user signed up for that capacity and in fact that may even be at large just as we go through the open season, but what we announced yesterday was just that we would perceive with the 300, we have enough to make it a valid project. So that’s the kind of end user demand we are seeing and its definitely linking the terms. I think we are even seeing people as capacity comes up and an open – on the bid situation where they have a low for, they now have to bid longer term in order to protect that capacity. People are saying I think that this capacity in general is only going to get more valuable as time goes on, as all these demand side projects come online.

Great. Thank you very much for that perspective guys and have a great day.

Thank you and our next question comes from Mark Reichman with Simmons & Co. Your line is open.

Hi Mark. How are you? Mark Reichman - Simmons & Co.: Good, good, thank you. See with respect to the announced expansions at Pasadena and Galena Park, I was just wondering how you think about export opportunities in general in order with the LPGs, with iron products and even process comments. So I mean as you serve a existing storage and loading capacity, where do you think opportunities remain unfulfilled and also in light of a number of international refinery additions that are designed to yield ultra low sulfur diesel for export, how deep is the market? Do you think they’ll accept growing our fine products exports from the US?

We’re right in the middle of all of that and what we announced yesterday certainly involves that area Steve.

Yes, so what we announced yesterday has significant tank expansion underwritten with some newly executed contracts from one shipper in particular and we had some previously executed contract and also includes an expansion of a ship dock to get out exactly what your talking about. I’m not sure that I can give you better numbers than what you can read other places in terms of what the demand is going to be for additional export capacity, but what I can tell you is that we are seeing people increasingly interested in capacity that they can get to a dock line and we have perhaps the biggest refined products storage position on the Houston Ship Channel and the combination of our Pasadena and Galena Park facilities and with some expansion at Bosco as well and we are expanding ship docks and we are expanding barge docks throughout that complex. So there is a lot of demand for that. We’ve got on a smaller scale a project that we are looking at in our Fairless Hills Terminal in the Philadelphia area that would involve LPG export and I think those are the two big locations that your going to see the demand. You’re going to see in the Houston Ship Channel. We’ve got all that refined product capacity and a little bit on the North East where people are looking for ways to get the liquids product out of the Marcellus and Utica to overseas markets. So what that aggregate number turns out to be, I don’t know, but we didn’t use to charge for or be able to charge for access to our docks and now we are charging for access to our docks and it is an extremely valuable bridge between the inter United States and the world market for refined products. So demand is going up. How far up it goes, who knows, but we base our judgments on what shippers are willing to commit to and we are seeing an up-tick in those commitments.

And I think right now and frankly I haven’t updates these numbers this quarter, but I think we believe we are handling something between a quarter and a third of all the refined products exported across the Houston and Belmont area. And then I think its also instructed that this storage is just so important and growing so dramatically and to put some numbers to that. I believe with this project that we announced yesterday on internals, I think that when completed will take the Galena Park project that combined Pasadena, Galena Park project over 30 million barrels of storage and if you add up everything we’ve got on the Houston Ship Channel, I think when that’s completed we’ll be slightly over 40 million barrels of storage. So that’s a really tremendous position to be in when you have the kind of need for export, the need for avoiding volatility and pricing. We think this storage is just going to be more and more valuable and we’re seeing that in the market. Mark Reichman - Simmons & Co.: Great. Thank you very much.

Next question from Darren Horowitz with Raymond James & Associates. Your line is open.

Hi Darren, how are you? Darren Horowitz - Raymond James & Associates: Hey fine. Thanks Rich. Hope your doing well and Kim, congratulations on the appointment to the office of the Chairman. Just a couple of quick questions. The first, on TGP when I’m thinking about broad run and the associated expansions you laid out, post anterior anchor commitment, if I start thinking about Rose Lake in Connecticut and the other initiatives that your working, is it fair to assume that there is going to be at lease to be, if not 1.2 bcf a day that could be hitting that West Virginia receive point and moving down to those delivery points in Mississippi and Louisiana. Because in looking at basis, specifically Tech OM2 and Dominion South and Olivia (ph), it would like that’s probably one of the biggest areas for you guys to invest incremental capital.

Yes, I mean I think we have started taking a look at what our next big project would be. I think it really boils down to what is the clearing price in the market for an incremental expansion, but I think there’s more volume that wants to move southbound. We are seeing some customer interests and diversify some into Canada and saw we one other project announced yesterday into Chicago. So I think customers are looking at our portfolio approach, but I think as I’ve said in other quarters, I think from our perspective we are needing a market-playing price north of $1 I think to the incremental projects to the Gulf Coast. At least the initial feedback we’re getting at this point is as I said, probably still a little bit on the high side. Darren Horowitz - Raymond James & Associates: Okay. And then Rich, if I could go back to an earlier comment that you made regarding the northeast energy direct project and rerouting that or moving along the existing rights away, is that the variance between the original cost estimates that you outlined of $6 billion and the new forecast of $4.5 billion to $5 billion or has there been any change to the scale or the scope of either Phase I or the second phase initiative into Massachusetts?

No, there really hasn’t. We just kind of refined the costs and got it to a more likely area of what we think the spin would actually be in the $4.5 billion to $5 billion as a result of that, kind of pinning down where we think the real construction will come out. Actually the rerouting would be an increased cost as part of that, something in that same range, but would be a net increase, because we have a few models of pipe. But on the other hand we would avoid most of the section 97 land in Massachusetts and just be largely along the utility write away. But we are still looking at that and we’re in the midst of doing that. Darren Horowitz - Raymond James & Associates: Okay. And then last question from me Steve, regarding CO2, if you could, could you quantify what that current Midland-to-Cushing differential could have on annual cash flow if it stayed at this level. I’m just trying to get an idea for the sensitivity for every dollar per barrel moving that spread.

Yes, I don’t really have a sensitivity for you for that. I can tell you that we’ve been actively putting hedges on for 2015 at levels that are, call it $4 better than what your seeing in the current market right now. Darren Horowitz - Raymond James & Associates: Okay. Thank you very much. I appreciate it.

Thank you Darren.

Next is Craig Shere with Tuohy Brothers. Your line is open.

Thanks.

Hi, how are you doing?

Very good. Thanks Rich and congrats Kim. A couple of quick ones here; does the $2 billion effect of quarterly increase in your gross backlog favorably impact I believe your just over 9% combined enterprise EBITDA, five-year tagger (ph) through 2020 that was noted in your S1. I’m just trying to see what’s baked in that and where do we start getting incremental?

Kim.

No, I think that backlog is – we actually still have some unidentified in that five year plan. Obviously that eats away at that, but it’s not going to be incremental at this point to the 9% growth.

Okay. Once we start getting through the backlog that was included in that guidance, if you guys can give us a heads up at anything new that is incremental, that would be great.

Sure.

We’ll do that.

And can you provide some more color around the continued growth in SACROC. You kind of referred to it, but not much detail and also the Yates NGL flooding time set and the latest ROZ updates.

I’ll turn that over to Jim Wuerth. He runs our CO2 operation. Jim?

Yes, in SACROC I guess three main areas that we’ve had real good success with the horizontal wells that we are using as the injectors of CO2, we are getting good response from those. So the bypass wells that we kind of talked about in the past, it looked like that’s going to be a real good outcome for SACROC, so that’s one. Two, with the seismic we have, initially I think we said we’d have about five or six pinch out wells that we’d be able to identify in infields and drill. We drilled 22 of those now. I think those are running about 1,100 barrels a day higher than we had anticipated. We have several more of those identified as the seismic prophecy continues to get better. The other area I think just (inaudible) infields, we’ve done a couple of those. We’ve been very encouraged with that, with one of them starting out close to 700 barrels a day. Back early in the year still producing 400 barrels a day. The second one coming on is over 400 barrels a day, so a lot of opportunities there. We continue to look at fringe areas. We know we got few more programs out there that are up in the platform where we’ll add on some there and around some differences around the, both the east and the west side of SACROC. So just continue that opportunities at SACROC that we are finding there and I think we’ll continue to find more as we go forward. At Yates on the hydrocarbon municipal we had – the good and the bad news there is we thought we’d have a test, putting some NGLs down into the gas cap in the third quarter. The problem we had is we needed a baseline and we got the first well we picked. The first oil there we are producing, its currently still producing about 350 barrels a day on it. So what that has done its opened up another opportunity for us to look at this purchased oil and we are doing that. We are taking some wells in there and actually perping and picking up some of those purchased oil. So I guess its a great opportunity there. I think now we have identified a couple of wells where the well bore integrity is really good. We think we can get the base line fairly quickly. We hope to do the injection of the NGLs in the fourth quarter.

We will see some results coming in.

On the ROZ, I’d like to continue on the ROZ. We have 10 other wells drilled at this point in time, facilities that are going in. We would still expect bringing the actually injection a little bit forward. We are hopping to start injecting by November 15 and we’d have all in production facilities up and running to go by late December. They will handle any gas or fluid that come out the other side. So we would expect to see some results on this by the end of first quarter 2015.

Okay, and the final results here on the NGL flooding. Is that a first half event?

On the NGL flooding we have not even had a chance to flood it yet. That’s why I said that will be fourth quarter in this year.

Okay. Thanks a lot.

John Edward with Credit Suisse. Your line is open.

Hey John, how are you doing?

Good afternoon Rich. Doing well and I also want to say congrats to Kim as well. So just – maybe I missed it, but what’s your sort of range, your total shadow backlog right now?

Well, I think Steve said when you get into the shadow backlog John, its very difficult to identify it, but I think the number he said was $15 billion to $17 billion.

Yes, that was just the projects that I mentioned. A different way of looking at it is if you look in the gas group alone its $18 billion. I don’t think we’ve calculated or identified a specific one for each of the other business units though John, so I mean its got to be 20 plus, but we haven’t articulated that.

Okay. So $18 billion in the gas group alone, but the $15 billion to $17 billion…

That included some of the gas projects John. So, I mean if you wanted to look at $18 billion in gas and then look at the non-gas projects, that would be another $1.1 billion or so, 88s on the Palmetto project and then the Y-Grade project is, call it a little over $3 billion. And again, those are 88s numbers. Don’t take into account if we ended up – we don’t have one today, but if we ended up with JV Partners on those. So that’s another $4 billion-plus on top on Tom’s $18 billion and that’s just in the products group and we haven’t – again, we have not gone out and calculated and compiled a shadow backlog for Terminals for example or even full done one for products. So we kind of sum it up. The prospects are very good and we’ll go knock these things down when they get in front of us and go from there.

So if I add that, I could characterize it as a round number, something like call it $20 billion to $24 billion of shadow.

I mean I would say north of $20 billion you know. I don’t know how far north, okay.

All right, just kind of helps us to think about that. And then so, I mean you sort of answered this earlier, but so in light of all the volatility in the market, you are not really seeing anybody. You are not really seeing this impact, your discussions on potential projects or impact interest in terms of yield future going forward. You are not really seeing any delays or deferrals or anything like that given the market volatility.

We are not seeing that thus far.

And to Rich’s point earlier, it doesn’t mean that you won’t see some of that on the producer side, some harder hit producers maybe. But lower prices are going to be very bullish for the demand side, which is where we still have – we have to see the full needs come to market to sign up for the firm, transport and storage commitments that they are going to need to serve in.

Okay, that’s very helpful. And as far as when you consolidate close and everything, the guidance that you’ve put out there is basically 16% dividend growth in 2015, 10% thereafter and I think you premised that on just roughly $3.5 billion spend per year. So assuming some of these shadow projects become a reality, so that effectively you are saying there is potentially upside to those numbers, is that a fair characterization?

The $3.6 billion per year did not include Trans Mountain. You got to add that on to get to your total.

But I think you can see from all these projects John, that’s why we are comfortable with thinking that that level of capital expenditure, which is pretty consistent as well with anything is certainly attainable and if anything you know that as I said in the beginning of my remarks, we’re seeing some of the opportunities (inaudible) infrastructure are better than they – they keep getting better. Now I think Steve and Tom and I have all said, we can’t predict the future and there maybe some impact on particularly some of the smaller producers. We have not seen that yet, but certainly we think the demand is going to be the big driver in the future and they actually improve as a result of lower prices, if indeed the prices stay low and certainly what we saw in the natural gas side.

Okay. And then just lastly sir, and you’re still thinking sort of 5 to 5.5 times leverage for the consolidated entity; I mean at least for 2020 or so that’s still the plan.

Yes.

Okay, great. That’s all I had, thank you very much.

Thank you John.

Next question is from Becca Followill with U.S. Capital Advisors. Your line is open.

Hi Becca, how are you?

I’m good, thank you. Better this afternoon than I have been in the last couple of days. Can you talk about just on – back on Trans Mountain, The Burnaby issues and the latest route to tunnel under the mountain and the delays; does it have any impact on the cost estimate at this point?

Ian Anderson, President of Kinder Morgan Canada is in the room, Ian.

Yes, no Bec, its not going to have a material cost impact from the overall project whatsoever. A little bit more spending up front to do the assessment of the geology of the mountain, but its not significant.

Great, thank you. And then there’s been an amazing number of new pipeline announcements just in the last six months and when we look at the last build out cycle we had in ’08, ’09 there was a lot of cost over runs. How are you guys planning differently in this cycle given kind of what we went through in the last time in a number of announcements.

Yes, now that’s a very good question Becca. I think first of all we are looking very, very carefully at our cost in terms of escalation, both of materials, but more importantly putting into our estimate adequate cost escalation of a labor side. I think that’s extremely important. If you look across our business units right now, on all the projects we are working on, Steve kind of alluded to this, actually products on all the projects that they are working on is actually running about 1.5% below the original estimates. Natural gas is right on. CO2 is right on and the only place we’ve had overruns is on Terminals, primarily some of our Canada projects and that’s between 6% to 7% over run. So we have not seen any dramatic issues thus far. The second thing that’s important about just really watching and getting your estimates right is trying to get a sharing mechanism with your shippers on some of the more inflation prone areas. For example, on the Trans Mountain we have some sharing arrangements on construction costs in the lower Mainland, this Burnaby would be an example of that. We have some sharing costs on the cost of First Nations involvement and that’s what we are trying to build in in various projects. There is nothing perfect here and its something that I think is going to be a challenge to the industry and the industry is going to have to watch it very, very carefully.

Can you say what escalators you have built in?

It varies with the project and specifically with the geographic location. Obviously you build in the higher escalators in geographic areas where you don’t have access to as many competitors in a particular subcontracting area. So it varies all over the longer part, but we think we are building in adequate incremental numbers as we go forward.

Thanks and then the last question is just on this SFPP settlement. Does this finally put to bed all of this long-standing litigation?

It does we think. It has to be approved by the CPUC. They fast-tracked it and we expect it will be approved, but obviously it has to be approved by the commission. Yes, it does, and in fact we have a three-year moratorium on rates on the SFPP system on the CPUC portion of the intra-state portion. So yes, we think that does put it to bed and as we said in the press release, I think we detailed, the details out really.

So we can take 10 pages out of the 10-K then.

I certainly hope so Becca; that’s a good catch.

Right. Thank you.

Thank you.

Thank you and our last question comes from Jeremy Tonet with JP Morgan. Your line is open.

Hi Jeremy, how are you?

Hi, great and my congratulations as well to Kim. At the risk of getting ahead of myself a bit here, I was just wondering if you could provide us kind of an M&N wish list in terms of what areas of midstream you’d like to expand into. Well, I guess the question is it seems on the Nat Gas Pipeline side, I imagine you might run-up into antitrust considerations. I’m just wondering what are the parts of midstream you might want to spend in more. Just any color that you’d be willing to share would be great.

I think the color we would be willing to share is we are looking at all realistic opportunities across the spectrum in all of the businesses that we are in.

That makes sense. Fair enough. Figured I’d try, thanks.

Okay, well that looks like that’s the last question. Thank you all very much and have a good evening and we appreciate you spending the last hour and a half with us.

Thank you. This does conclude the conference. You may disconnect at this time.