Kinder Morgan, Inc. (KMI) Q4 2013 Earnings Report, Transcript and Summary

Welcome to the Kinder Morgan Quarterly Earnings Conference Call. [Operator Instructions] Today's conference is also being recorded. If anyone has any objections, you may disconnect. [Operator Instructions] And I would now like to turn the call over to Rich Kinder, Chairman and CEO of Kinder Morgan. You may begin, sir.

Okay. Thank you, Holly. Welcome to the Kinder Morgan Analyst Call. We'll be discussing Kinder Morgan, Inc., which I'll refer to as KMI; Kinder Morgan Energy Partners, referred to as KMP; and El Paso Pipeline Partners, referred to as EPB. As usual, we're likely to make statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. I'll do an overview of the results and recent developments, as Steve Kean, our Chief Operating Officer, will give the details of business segment performance and discuss our backlog of future projects; and Kim Dang, our CFO, will go through the financial details for both the fourth quarter and full year 2013; and then we'll take any questions you may have. And let me start with KMP. We raised the quarterly distribution on KMP to $1.36 for the full year 2013. We declared $5.33 in distributions. That's up 7% compared to 2012 and 5% above our original plan for 2014 of $5.28. Our full year DCF per unit, which we believe is an important way of measuring our success, was $5.39, up 6% from a year ago. Indicating how strong our performance at KMP was, our total DCF was up 28% for the fourth quarter and 26% for the full year. Segment earnings before DD&A was up 22% for the quarter and 27% for full year 2013. Steve will discuss the drivers of this growth, but overall, we were pleased with the performance of all 5 business segments. But I think particularly noteworthy were the integration of the Copano and El Paso assets in our Natural Gas group, a nice increase in refined products volumes at our Products Pipelines group and increased oil and NGL production in our CO2 segment, particularly at our SACROC Unit. I'm also…

All right. Thanks, Rich. I'm going to start with the project backlog. As Rich mentioned, we've been updating this backlog, really, starting with the investor conference in January of 2013 and intend to do it probably quarterly going forward. In the fourth quarter, the backlog increased from $14.4 billion to $14.8 billion, and this is a combined KMP and EPB look. And we had that increase even though we had over $900 million worth of capital projects go into service and come off the backlog during the quarter. So the project additions grew the total backlog while offsetting the projects that went into service. The larger projects that went into service were on our TGP system, both the Northeast Upgrade Project and the Marcellus Pooling Point Project, as well as some export coal terminal facility expansions in our Terminals business segment. Now a few facts about how we put this backlog together. First, it's made up of those projects that we are highly confident will get done. Not guaranteed, but highly confident, high probability. We would expect to actually do more projects and invest more capital than what we have in the backlog, but until we consider project highly probable, we don't add it in. So, for example, we don't have in the backlog our current joint venture Y-Grade project from Pennsylvania to Texas. We believe that project is very attractive as a solution for producers in the Utica and Marcellus. And we're actively marketing it, but we won't put it in the backlog until we see strong indications of commitments coming through. Now the business unit by business unit composition and change in the backlog is as follows: the gas group went down in the quarter from $2.9 billion to $2.7 billion. That's because we had over $500 million…

Okay. Thanks, Steve. Just going through the numbers. Looking at the first page of numbers in the KMP press release is our GAAP income statement, and on that, you can see the declared distribution today of $1.36, which results in a distribution of $5.33 for the year. I'm going to turn to the second page and walk you through our calculation of distributable cash flow and the drivers of the growth. That distributable cash flow is reconciled to the GAAP numbers on the first page. The $1.36 -- we generated DCF per unit, as Rich said, of $1.44, which was up 7% versus the $1.36 distribution. That resulted in $36 million of coverage in the quarter, consistent with what I told you last quarter. We expect to have positive coverage in the fourth quarter. We also have positive coverage for the year. For the year, distributable cash flow per unit was $5.39, up 6%, versus our declared distribution of $5.33. That's $22 million in excess coverage for the year. That comes in just slightly below our budget, $12 million below our budget of $34 million in coverage. Total DCF, $635 million in the quarter. That's up $140 million or 28% versus the fourth quarter a year ago. And just to walk you through the pieces of that. The segments are up $279 million or 22%, with approximately 70% of that $279 million or about $191 million of the increase coming out of the Gas group for the reasons that Steve mentioned. $55 million is the growth in CO2; $27 million in Products; $23 million in Terminals. And then as Steve said, Kinder Morgan was down for the quarter, about $17 million due to the Express sale and book taxes. Now as you know, book taxes have no impact on our…

All right. And with that, Holly, if you want to come back on and open the line for questions for us.

[Operator Instructions] And the first question comes from Darren Horowitz with Raymond James. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Two quick questions from me. The first, and I recognize you're going to provide a lot more detail at the Analyst Day in a few weeks, but I'd like just your macro thoughts on the downstream expansion or repurposing opportunities on KMCC. And I know that you've got that lateral in Gonzales County, so that gives you access to the ship channel. And also, the joint venture with Magellan gets you there, as well as Corpus. And Steve provided a lot of detail, which we appreciate on all those terminal expansions, but when you think about the overall demand pull that drives the export of higher-end dis/splits [distribution and splits] and gas/oil to areas like Latin America, let's just say, if you could just outline the opportunity set and required capital that might be necessary in order to meet that demand beyond 2015, that would be helpful.

Well, first of all, from a macro standpoint, of course, we continue to extend KMCC outward into the Eagle Ford. And one of the benefits of the Copano acquisition was the ability to connect KMCC to Double Eagle. And so we can now provide a producer with optionality. He can connect and either go all the way to the Houston Ship Channel on KMCC, or if he's in the right place, go down Double Eagle to Corpus. So that's our initial contribution to moving the condensate around. Obviously, I agree with you that the export of refined products is increasingly in vogue. We're handling a fair percentage now that -- in all of our assets along the Houston Ship Channel, and we will continue to expand that by more connectivity, by more berths that we are building and by more storage capabilities. For example, in conjunction with the splitter, which is an outgrowth of KMCC in which we are investing about $360 million per 100,000 barrel splitter that's fully subscribed by BP. We're building 2 sets of new tanks for that. And that will facilitate the ability to move the split product out. It's not refined products, but it will facilitate that ability. So I think we're pretty much on top of it, given all the connectivity we have. And I think we'll be able to continue to benefit from what we see as a significant trend. Steve, anything else on that?

Yes, I mean, the KMCC right now is about 2/3 full under contract, so there's more room for shippers to get in there. As Rich mentioned, that's interconnecting with Double Eagle, so there's really kind of a network down there right now, connecting either Corpus or the Houston Ship Channel. And then, in connection with the splitter project, we're putting in 3 new cross-channel lines between Galena Park and Pasadena, adding to the existing cross channel lines we have there, about 5, I think.

Six.

Six, okay. And with BOSTCO, we're adding ship docks, adding 12 barge berths, looking at the potential to connect Pasadena and Galena Park with BOSTCO. All those things, it's very hard, Darren, to say well, how much total capital we have put to work there. It's really a question of how much growth there is. It looks like there's going to be a lot, and what customers sign up for. But we're very happy with the network that we've got and its expandability. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Right. I appreciate that. And Steve, last question, I just want to go back to the comments that you made about TGP's open season for that backhaul capacity out of the Northeast. I know that you said in the prepared comments you're looking at additional expansions there, but can you just give us an idea, as you're looking at basis differentials and talking with producers, what you think the scale and scope necessary to meet the production profile to get incremental gas to the Gulf Coast could be? Because it seems like recognizing you're not going to build it before commitments are signed, but it seems like it could be significantly larger than existing capacity in the ground.

That's -- we believe that is absolutely true, and so we're out talking to the market right now about another potential expansion. I'm sure others are as well. It may have as much to do with how much gets expanded into New England, so how much of the gas ends up going that direction or into the Northeast, generally. But we were, I guess maybe some people said they weren't surprised, I was surprised. And it was a very strong open season and it has prompted us to start very quickly on the next round. And I think we just have to see whether the first ones are cheaper, the next ones are more expensive. We have to see if the customers are there for a higher price point. And they may not be immediately, it may take some time and some build up and some ramp-up in production in the Utica for people to really get a sense of what they have, but we expect there's more to come. Tom, do you want to add anything to that?

Yes, I mean, I think the kind of [indiscernible] that we're doing out there which is [Audio Gap] excess of a bcf, maybe closer to 2 Bcf. [Audio Gap] Not all that is something we'll get, but I think it's certainly a representation of what kind of scale is out there, and we're certainly [Audio Gap] option that we have to head back to the Gulf Coast and/or take it to the [Audio Gap]

Look, what's happening is that the production of Marcellus and Utica is, all of you on this call know, is so huge, that while there is need for more connectivity into the Northeast, particularly New England, the amount of production there has, is in the process, and has already, in some respects, swamped the demand that can be sucked up by the Northeast. And so lines like Tennessee are obviously going to become, in some respects, bifurcated lines, they're going to move a huge chunk of gas downstream from the producing areas of Marcellus and Utica in to the North. And then, as we found in this open season, we're going to move a lot of gas south, to where we think the huge demand is going to be, down here along the Gulf Coast, with all the new downstream facilities being built. So I think it's a very good opportunity for us. The caution would be that obviously, as Steve said, that the cheapest expansability [ph], the low-hanging fruit is always the first one. And that's why I think we were so tremendously oversubscribed in the open season. But now we're working to see what the next level of demand is, and I think we'll capture some of it. Certainly, others will capture some, too.

The next question comes from Brian Zarahn with Barclays.

First question is on the long-term distribution growth guidance. Is that unchanged with 9%, 10% of KMI, 5% to 6% KMP and EPB? And is that from a full year 2012 base?

Right now, we're going to be able to give you more of an update on that. We're, right now, that's certainly the last -- the guidance we've given and we've talked about that, the 5% to 6% of KMP and 9% to 10% at KMI. And now, in preparation for the conference in a couple of weeks, we're now updating that and extending it, Kim, out through 2018. So we'll have an update, we haven't even completed running those numbers, but that will give you, horseshoes and hand grenades, look, from '14 out through '18 and we'll have it for you at the conference.

Okay, we'll stay tuned on that. On drop downs, what are your thoughts regarding FGT, previously you mentioned that would dropped this year, it seems like it's going to stay a little bit longer at KMI, so any color around the ownership of FGT long term?

Right now, we're keeping it -- we've budgeted for the year staying up at KMI. We're just going to continue to look at it. We're going to drop the 2 other assets to EPB this year. And we just haven't made a decision on when we -- [Audio Gap]

Okay. And on the marine transportation acquisition, can you provide some color on to the strategy and expanding to that business, and about the timing of the EBITDA ramp-up from the $55 million now to, I guess, to the $140 million or so you're expecting?

Happy to. I think some people looked at that as this was a big step out for us. And although I think most people saw through as to what our real reasoning is, but let me just take you through it. We're in the midstream transportation business, and the greatest single opportunity, and why, in my roughly 35 years in this business, this the most interesting time we've had, is we have all this tremendous increased production coming from areas, and this is true of across the board, whether you're talking about crude oil, natural gas, condensate or indirectly, even refined products. We have a tremendous need to transport that from new production areas to market areas. And there are a lot of ways of moving it, and we're primarily a pipeline company, of course. And so, the cheapest, most effective, long-term way of moving with all these products, is by pipeline. That said, and we've discussed this before, there are a lot of reasons. Some of it is infrastructure not being built on a timely basis or permitting delays. Some of it is optionality that producers or others want. But there are reasons why pipelines don't satisfy everybody's need. An outgrowth to that is obviously crude by rail. Another outgrowth of that is the Jones Act. And that's why we are pretty bullish on this area. If you think about it, if you're talking about moving crude oil, for example, from the Eagle Ford, very simple to take it down to Corpus, and you can put it on a barge and move it over here to Houston, or over to New Orleans, or you can put it on a Jones Act ship, and get take it up to the refineries in the Northeast. And I'm sure you've seen these…

And on the -- I appreciate the color on the ramp-up to $140 million of EBITDA, is that sort of a 2017 time frame, would you expect?

Upon completion, Dax, you want to...

November of '15 through October of '16 are the -- vessels will be coming by.

So by -- everybody, all the new vessels will be on by the end of '16. So it ramps up, and I think it's actually more than $140...

Yes, it's about $146 million.

$146 million, that we expect for '17, once they're all in.

Okay, great. And just lastly from me, can you update the number of warrants outstanding at KMI?

Yes, $348 million.

Our next question comes from Ted Durbin with Goldman Sachs.

I want to follow-up on some of your opening comments there and the underperformance of the stock and talking about how you think it -- maybe can you be a little more specific around any kind of actions you might actually be able to take? It seems like you alluded to it, but I'm just wondering if you can give us anything more there?

Well, the action I hope is that, you guys will be so impressed with our performance that the stock price will rise meteor-like. But somehow, I don't see that happening in the next 24 hours anyway. What we're looking at, trying to do a better job of communicating the story. I'm befuddled because we have this tremendous backlog, and each of these projects has so much potential. If you take the Trans Mountain expansions, and you look at the spread between our cost of capital, what we're going to make on an unlevered basis, on $5.4 billion, and start calculating that and then split it between KMP and KMI, and that alone is a huge growth mover. If you look at some of the projects in the CO2 field, where we're bringing all this additional CO2 on and the new developments in the ROZ, on the other end of it, tremendous growth. We just took our board on a tour of the Ship Channel yesterday, right here in Houston. Kinder Morgan is spending $1.8 billion along the Ship Channel. That's the total projects, along there both in the terminals and the products group. All of these are coming online. We'll fill the rest of KMCC. We started out with 1 commitment on Kinder Morgan crude and condensate, which was from Petrohawk, now BHP, for 25,000 barrels a day the first year and 50,000 thereafter. And that justified a 15% unlevered return on the $220 million investment which, as you know, we converted some of our natural gas lines to hold down the cost of the investment. Today, we've extrapolated that into spending $1 billion in the area. We now have long-term commitments for over 200,000 barrels a day, and we're going to be adding volume on top of that. That…

That's very helpful, and I appreciate all of the color there. Next question for me is just thinking about your Y-Grade pipeline out of the Marcellus. And I guess I'm a little worried here about any abandonment issues you might have with the FERC. You just mentioned there's tremendous trip [ph] demand with gas, north to south. Is there any risk that the FERC says, "Hey, we need to keep this pipeline in gas service and we can't take it out of service?"

Yes. Look, we're in a very good position there, Ted. This is pipe that's in demand, and that's in demand for gas service and we think it may be in demand for a Y-Grade service. And so that does raise the concern that you identified. But we do think, and we're -- what we're aiming for, is the prospect of doing a further expansion on our -- on TGP to move additional gas out, and still be and able to make room for the Y-Grade. Now we'll have to do it realistically, and the Y-Grade line will have to pay for, or bear the, some of the burden of making sure that there's additional capacity on TGP to replace what's being used, but we're shooting for both. We're shooting for the expansion of gas service and the Y-Grade conversion. But you are highlighting a good problem to have, which is, we've got pipe in the ground that's in demand.

And on these -- the sort of backhauls, are you just basically targeting max rates? Is that the way we should think about that, on TGP now for the gas?

On max rates -- I mean they're -- the market rates and they're going up, so.

You've got some headroom, effectively, if you wanted to go to max, is that fair? [Audio Gap]

Did that answer your question, Ted?

Yes, no, sorry, I was just asking, is there a lot of room between sort of market and max? I guess that's what I'm trying to ask, get out of there and --

Yes, no, there's room. I can't get into specifics, I guess we're -- we've got room between the market rates and the max rates.

It's actually forward moving, we're actually physically moving molecules from north to south. And I think the market continues to refer to it as backhauls, but it's an old pipeline. This is really a forward haul, and that -- those molecules are going to end up in the Gulf Coast. Tremendous demand for that, and as Steve says, it's a whale of a nice problem to have.

Next question comes from Craig Shere with Tuohy Brothers.

So a couple different questions. Let's start, maybe with LNG. How is the FTA contracting going for Gulf LNG? Any update on how you guys see authorization, authorizations coming through from non-FTA requests for Gulf and for Elba? And can you remind us, if you do get that, just how large can the growth pipeline expand?

Well, there's a lot of things assumed in that question. First of all, let's look at our efforts as an LNG developer. The right way to think about Elba Island, even though we're certainly like everybody else, applying for non-FTA is, we don't need non-FTA for that. And Shell, in December, just exercised its option on the first part of Phase 2. Now there's another option that can be exercised at the end of this year. But all of that, and if they exercise that second option, we will end up there with a project on a [indiscernible] basis, something in the $1.5 billion range. And it will be moving about 350 million cubic feet a day through there. That's relatively small by LNG standards, but it's a very nice project for us. We own 51%, Shell owns 49%. And in addition to that, it gave us the opportunity to spend money on other infrastructure necessary to get the LNG there and associated facilities around the terminals. So it's more than just our 51% of $1.5 billion or so. So a great opportunity for EPB. On the Gulf LNG, we continue to look at opportunities there, we talk to customers, we don't have anything to announce at this point. Another big part of the LNG story, of course, is the ability of our pipeline network to serve the LNG facilities, particularly those along the Gulf Coast. And we will have a role at Magnolia, assuming that gets built, we think we'll have a role at Cheniere, some of the additional trains at Cheniere 5 and 6. We certainly believe we will furnish a significant part of the gas at Freeport. And so all along here, we have as many miles of pipeline or more than anybody else, and the ability to connect all kinds of sources of supply and get it to these LNG facilities. And in the long run, that may be the greatest opportunity for the Kinder Morgan family of companies. We're going to continue to look at opportunities at Gulf LNG, we'll see how it plays out. We don't do anything unless we get firm commitments on it, so we'll see there, but the opportunity for serving these facilities through our pipelines is enormous, comes back to what I was saying a question ago, which is the size and scope of our footprint.

Great. And let me follow-up on Brian's question about Citrus. How full is FTT now? Is there still that, what was it, 20%, 30% capacity on the old Phase 8 expansion that was originally uncontracted? And does the tax status have any implications of any drop-down decisions?

Dax, you want to answer that?

What was that again, Rich?

Well, the first question was on the capacity, is there any remaining on Phase 8. And the answer is yes. I'm not sure what the percentage is. And then, the second question was on tax status.

Yes, the -- there's approximately 184 a day remaining of capacity, that we're still having a little bit on an interruptible basis. And we're constantly looking at the market to see what we might be able to sell on a term basis. We've had conversations with several people, talked to [indiscernible], we're getting things done on a near-term basis. And from a tax perspective, we certainly -- we have some NOLs and some depreciation associated with the Phase 8 expansion that we'll be running out over, call it, the next 4 or 5 years. And the cash tax obligation of Citrus will ramp-up over what I'd call the next 4 years, pretty substantially, so.

Great. And last line of questioning is around the EOR ops. I noticed the nice bump sequentially from third quarter for Katz. Is that finally kind of on track with the model performance? And was the 9% jump from the third quarter in SACROC expected or well ahead of expectations? Looked like a nice jump there. And if the market continues to be flustered by that business, which I don't understand why, since you had it for so many years and it's a smaller part of business today, but if it is, would there be any way to monetize a portion of the assets to reduce the overall size, minimize production rollover concerns and help fund the growth projects?

Let me start with Katz. We believe Katz is on track. There are no guarantees but certainly, we've -- we just went through a review a few days ago with the CO2 team. We think it's in good shape and moving up as we said, so many times. It was a delayed response, but we believe we'll get the same amount of barrels out of there, as we expected when we first developed it. It's just they're coming a little later. SACROC, we've said before, the old phrase that Tim Bradley taught me, which was, big fields get bigger. And I think that's what we're finding at SACROC. We're just finding a lot of additional opportunities to drill there. A nice increase, that increase is continuing through January. We're averaging between 32,000 and 33,000 barrels a day there. I don't think anybody on this call's mentioned the fact that also last year, we set an all-time annual record on the NGL side at about 19,500 barrels a day of NGLs associated with SACROC. So it's going very well, and we think we're going to have additional opportunities to continue to grow SACROC. I think monetizing these assets would be very difficult. We're not in the game of selling things. We're in the game of buying and expanding, and so we don't have any intention of doing that now. And you're quite correct, I mean, CO2, we hold it to a higher level of expected return than our pipeline's investments and rightly so. And it's declining part in terms of the overall company. We're happy to have it, it's a good asset. And remember, a big chunk of it, and a big chunk of the future growth there is not on the OR [ph] side, it's over there on the S&T side where we're finding some really good ability to produce more CO2 and get it to the Permian Basin.

Right. And one last follow-up on that EOR question. Can you update us, it seems like propane's recovering, even ethane pricing to some degree. Can you talk about what you're seeing in terms of trends there, and also for the basis differentials?

[indiscernible]

Yes, we are seeing -- we typically look at NGLs as a percentage of crude, and obviously that's climbing up, primarily driven by propane. And we continue to see that. We expect that to continue to happen over the next few years.

Our next question comes from John Edwards with Crédit Suisse. John Edwards - Crédit Suisse AG, Research Division: Just following up a couple of the earlier questions. Just -- I'm curious on the TGP expansion on the gas side, and then comparing that to the proposal to move NGLs. I'm just curious, which opportunity do you view as bigger? The further backhaul opportunity, or with the NGL transport opportunity, would you view that as larger?

I guess, I would say, John, it's bigger if we could do both. And so we're trying to figure out a way to do both. And that is a function of being able to expand our backhaul -- our gas backhaul capacity on TGP, and still leave room for a Y-Grade option. And that's really the path that we're on. Now the thing that we have -- there are a few things that have to come together in order to make that happen. The biggest one of which is that Utica and Marcellus producers have to be ready to commit. And so as you know, we extended the open season, we and MarkWest extended the open season on the Y-Grade line and -- to the end of February, and we are working actively with customers. We think it's a good project. We think it's a good solution. I think MarkWest, I know MarkWest thinks it's a good solution and a necessary outlet for producers up there. But it sometimes takes a while to have that materialize into commitments. But our approach is, we think there's a way to do both, and so that's what we're pursuing right now. But it's not entirely within our hands, it's up to the market in part. John Edwards - Crédit Suisse AG, Research Division: Okay, fair enough. And I mean, can you comment at all on what you think might be -- what's causing the hesitation to commit, or is that something you can't talk about?

Well, no. I mean, I think it's -- look, if you look at the numbers, people are projecting 1 million barrels additional NGL volume coming out of the Marcellus and Utica -- or the Martica, I guess, the combined play. And if that's the case, I mean, you can fill up 2 pipelines, expanded, right? But there's a time lag between projections and -- projections coming true, and people being confident in what they have, and needing an outlet and signing up for an outlet. And so it's really just a function of, I think, a natural producer, with their working -- not so sure it's a hesitation -- they're working first on their production and figuring out how to get it out of the ground and what it is that's coming out of the ground, and then they start looking for the downstream solutions. And that's a question of timing, they're going to need them, we're convinced they're going to need them, we're convinced that an outlet to Mont Belvieu is going to be part of the answer, but they have to be prepared to sign up. John Edwards - Crédit Suisse AG, Research Division: Okay, that's really helpful. And then with the -- moving over to SACROC, with the increased production you're seeing, maybe you'll cover this further at Analyst Day, but as far as you keep pushing out the year when you see production rolling over, is it fair to say that, that's going to pushed out further once again? And is it now going to be pushed out to say, somewhere around 2018 or so, if you could talk a little bit about that?

Yes, I think there's a number of things that are obviously impacting the in-fields we're finding from some of the seismic we've run, we're working out very well, we still have a lot of opportunities there. Our platform areas are doing better recovery than we expected, we're doing some horizontals up there that are looking really good, these horizontals will allow us to go back in amidst [ph] some -- pick up some bypass pay. This will extend SACROC out several more years, and we'll get into that in the conference. But I think you'll be surprised how many years out it will extend it. Our harvest wells continue to do well. In fact, we're backing off of those a little bit, just to have -- we started those when we needed CO2. Now we've kind of got, with Doe Canyon coming on, full strength. We've got a little bit more CO2 coming into the basin, so we backed off the harvest a little bit, not doing as many of those as we had planned this year or next year probably, but still, we'll run the 2,900 barrels a day with the harvest wells, so that's a good project there, too.

Next question comes from Jeremy Tonet from JPMorgan. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: I was just wondering, I had a couple of questions, if you're working at the natural gas pipeline segment, and you took out what happened with the Copano acquisition, just wondering how that baseline business stacked up against the original budget for the year, if you have that available?

Sure, I think Kim covered that, [indiscernible]

I can take you through it. So natural gas, versus its budget -- or versus the original budget was up about 10%. Without Copano, without any benefit of the Copano acquisition, it would have been down about 3%. And the reason that it would have been down was poor performance out of our trading business, lower storage revenues coming on our Texas intrastates, and then our investment in the Eagle Hawk, our 25% investment and JV with BHP didn't ramp-up as quickly as we expected it to in our budget. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: Got you, great. And then for Kinder Morgan Canada as well, how do things look if you excluded the impact of the Express-Platte sale?

If you exclude -- and Express has an impact on Trans Mountain as well, because we had a management fee that Trans Mountain was getting. And so, if you just look at Trans Mountain, other than the loss of revenue from Express, Trans Mountain would have been on its budget.

Next question comes from Kevin Kaiser with Hedgeye Risk Management.

The first question I have here is on the Natural Gas segment. Transport volumes were down 5% year-over-year in the quarter, and gathering volumes down 3.4% year-over-year in the quarter. Can you talk about what's driving that?

I think, at least on the gas transport side, I think it was -- and, Tom, you correct me. We had record electric generation volumes associated with relative coal to natural gas pricing. That was probably a contributor, not sure if it was the whole story there.

'12 versus '13.

Yes, in '12 versus '13. I think our sales volumes were actually up, so I think you may be right on transporting, gathering, but the sales volumes were up on our Texas intrastates. And then gathering, probably a function of the KinderHawk or the KinderHawk volumes. And so, both on the transport side, and in that case, if that's the explanation that KinderHawk -- we have minimum commitment, so it's demand based on gas transportation side, and it is take or pay, effectively demand based on the KinderHawk asset as well, contract minimums.

Okay. Moving to the CO2 segment. What was the EOR side -- in the EOR side of that business, what was capital expenditures in the fourth quarter? Total CapEx for EOR in 4Q '13?

I don't have it with me, hang on a second.

[indiscernible] EOR versus the rest of CO2.

Go to your next question, and we'll see if we can find it.

Okay, and KMP, what's the coverage guidance for 2014 DCF versus the guided distribution?

We haven't given it yet, and we're going to go through the entire budget in 2 weeks at the Analyst Conference, or 1.5 weeks, 2 weeks at the Analyst Conference.

Including the expected coverage.

And the expected coverage on KMP, EPB and KMI.

Okay. And the last question I have is, have you considered amending KMP's partnership agreement for how sustaining capital was defined there? I mean if you look back at when the partnership agreement was put in place, there wasn't E&P, there wasn't shipping, there wasn't coal royalties, so do you think that amending that partnership agreement would be appropriate to protect the limited partners from dilution?

I don't think we have any present plans, Kevin, to change the partnership agreement. We think it's worked very well, something that was put into effect in 1992, long before we bought it. And we think it does a good job of protecting the limited partnership.

We think our limited partners have gotten a very nice return over those 12 years. And we expect them to continue to get a nice return in the future. The expansion capital for 2013, for the S&T business was a little over $200 million, and we spent about $675 million total in CO2.

You're talking about S&T though...

S&T and then the rest would be oil and gas.

[indiscernible] about 4 75.

And I think, Jim, if I'm remembering correctly, if you look at SACROC and Yates together, the total CapEx in there was about $330 million, $340 million. The total DCF on a combined basis was a little over $1 billion.

And our last question that I am showing comes from Becca Followill with U.S. Capital Advisors.

On EPB, flat distribution this quarter and your guidance is for flat distributions for the rest of '14, can you talk about what visibility you have on being able to maybe increase that distribution beyond '14?

Again, we're going to take you through all that in 2 weeks at the conference, and that's what we're working on now, looking out as I said, across all the companies, out through '18. But horseshoes and hand grenades, the key thing on EPB is that it's relatively flat, it has very good, solid contracts but has some headwinds relatively flat, that obviously has -- will get a nice bump when the Elba Island assets come online. But we're going to take you through that. Like I said, we're running numbers out through '18 and going to be able to take you through on all 3 companies in 2 weeks.

And then on SACROC, that's probably the biggest bump in production that I've seen on a quarter-to-quarter basis. Is that -- I think, you spent 2 -- I just want to clarify, is that largely being driven by horizontal drilling?

Yes, I think so, and particularly in the north platform, one of the things we're seeing that is the oil bank was probably pushed more towards the well bores prior to us even injecting, because there had been CO2 injected in that area back probably in the late 90s with Penns [ph] Energy. So CO2 had already been in the ground, and that's the upside on this, as we're seeing that in tight zones, that the longer the CO2 sits in there, it starts making that oil bank. And we drilled some horizontals. We had trouble getting delays and getting permits from the railroad commission for 2 or 3 months and we're producing 400, 500 barrels a day out of those horizontals that we're using now as injectors. So that gives you an idea of the oil bank that was ready there, and that's what gives us a huge opportunity for some of the bypassed oil back in some of the other areas in Bullseye and so forth, where we put lot of CO2 into the middle canyon, and just didn't produce the barrels out that with that we would. It was a geat opportunity to go in with horizontals, and get that back in there.

Can you speak to how many horizontals you drilled during the quarter?

I believe we drilled 4 during the quarter.

And then, plans for '14?

We've -- can't remember all of them. I know we've got a couple of -- that we're going in to test the bypass oil and then I think we've got just our regular development, up in the platform area, I think we've got 4 or 5 of them set to go there.

And then last question on the per unit DD&A in the CO2 business. It looks like it was a sizable drop quarter-to-quarter, about $2 a barrel. Anything in particular going on there?

Drop in the DD&A per unit.

I think the key thing there was just the additional barrels that we produced in -- at SACROC, lower rate that we've been able to push in there. We've got a lot more barrels. We -- the infrastructure's now getting to a point where we're not having to add a lot of extra infrastructure to get to additional oil. And so that, over time's just going to push that rate down.

And I am showing no further questions at this time.

Okay, well, thanks to all of you. I appreciate you sharing some time with us. Thank you, have a good evening.

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