Kinder Morgan, Inc. (KMI) Q1 2013 Earnings Report, Transcript and Summary

Welcome to the Quarterly Earnings Conference Call. [Operator Instructions] This call is being recorded. If you have any objections, please disconnect at this time. I would now like to turn today's call over to your host, Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. Sir, you may begin.

Thank you, Aerin, and welcome to the Kinder Morgan Analyst Call for the First Quarter of 2013. 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 give an overview of the first quarter. Kim Dang, our Chief Financial Officer, will then take you through the detailed financials. And then our President, Steve Kean, Kim and I will answer any and all questions that you might have. As usual, we'll be talking about Kinder Morgan, Inc., the GP of the Kinder Morgan companies, which I'll refer to as KMI; and also about Kinder Morgan Energy Partners and El Paso Pipeline Partners, which I'll refer to as KMP and EPB. And those are our affiliated Master Limited Partnerships. Together, these companies have an enterprise value of a little over $110 billion. That makes us the largest midstream and third largest energy company in North America. Once again, I'm happy to report that all 3 entities raised their dividends or distributions for the first quarter of 2013. So let me take you through each of the 3 companies. Starting with KMI. We raised our dividend to $0.38, which is $1.52 annualized. That's up 19% from the first quarter of 2012. We had cash available for dividends of $513 million or $0.49 per share, which is an increase of 14% over the $0.43 per share that we had in Q1 of 2012. We're on target with our drop-downs of El Paso assets into KMP and EPB, and we completed the drop-down to KMP in the first quarter of 50% of El Paso Natural Gas and certain midstream assets. And we expect to sell our 50% interest in the Gulf LNG facilities to EPB later this year. We're also on target…

Okay. Thanks, Rich. I'm going to start with KMP. Then I'll do EPB financials and finally, KMI. Looking at the first page of the KMP financials, you'll see it's the GAAP income statement. As we say every quarter, we don't find the GAAP income statement overly meaningful. And so I'll move to the second page, which is what we think more accurately portrays the results of the company and our calculation of distributable cash flow, so the cash flow that we produce for -- that's available for distribution. At the bottom of that page, you will see DCF per unit, as Rich said, of $1.46, up 7% versus a year ago. Versus our distribution of $1.30, that translates into coverage of a little over $60 million. As we said at the time of the budget and it still continues to be true, we will have excess coverage in the first quarter. We will have excess coverage in the fourth quarter and we will have excess coverage for the year. But we will have negative coverage in the second and the third quarter. The DCF in total, $550 million in the second quarter. That's $88 million above this first quarter of 2012. Looking at where that growth comes from, the segments in total, $1.276 billion of segment earnings before DD&A in certain items. That's up $247 million or 24%. Of the $247 million, $218 million of that is coming out of natural gas. And as we discussed, that's largely driven by the drop-downs that KMP or the assets at KMP has acquired from KMI, both in August of last year and in March of this year. And that's somewhat offset by reduced income because of the sales, the FTC sales, that we made in the third quarter of -- the fourth…

Okay. Aerin, if you'll come back on, we'll take questions that you may have.

[Operator Instructions] Our first question comes from Darren Horowitz from Raymond James.

I've got a question -- actually, 2 questions about the CO2 business. And this goes back to some of the comments that you made with regard to expanding the source fields in Southwest Colorado. But as you're talking with these Permian producers, you guys obviously have a pretty good sense of the timing of CO2 production as that ramps concurrent with the expectations for crude production growth. And it seems to like that could drive a lot of incremental volume commitments on the Freedom line. So from a source field perspective, is the right way to think about those compression additions that you referenced at Doe Canyon and McElmo Dome still tracking about $500 million in total cost for both and a target in terms of volume ramp maybe around the second and the fourth quarter of 2014, respectively?

Go ahead, Jim Wuerth.

Yes. The costs are right on budget and I think with both of those together, it's about $500 million. We should have expand at Doe, and we should even be getting most of that expansion done in the volumes by the end of this year, in fact, in the fourth quarter and then towards the end of 2014 for the Yellow Jacket facility.

Okay. And then taking that one step further, that new source field on the Arizona-Mexico border, I assume you're talking about expanding St. Johns. And I recognize you're still in the assessment phase there, but is the right way to continue to think about that, roughly a $2 billion project cost that could possibly get to 650 MMcf a day throughput and that would basically feed the Cortez line? Am I thinking about that the right way?

Yes, we reduced the cost quite a bit and looking at a $200 million case and that will start with that. And I think those numbers are around $600 million and we -- yes, we would head into the Cortez Pipeline just south of Albuquerque.

Next, we have Ted Durbin with Goldman Sachs.

Just on the Freedom side here, you've got this number, the 277,000 barrels a day. I guess I'm wondering, it seems like a pretty precise number. How did you get to that number? Is that what you need to get to sort of a certain hurdle rate or your kind of a return that you'd need? And then maybe you can talk about what kind of tariff you'd need to get to the economics you want on that pipeline.

Well, the 277,000 is just what the engineering studies showed would result -- would be the resulting capacity from the way we intend to build it. That's not the number of barrels we would need. We would need fewer barrels than that. I think we've said publicly we need around 200,000 barrels a day to make the thing hunt economically. As far as the tariff, Tom Martin is here. Tom?

Yes. It's in the neighborhood of $5. It's kind of what we've been pitching to the market.

$5. And so again, as I said, we have an open season underway now. And if we get the kind of commitments that we hope to get, this will be a good project. If we don't, we'll, obviously, reassess. We're not building it for our health. We're building it only if we can make money on it. So that's where we stand on it. And we're just in the middle of the open season now, we've got good conversations, but we'll see how that translates into volumes. As I've said before, it would seem to be a marriage made in heaven. You've got certainly trend line toward increasingly excess production in the Permian and you've got the West Coast refineries that are spending hellacious amounts of money on crude supply. And you would think that paying a reasonable amount of money to bridge those 2, the source and the demand, would make sense, but again, that's up to our customers.

Got it. That's helpful. The next one for me is just on the Terminals here. It looks like kind of flat year-over-year results. You're now saying probably below budget. I guess I'm trying to understand, is that just kind of continuation of the trends you saw in the first quarter with the weak coal volumes, petcoke volumes? Or kind of how do you see that shaping up for the rest of the year?

Well, first of all, we had a 12% growth in the Terminals for the year and we'll get very close to that. And so when we say slightly below budget, we're still, for the year, going to have a very nice growth. We have some things coming online later in the year. So certainly, it's not going to be flat to 2012. We're going to have growth. We're just not going to have -- quite chin the bar at that 12% growth that we have in the budget. John Schlosser, you want to add...

The other thing I'd add is the petcoke volume our earnings were off $2.3 million and that was associated with 4 outages at major refineries here in the Gulf Coast. So we don't expect that to recur in the out-quarters.

Great. And then this is a small one -- I think it's a small one for you, but I want to make sure. All this RIN noise, the renewable credits, I guess, is that anything that we should think about as being an impact to you, an opportunity or a cost? Just how do we think about the RINs for you?

Well, it's a positive for us because we generate excess RINs at our Transmix facilities. And then how much of an upside for us is, depends on the price of the RINs. We're pretty definite on how many RINs we're going to -- excess RINs we're going to generate and it's about 700,000 gallons a month.

That's right, it's 700,000.

And so today, those prices are running $0.65, $0.70. So you can multiply that out and that's how much per month we can make from it. But they were as low as $0.10 a few months ago. They've been as high as, I think, $1.08 or $1.10 at one point. So we're just -- we're selling them on a monthly basis to a customer who wants to take all that we have and so we'll just see what it results in. So it will be upside. The question is how much; and that, we don't know. We just play it month by month and that's not in any of the projections that Kim's talking about when she says products is going to slightly exceed. It's a plan for the year. We haven't counted anything on additional RIN sales, although we recognize about $1.9 million, I think, Ron, of sales in the first quarter.

Yeah.

Next, we have Craig Shere with Tuohy Brothers.

A couple of questions. First, on LNG. Is the focus on off-takers that are really interested more on FTA country exports, just natural conservatism? Or do you think that it's just going to be very tough to get incremental DOE non-FTA approvals? And do you see the recent rise in gas prices in the states affecting both the appetite and potential pricing for those long-term contracts?

Well, first of all, I think the answer as to why we're concentrating on FTA is a combination of 2 things. You mentioned that we are conservative about it. And secondly and we're not sure what the non-FTA process is. I mean, just as recently as yesterday at a conference, I guess, the undersecretary, who's in charge with making these decisions, said he didn't know when they would make the decision, that they had to consider a lot of factors. They've had a couple of studies already about which you said we should export. But we don't have a decision yet. So I think in the end and I've said this before, our view is that there will be substantial amounts of non-FTA approved, particularly for those plants that have good contracts with viable, creditworthy companies. But we can't guarantee that, that's going to happen. So we've concentrated on the FTA. And as I said in my remarks, the beauty of the deal with Shell at Elba Island is that whole first phase is not contingent on getting the non-FTA approval. Now at the Gulf, where we have more space, more opportunity there in terms of sizing, we're working with some customers there to do a non-FTA train -- excuse me, an FTA train and we're working with other customers to work on non-FTA volumes, too. But again, our first preference is to get FTA signed up because there, we have projects we can depend on and know that they're going forward. So that's our feeling. As far as the gas price increase, I don't know how much weekly or monthly movement really means. I don't believe anybody thought that the Henry Hub price of supply looking out over the life of an LNG contract was going to stay at $2 or $2.50 where it was this time last year. But certainly, if the perception becomes that gas prices are meaningfully higher, then that will have some impact, I suppose, on how willing players are to enter into contracts. You have to remember, of course, that the disconnect between the landed prices for LNG, particularly in Japan and the rest of Asia to a lesser extent, versus the price of the Henry Hub even when adding in the liquefaction and transportation expenses is still enormous. There's still a big spread there between the landed cost and the cost of the -- landed price and the cost of delivering. So I think there's still money to be made there. But that may well change, may well close. And obviously, we're not betting on that. We're just looking for customers who want to take a swing at those things and make a lot of money and we're happy to just get the minimum return on our little assets that we're going to build for them.

Great. And I just want to follow up on Darren's questions on CO2. Is the CO2 supply more than EOR really driving the expectations for outperformance for the year? And on EOR, do you see production continuing to surprise the upside?

Well, I think first of all, starting with the second question on the EOR side, we were off to a very good start, particularly SACROC, which was hugely above this quarter last year and a good bit above our plan for the first quarter. And these NGL volumes also are running above our plan and at record levels. And we expect those to continue. Now we're going to have -- we have a train down now on the -- that curtails for a couple of weeks some of our NGLs. So we may not have exactly the same numbers we had in the first quarter, but we expect both of those will be very strong for the year. Katz had a very nice increase quarter-over-quarter and we're continuing to see growth over there. We're now running -- in April, for example, we're up to 2,400 barrels -- a little over 2,400 barrels a day there. So that's a nice increase even though we're in the first quarter. So I think all of our EOR activities are all production that looks good for the year. And we expect that to continue. We -- the supply side of it, the CO2 amount, I think it's more of a long-term driver. As Jim Wuerth said, we will have some of that, particularly at Doe, online. We've taken the October, November timeframe, which will help us some. We're curtailing now. And at Doe alone, we think we can take the production up from about 105 a day to 170 a day. So to the extent we can sell 65 million cubic feet a day of CO2 for a couple of months, that will be a nice little driver in the next couple of months. But it's not the major driver. The major driver, I think, in the long run, is getting that production from Southwest Colorado up to the full 1.4 Bcf per day and then that should happen by next year. And then getting the St. Johns field, all in which case, we'll be at 1.6 and maybe a little better. That's where I think the upstream or the supply side becomes a real driver.

[Operator Instructions] Our next one comes from Bradley Olsen with Tudor, Pickering.

On the Cochin project that you guys have discussed going from Illinois to Alberta, you obviously have an Eastern segment of that pipeline, which there's been no reversal plans announced yet. But given the prospect of a lot of condensate basically without a market in Ohio, as the Utica gets ramped up, is that a project that you're continuing to look at? And have you discussed that with potential customers?

Yes, we continue to look at that. There are a couple of interesting alternatives for that Eastern segment. Ron McClain, anything you want to add to that?

We've looked at several opportunities and are actively pursuing it. We don't have a project yet, but we do think it's part of the ultimate solution for some of those projects that's going to come out of that area. So we're working with several people on it.

Great. On the Tennessee Gas asset, you -- the asset runs through a potentially productive area in Northwest Pennsylvania and Northeast Ohio. One of your competitors recently announced a project to provide gathering and processing services in that area. Is that an area where, especially given your past relationships with Petrohawk, given that Halcon is talking about that being a big area for them, is that an area that you expect to potentially use your Tennessee Gas footprint to build out a gathering and processing asset base there?

Tom Martin?

Yes, we are actually -- in our midstream segment, we're actively pursuing, gathering and processing opportunities in the Utica as well as the Marcellus. We're really focusing on the Utica right now. We've been pursuing that for the last several months and really starting to see a little traction that at this point. So it will be both dry gas and rich gas gathering as well as processing and we're pursuing those opportunities right now.

Great. And then just one more housekeeping question. Can you provide utilization rates on the oil and condensate line out of the Eagle Ford? and if you have the numbers available, a breakout of oil versus condensate volumes?

Well, what we have on the Kinder Morgan Crude and Condensate line is it has capacity of 300,000 barrels a day. As we have publicly said, our original contract with Petrohawk, now BHP, was 25,000 barrels a day in the first year and then ramping up to 50,000 barrels a day beginning in the middle of this year, 2013. And that throughput alone was sufficient to make it a very viable project economically. Since then, we've added Phillips 66 as a customer. We publicly announced this. They have taken additional capacity of about 20,000 barrels a day on it. We're very close to adding another customer, in fact, our board approved today the expenditures for it, that will add another 25,000 barrels a day. And we have still another customer that we think is probably another 25,000 to 30,000 barrels a day. So that kind of gives you an idea of the ramp-up in volumes there. We see that as it's going to be an extraordinarily good investment for us because there's just a lot of people, a lot of producers that want to get to the Houston Ship Channel and that's what we provide them. And then sort of as a step out from that, of course, I think that helped us secure the contracts to build the condensate splitter on our Houston Ship Channel property, which is the $360 million project that I referred to earlier. So we've got a long way to go, a lot of upside on KMCC that we'll just see how it plays out in the future.

We have no further questions in queue at this time.

Okay. All right, Aerin, thank you very much. And thanks to all of you. And we're delighted to share our good news with you and have a great evening. Goodbye.

Thank you for your participation on today's call. You may disconnect your lines at this time.