Kinder Morgan, Inc. (KMI) Q3 2013 Earnings Report, Transcript and Summary

Welcome to the Quarterly Earnings Conference Call. [Operator Instructions] Today's conference is being recorded. If you have any objections, you may disconnect at this time. Now I will turn the call over to Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. Sir, you may begin.

Okay. Thank you, Kelly, and welcome, everybody, to the third quarter earnings call of Kinder Morgan. As usual, we will be making statements within the Securities Act of 1933 and the Securities Exchange Act of 1934. I'll give an overview of the quarter and 2013. Steve Kean, our Chief Operating Officer, will go into more details of segment performance and talk about our project backlog; and then Kim Dang, our Chief Financial Officer, will review the details of the financial results for quarter and year-to-date, and then we'll take your questions. The Kinder Morgan companies had a good third quarter, and I think we're on track for a very good year. At KMI, we raised the dividend to $0.41. That's an increase of 14% from the third quarter of 2012. In terms of cash available for dividends in the quarter, it was up 17% from the comparable quarter a year ago. We're on track for a 14% growth and declared dividends for the full year '13, and we expect to declare at least $1.60 versus $1.40 for the full year of 2012 and versus the '13 original budget at KMI of $1.57. KMI continues to benefit from strong growth and performance at KMP and from solid cash flow generation at EPB. At KMP, we raised the distribution to $1.35. That's up 7% from the third quarter of 2012. Our DCF before certain items was up 22% for the quarter. For the full year 2013, we expect to declare dividends of $5.33. That's up 7% from the full year 2012 and is $0.06 above the $5.27 target in our budget for 2013. At EPB, we raised the distribution to $0.65. That's an increase of 12% from the third quarter of 2012. For the full year of '13, we still expect to…

All right. I'm going to go through the segments, focusing on performance third quarter, the third quarter last year versus this, our expectations versus plan for the full year and then some of the business drivers and the backlog. Starting with gas, the gas segment at KMP is up 59% on an earnings before DD&A basis, to $608 million versus $383 million in the same quarter last year. The increase is the result of the drop-down transactions, TGP and EPNG and also the acquisition of the other 50% of El Paso Midstream from a third-party owner, and the closing of the Copano transaction in May of this year. So these acquisitions more than offset the year-over-year negative of the divested Rockies assets that we had to sell pursuant to the FTC order to close the El Paso transaction. With respect to the performance versus plan, this segment is expected to exceed its plan for the year, but entirely as a result of the Copano acquisition. From a volume standpoint, higher Eagle Ford volumes drove improved year-over-year performance at the Texas Intrastates. But we had lower overall transport volumes across the segment versus the third quarter of last year as a result of lower gas demand for electric generation versus that record year that we experienced in 2012. If you look -- focus in on EPB, that lower demand in electric generation on the SNG system, and the impact of rate case settlements on SNG and WIC caused EPB's assets -- asset earnings before DD&A to be down slightly in the quarter versus third quarter last year, $286 million versus $299 million last year. But looking ahead, we added to our project backlog in this segment, primarily in EPB, and overall, we continue to identify and capture opportunities for expansion, driven…

Sure. And I'll go through the numbers, starting with KMP, and you should have 4 pages of numbers. I'm going to go and focus on the second page of numbers, which is our distributable cash flow and how we look at performance. Let me point out that, that distributable cash flow is reconciled to our GAAP numbers, and we provide details for you on all the -- on all the certain items and adjustments. But in the quarter, as Rich mentioned, DCF was $1.27 per unit. That's down slightly from the third quarter of last year. But on a year-to-date basis, $3.94, up $0.22 or 6% on a year-to-date basis. And for the full year, we expect DCF per unit to be up about 6.7%. The $1.27 based on $1.35 declared distribution results in about $34 million of negative coverage in the quarter. And as we told you, we've told you all year, we expect coverage to be negative in the second and third quarter, positive in the first and fourth, and positive for the full year. On a year-to-date basis, the $3.94 compares to the distribution of $3.97, and so we're about $14 million short. But again, for the full year, expect to cover. The $1.27 translates into DCF of $554 million. That's up $99 -- $99 million or 22% versus the third quarter in 2012. And so, let me just reconcile that $99 million for you, what's driving that growth. If you look at the top of the page, our segments are up $262 million. And of that $262 million, $225 million is coming from the Gas group, so about 86% of the segment growth in earnings before DD&A is coming from natural gas. And as Steve said, that's driven by the drop downs from KMI and from…

Thank you, Kim. Thank you, Steve, and we'll take questions from the callers. Kelly, you want to come back on?

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

I realize the Marcellus and Utica liquids project isn't in the budget and that it was announced as a letter of intent contingent upon sufficient shipper commitment and various approvals. But since the JV announcement, the competitive landscape has changed a little bit. You've got an additional proposal for a big LPG dock in Lake Charles and another large player moving forward with the second big marine terminal expansion. So I'm curious how that changes the playing field as you view the project and, more importantly, the odds of it getting done.

Well, again, as we've said all along, Darren, we'll only do this if we have commitments. So far, we're seeing a lot of customer interests. Steve, what do you want to add to that?

Yes, I think one of the things that is still to be completed, particularly, folks, you really have to look at this project in 2 parts. First part is the processing part. There appears to be a lot of demand for additional processing capacity, and we expect there'll be even more as the producers get a handle on the composition of their Utica volumes as it starts coming out of the ground. And so that's kind of one aspect of the project. The other is the Y-Grade line, and that's you're mainly focused on. And there -- I mean I think that having more outlets potentially for this product as it moves south, the way we proposed it is we could build either into Southwest Louisiana or into Mont Belvieu. And what we're talking to shippers about or producers about right now is what they would prefer and what we've also put on the table -- when I say we, I mean us and MarkWest -- is the interest that we have in potentially building some fractionation capacity for them. So the fact that there might be some additional destinations, it certainly complicates the picture, but it's still something that we're willing to invest in and willing to hear what our producers think in terms of where they want to go. But that's the thing we've got to still get straightened out and be able to present to our producers, but we're really kind of looking in part for them to tell us where it is that they want to go.

Okay. And then, Steve, my last question, shifting gears a little bit, over to the BOSTCO terminal. I appreciate the color there, but beyond the remaining 30 tanks that should arrive online over the next 6 months and hitting that aggregate capacity threshold that you outlined, how do you guys think about land adjacent to that or the ability to leverage that footprint possibly to add more splitting capacity for the export of a complementary product like gas oil or like [indiscernible] Latin America? I mean, how does -- ultimately how does this refined product push to the Gulf Coast whether or not it's there or Galena Park or Corpus? How does that work into your downstream plan to add more capability?

Well, I mean, it's a good thing for our assets set on the Houston Ship Channel. So we have the largest independent terminal-ing facility at Pasadena and Galena Park. Over the years, we've been adding across channel lines to improve the connectivity. KMCC has that as a destination. We're looking for ways to interconnect that big operation, which is also expanding with the BOSTCO facility. And so overall, the push to move more product into storage and then out, either by pipeline or on ship or barge, is a positive thing. And John Schlosser is here. Do you want to add anything?

Yes. We've seen a groundswell of products that's trying to get to the water there. You have the opportunity for 2 additional docks at BOSTCO. We're building a new dock at the Greens Port facility at our partner Watco's facility, and we announced the AES facility, which will have an additional dock as well. With that, will come additional tanks and additional ability to move product down to the water.

Our next question comes from Brian Zarahn from Barclays.

I guess following up on Darren's first question on the Marcellus Utica Y-grade line. Where are the potential shippers leaning towards in terms of destination of Belvieu or Louisiana?

I think there's interest in both. I don't know if there's a preponderance. I guess we've heard more talk about the ship channel than anything else when you say Belvieu.

Probably Belvieu on the margin.

Just because Mont Belvieu is still viewed, and I think correctly, as the most liquid point in the whole infrastructure play. So I'd say we've had a little bit more interest there.

In terms of if that's the market, would you lean towards third parties? Or would you look at adding your own fracs? And if you were going to build your own, where -- would it be in Belvieu or outside Belvieu?

Well, I think we're working with a number of parties now on both ends of the transaction, in other words, with some of our potential shippers and also present owners of frac capacity. And together with MarkWest and we're just looking what other alternatives are. I think we haven't made a decision on that yet.

Okay. Any type of ballpark range of potential cost without the fracs for the project?

Well, what we've said -- and, look, we're in a very competitive situation here, as you know, Brian, so we have not really broken the components out. We've just pointed to north of $2 billion as the kind of all-in investment here.

Okay. And then any update on the hedges for 2014 and 2015 production in the CO2 business?

Kim, do you have those?

Sure, I can tell you what they are. If you look at the -- you want 2014, we are 66% hedged at about $94 a barrel. 2015, we're about 43% hedged. And depending on the way you look at our collars between $90 or $92, if you have the market price in, it's $92, if you have it down at the put price or the floor, it's $90.

Our next question comes from Ted Durbin from Goldman Sachs.

Question on the CapEx budget overall and you talked about how you had this sort of hollow part in the 2014 and 2015 that you're now filling in. I'm just wondering if you can give us a sense of where the budget is looking like for '14 at least. Is it up or down versus this year? And then how that might then translate into your goals for distribution growth of, say, 5% to 6%?

Well, if you look at '14, Steve is right, we're filling in those holes. And right now in this project backlog, we have about $3.4 billion, a little north of that for 2014. We're just starting the budget process, and I'm sure there will be additional projects added to that when we go through the budget with all of our business segments over the next 3 weeks starting next week. But that's what we currently have in this backlog. And again, I would look at that as a pretty conservative number compared to where I think we will end up.

Did that include drop-downs as well, I'm assuming?

No, that does not include drop-downs.

Yes, that is just capital projects.

Got it. And then if I can just shift over to the Gulf LNG. You mentioned that a little bit in the prepared remarks kind of waiting on the drop-down to EPB. I guess I'm just wondering if you can give us a little bit more detail on where you are in terms of the contract. You said you were going to wait maybe 4 months. Is that a reasonable time frame to think about when you might have a sense of what the contracts are or is that just you're sort of pushing that out and they got pushed a little bit further? Just talk about Gulf LNG for us.

I think we will have detailed information on the drops of the remaining assets by the end of this year, we'll be able to disclose that. Once we get through the budget process, I think we'll be able to tell you what we expect will be able to do.

Got it. And then just coming back to the Marcellus and actually on the natural gas side, you've obviously got a lot of growth there and a lot of producers that are concerned about where basis differentials for and some of the discount I think you saw the summer. I'm wondering if there are some bigger things that you're thinking about around takeaway there because of the big growth in the basin and around your assets.

Yes, there are a number of things we're thinking about. And for competitive reasons, I really wouldn't want to go into all of them. But obviously, we believe that in the long term, there needs to be a significant additional capacity built into New England. And we obviously, in Tennessee, have the pipe to do that or the base to do that. That depends again on shipper commitments. We'll just see where that comes out. But we think there's additional volumes to go to into Canada. And as I said before, our belief is that eventually, virtually all of Eastern Canada will be served out of the Marcellus and the Utica. Again, our pipeline network lends itself very well to that. I think we'll have some announcements pretty shortly on that. And then, of course, there is a takeaway for the Y-Grade to get the NGLs out, and we think that there are a lot of opportunities for us there. So we're very happy with the kind of footprint we have in the Marcellus and Utica, and we think we're going to be able to use that to our advantage and to help our customers over the next several years.

Or do you -- is the demand for takeaway -- are you sensing that the producers are willing to sign up for capacity more or is this more going to be a demand pull from the utilities or power generators?

I think on the New England expansion, it's going to be primarily demand pull.

Our next question comes from Craig Shere from Tuohy Brothers.

Looks like SACROC was off second quarter in a row, Yates was down sequentially, and the Katz ramp is still a little under budget. Do you all still feel comfortable production will grow over the next couple of years? And is permitting for new field injections becoming an issue?

I'll have Jim Wuerth. The answer is yes, we do. And, Jim, I'll let you answer that.

Yes, I think SACROC is always a little up and down. So I might mention that it is, as of right now through October, running close to 32,000 barrels a day. So a lot of it just depends on how quick we're able to get patterns ready, get the injection permits and monitor the flood. So it's going to be up and down. But I expect SACROC to continue to be relatively flat for several years to come. Yates is a big field that is on a slow decline, and we'll work it as well as we can, but there'll be a slight decline there each year. And Katz is running, as Steve mentioned, about 30% to 50% right now for the month, so it's getting real close to the budget numbers. And I think what we're going to see at Goldsmith is we've got great opportunities there. In 10 years, there'll be a lot of opportunities, I think, out there for CO2 flooding. The demand is still real high for CO2, and that bodes well for us.

And is contracting -- not contracting, permitting becoming an issue as far as being able to move forward on some of these opportunities?

Right now, we're having a little problem at the railroad commission, just a lack of staff there, but nothing we aren't able to work around, I think.

Okay. And while I'm on the subject of EOR, a simple question for you. If all of EOR's CO2 needs were acquired from third parties, do you believe that you would, in fact, capitalize more CO2 purchases and book higher DCF than you're reporting now?

We would have recorded higher capitalized CO2, that's correct. If we were selling the CO2 to third party just on our S&T side, we would have had a higher DCF.

I got you. So the intercompany sales results in more conservative accounting?

I believe that's a good way to say it.

Okay. And last question, given some of the recent headwinds kind of affecting KMI's share price from some market perceptions, how do you think about the alternatives of repurchasing warrants versus existing shares? And how much capacity do we have to keep renewing these equity repurchases every quarter?

Well, we look at that based on growth projections and based on what we believe the return is on purchasing warrants versus shares. And as you see today, the board authorized an additional $250 million to be used for either shares or warrants at our discretion. And we just continue to look at what makes the most sense, to buy back shares or buy back warrants.

I got you. And speaking with some clients, Rich, the comment was made that your own repurchases were not a large percentage of your annual distributions that you got. And I just wondered if you'd like to opine on the value of the equity right now.

That's, of course, you guys' expertise, not mine. But I believe, obviously, the equity is undervalued at KMI. You have a stock that is yielding 4.5% now and has growth of 14% this year in declared dividends. We've said we believe long term it's 9% to 10%. And at KMP, you have a security that's yielding 6.5% with growth of 7% this year. We've said long term, we believe 5% to 6% there. So to me, that's a very good investment, but that's, again, not mine to opine. I'm obviously prejudiced. I think the stock and units are tremendously under priced in my view, but again, that's for the market to determine.

Our next question comes from John Edwards from Crédit Suisse.

Just if I could follow-up on the -- your Y-Grade pipeline from the Marcellus. With the production there, it seems to be continuing to ramp faster than most expect. At least in the past people have said there's this room for one of these pipeline projects to come to the gulf. Do you think if things continue in that direction, there might be room for 2 projects?

Well, it looks like...

Yours and a competitor.

Yes, I would say, John, that's possible, but we can't look at it that way, and we won't look at it that way. We're going to get out there and compete and see if we can get the first project. The thing you have to keep in mind is it's not just the first pipe that goes into the ground. There's expansion capabilities and things like that. And so there's definitely an advantage to being the one, the first one, that gets built of these 2. And so we're just looking at it as it's one or the other is going to win the day. And the other thing to take into account, and I know you are very familiar with this, but production targets or expectations and actual production on the one hand versus willingness and ability to commit contractually for a long term from the other are 2 different things. And so what it comes down to is whether people will put ink on paper to sign up for the capacity.

[Operator Instructions] Our next question comes from Kevin Kaiser of Hedgeye Risk Management.

Question on CapEx for gathering and processing. What is CapEx budget for gathering and processing on a quarterly basis, including Copano?

I don't know if we have that number broken down.

We don't break it out separately. It's just part of our natural gas CapEx.

CapEx on Copano and Altamont and some in Texas, some in other -- in Texas as well, but we don't have a breakout of that.

Okay. So no breakout for GNP by sustaining CapEx versus expansion CapEx either?

No, I think that's just aggregated in our total gas group.

Yes. Total Natural Gas segment aggregates all of the -- whether sustaining CapEx or the expansion CapEx is all aggregated.

Okay. And then on the company-wide, so the budget for this year for sustaining CapEx will be $339 million, that's before Copano. If KMP only spent that on an annual basis, so no organic expansion CapEx, how would this segments perform over the long term? Would the company be able to keep cash flow flat?

I'm sorry. I don't...

Yes, well, I think that we have grown -- I mean, are you asking if there is growth absent spending CapEx in KMP?

The question is really if the budget was only limited to the sustaining CapEx, would the additional asset base be able to -- would it be maintained, would the cash flows be maintained over the long term for 3 quarters[ph]?

Oh, I see your question. Yes, and we've said this several times and these are ballpark numbers, of course. But generally speaking, that 5% or 6% this year happened to be 7% growth in distributions. We think probably 1.5% to 2% is organic growth. In other words, if you didn't spend any capital, you would get that. At KMP, that comes from a number of things. One is, of course, the inflation escalator that we have on our FERC-regulated Products Pipelines. Second is on automatic escalators that we have on some of our terminal assets. So you probably have, we estimate, 1.5% to 2% growth if you didn't spend any capital. And then the rest of that growth comes from -- primarily from new projects that come online.

That will be subject to market conditions. Market conditions determine the growth on the -- just the existing asset base on the stand-alone basis.

Right. And how would 1% to 2% organic growth be possible with just $339 million if you spend about $400 million in E&P alone, and that's not in the sustaining CapEx budget?

As I've just said, I'm not following your question, I guess. You asked how much organic growth you had without expansion CapEx, and that's the kind of number that we use, about 1.5% to 2%. Kim?

Kevin, is your question if CO2 production would stay flat if we weren't spending expansion capital?

No, the question is really if you -- yes -- no, the question is on the business -- the entire KMP business, how would cash flows trend over the long term if we only spend $339 million a year in capital expenditures?

Then I think Rich just answered it.

Okay. And then the last question I have is do you consider distributable cash flow to be synonymous with free cash flow?

So that, I mean, Kevin, I mean, look, what we're looking at is how much cash flow that the MLP generates before expansion capital, because our partnership agreement requires us to finance expansion capital to distribute everything that we generate and to finance our expansion capital. And so what we are comparing distributable cash flow is to the cash flow that we have available for distribution to our unitholders before we factor in expansion CapEx.

Okay. So it's -- you would say it's not -- you would not say that free cash flow and distributable cash flow are the same thing?

If you're defining free cash flow as cash flow after expansion CapEx, then I would say that distributable cash flow and free cash flow are not the same thing. But it depends on how you're defining free cash flow.

I would define free cash flow as cash flow from operations minus the capital expenditures needed on an annual basis to maintain those cash flows from operations.

Well, that is not -- unfortunately, that is nice that you would interpret it that way, but that's not the way that our partnership agreement defines it. And therefore, that's not the way we are allowed to segregate it.

Our next question comes from Becca Followill from U.S. Capital Advisors.

Can you talk a little bit about the interim outlook for EPB post '13 but before the Elba export facility comes online given the roughly $80 million in rate reductions with these 2 rate settlements at WIC and SNG and then a step down in rates at SLNG at year end?

Yes, there's no question that -- and we've been very clear about this that, of course, the rate case on SNG and the rate case on WIC will be a negative impact. We settled both of those, and they had some negative impact, as Kim said, in 2013, but that will increase because we'll have a full year at '14. We, of course, have -- longer term, obviously, the Elba Island LNG project is a huge positive. And we have some other smaller growth opportunities coming online in EPB. And then we anticipate we will have drop downs into EPB that will help in terms of distributable cash flow.

So there'll be drops. In the interim that'll help bridge that gap?

That's true, Becca.

Okay. And then what is the timing for filing for abandonment of Tennessee of the portion of the line that you're looking to convert?

Do you have a time frame?

I mean, I think we'd be looking at that into early next year.

Early next year would be the probable answer.

And then the last question on the CO2 business. Just by my quick back at the envelope on the numbers, it looks like operating expense was up pretty materially during the quarter. Was there something unusual there? Is that just a function of maybe adding Goldsmith? Or is there something else going on that's maybe short-term in nature?

Jim?

I would guess it's probably Goldsmith. We haven't seen anything unusual that has popped up on us at all.

Did they have materially higher per unit O&M cost?

It depends on what you're comparing it to. If you're comparing it to Yates, the answer would be yes. If you're comparing it SACROC, probably comparable.

Okay. Just on the overall average basis, it just looks like it's up meaningfully.

There are no further questions at this time.

Okay. Well, thank you all very much. We appreciate your time and attention. Have a good evening. Thank you.

Thank you for participating in today's conference call. You may disconnect at this time.