金德摩根 (KMI) 2014 Q1 法說會逐字稿

Welcome to the Kinder Morgan quarterly earnings conference call.

(Operator Instructions)

I would now like to turn the call over to your host, Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. You may begin, sir.

Okay. Thank you, Holly. As usual, we will be making statements within the meaning of the Securities Act of 1933, and the Securities Exchange Act of 1934. We will be referring to Kinder Morgan Inc as KMI, to Kinder Morgan Energy Partners as KMP, and to El Paso Pipeline Partners as EPB, and we will cover all three.

Let me kick it off by saying we had a very good quarter, and we're on track for a very good year. We expect all three of our entities to meet or exceed the distribution or dividend targets that they have for the full year.

I'm going to mention just a few significant matters, before turning the presentation over to Steve Kean, our Chief Operating Officer, who will talk about specific performance of our business units, and also about our backlog, and then to Kim Dang, our Chief Financial Officer, who will go through the details of the financial results for the first quarter.

Let me start just with a high-level view of our operating performance. Three or four things come to mind. We had extraordinary gas throughput during the first quarter, and we moved what we think is an all-time record for us, 33 Bcf a day during the month of January on average, and that's about 33%, or about a third of all the natural gas consumed in the United States during that month.

In our refined products group, we actually had a pretty nice increase in refined products volumes. We were actually up 5.3% if you count our Parkway project, I think it's fair to strip that out. If you strip that out, we were up 3.7% in refined products volumes, and that's versus an estimate from the EIA of 1.1% across all of the United States.

Over in our CO2 segment, we had another very nice quarter at our SACROC unit, where the oil production increased by 4%. Lifting the overall oil volumes in our CO2 segment, allowed it to be up by 5% overall, and on a GAAP basis, net to our share, up 7%. But I think SACROC is a more meaningful number, because we did have some improvement in some of our newer start-up projects, also.

In our terminals, we had a very nice increase in earnings the DD&A, driven by both new projects coming online and organic growth, as well as the tanker APT acquisition, which was closed in January of this year.

On the business development front, we had an outstanding quarter. Steve will discuss the project backlog, which increased by $1.6 billion during the quarter, notwithstanding the fact that we put $800 million out of the backlog into service during the quarter, so we really generated $2.4 billion worth of new backlog projects, and most of the increase came in the natural gas business segment.

Now as you look across Kinder Morgan, we like to think that there are many opportunities to grow our business, across all of our business segments. But if you look back a couple of years to when we made the El Paso acquisition, that represented a huge investment on our part, based on the future use of natural gas in the United States, not the price of natural gas, but the supply-demand equation for natural gas.

And we felt at that time there was going to be a tremendous need for capacity to transport natural gas around the country, as both the demand and supply side grew, and it represents an enormous long-term upside for all three of the Kinder Morgan companies. So I thought it would to spend a little time sketching out for you my view of the national market, and the significant recent impact on our pipelines, in terms of new long-term agreements with customers to utilize our system.

Some of you may have seen that Wood Mackenzie just put out its spring 2014 preliminary outlook. In that outlook for natural gas supply and demand, they estimate that demand this year the United States will be 71.5 Bcf a day, and they projected by 2024, in 10 years, that demand will escalate to 94.5 Bcf a day, or an increase 23 Bcf a day, and we would view that as a real understatement because the way WoodMac computes this, they actually have the increase in Mexico, exports to Mexico, as a deduct on the supply side rather than an increase on the demand side.

So really, this 23 Bcf per day potential increase, in our view, is a little bit understated. That is coming from a number of sources, all of which we have discussed before, but LNG exports, additional electric generation fueled by natural gas, an increase in industrial use, and then an increase in exports to Mexico. All of these, we think, bode very well for a national pipeline network like us.

A couple of other facts that have come out very recently, that I think are also important from a national basis, is that you may have seen a recent article that we now have $70 billion of announced US petrochemical development, almost --the great bulk of it along the Gulf Coast in Texas and Louisiana, where we have a tremendous pipeline network. You may have also seen just in the last couple of days, the estimate for May, Marcellus-Utica production, approaching 15 Bcf for the month of May 2014. The same WoodMac study that I referred to on the supply side sees that increasing to 28.5 Bcf in 2024, or a net increase of about 13 Bcf a day.

Some of these are pretty much mind-boggling figures. Another is that INGAA recently commissioned ICF to do a survey of infrastructure needs over the next 20 years. They projected that infrastructure needs would require $641 billion of investment between now and 2035, an average of about $30 billion a year.

Now, not all of this is natural gas, it's overall infrastructure, but the relevant thing, I think, is that's versus and 2011 estimate that INGAA had, which turned out to be $10 billion a year, a tripling of potential investment. All of these facts, I think, are very relevant to saying that we're at the beginning of what we view as a tremendous upswing in the need for natural gas transportation in the United States.

Now, you would expect us, as the largest owner-operator of natural gas pipelines, to benefit from these nationwide trends, but the real issue that you ought consider is are we benefiting, and what specific examples do we have to talk about that show Kinder Morgan's benefit. Let me give you some numbers.

Since December of 2013 we have executed long-term binding contracts with an average life of approximately 15 years, for about 2.8 Bcf a day. These are binding contracts, over 1.4 Bcf a day is on our Tennessee system, and about 800 million a day is on our El Paso natural gas system in the West.

In addition to that, we have executed a long-term contract to supply still another Gulf Coast LNG terminal, with volumes estimated at 700 million cubic feet a day, contingent on final FERC approval of the project, and we had three very successful non-binding open seasons. One on NGPL, to move gas from the REX Interconnect in Illinois with NGPL, to the Gulf Coast, and two on our Tennessee system for Northeast capacity. All three of these open seasons were vastly oversubscribed, and we are now working to advance those projects.

Again, I want to emphasize those were non-binding open seasons, but the results we received were very encouraging and very positive. I think two points come home, very clear, and very important.

The first is that Tennessee is now on its way to becoming a bifurcated system, with gas moving from the Marcellus-Utica to the Northeast, and also from the Marcellus-Utica to the Southeast and the Gulf Coast, and this will only increase as the production in Appalachia increases. Secondly, EPNG is filling its previously underutilized South line, largely with exports to Mexico, and will be expanding the system later this decade, to complete the demand.

All-in-all, we see all of these events and the national statistics, for that matter, as a very positive trend that will drive growth at Kinder Morgan in the years to come. And with that, I'll turn it over to Steve.

Thanks, Rich. I'm going to give an update on the backlog, and then go through the segments quickly. So starting with our January investor meeting last year, we have been giving -- we rolled out our backlog, and have been updating pretty much every quarter since then.

As Rich mentioned, we went from $14.8 billion to $16.4 billion across all of the industries on a combined basis, so we added this $1.6 billion to the backlog, also putting in service over $800 million worth of projects. Our project additions grew total backlog, while offsetting the projects we put into service. Among the larger projects we put into service were the $100 million KMP Sweeney lateral, to serve the Philip 66 refinery there.

Almost $500 million worth of terminals group projects went in, including phase 1 of our Edmonton terminal expansion, an expansion in our Pasadena and Galena Park facilities, and some coal export facility expansions. We also had about $150 million worth of projects come into service in the CO2 segment during the quarter.

Now, a reminder about the backlog. It consists of those projects that we view as highly probable, highly confident they will get done, not a guarantee, but a very high probability. We actually expect to add to this, and do more, and invest more capital than what we have in the backlog, but unless we have a project that is highly probable, we don't add it.

So here's the business unit composition. The gas group is up from $2.7 billion to $4.1 billion. That $1.4 billion by far the biggest increase across the business units.

The other biggest additions were the $780 million expansion for Ontario, to increase southbound NGP capacity out of Utica and Marcellus. This demonstrates again, with a strong demand for additional capacity, and comes on the heels of an oversubscribed open season, for that same path that we had in December.

Second, we have got firm contracts supporting the $500 million-plus expansions on the EPNG systems, so it's not just Marcellus and Utica, we're seeing strength in demand for transport capacity in other parts of the network, too. The third big contributor to the increase is the expanded scope on our liquefaction project, and associated facilities at Elba Island, bringing the total to our share to $1.2 billion. That's a EPB investment, and overall EPB was up $200 million from quarter to quarter.

The products group backlog is down from $1.1 billion to $1 billion, and that's due primarily to the Sweeney lateral going into service. I want to point out here we have $300 million plus project, the UTOPIA Utica to Ontario pipeline, the NGL line, which we have an LOI on, we view it as pretty probable, hope to, and expect to firm that up and put it into backlog for the quarter, but it's not currently in the backlog.

The terminals portion of the backlog is down $300 million from $2.3 billion to $2 billion. We added about $200 million worth of projects in the terminal sector, but as I mentioned, they had almost $0.5 billion going into service during the quarter. We continue to see really good growth opportunities in this sector.

We are rapidly expanding our Edmonton position by about 50%, our Houston ship channel position by about 26%, to just under 40 million barrels of capacity. We are also in the very early days of growth in demand for midstream infrastructure, that we expect will accompany the massive build-out of new chemical facilities, primarily along the Gulf Coast.

The backlog in our CO2 business is up $600 million. SMP is essentially flat at $1.8 billion, but the enhanced oil recovery part of the backlog is up to $2.1 billion, a $600 million increase, and that's primarily our ROz, or residual ozone, new development projects. So we continue to see strong demand for CO2, and plenty of places to put it to use, either our projects or others. The biggest project, of course the last one, Kinder Morgan Canada $5.4 billion [Key of X] expansion, which is unchanged from the last update.

Now again, the segment update, and I'm just going to focus on how we came out from this quarter versus the same quarter last year, and Kim will take you through the details on all the numbers. So for the gas group, earnings before DD&A were up $226 million of KMP, [46%], so that's due to the Copano acquisition, which closed in May of last year, and the drop down of the remaining 50% of EPNG and El Paso Midstream, which closed March 1. But if you scoop those out, earnings before DD&A for the segment were still up $62 million, and as Rich pointed out, we saw strong demand for transport capacity, really across our system.

If you look at the volumes on KMP, our transport volumes were up 5.1% on a year-over-year basis. When you factor in the increase -- year-over-year increase in storage withdrawals on the Texas intrastate, which don't count on those transport numbers, that increase grows to 6.2%. And on the 2.8 Bcf of sign-up, new capacity sign-ups that Rich mentioned, it is worthy of note that a quarter of that was on existing capacity, so we signed up capacity, previously unsigned capacity, but not really requiring CapEx to get those deals done.

So that just again shows the strength in demand for transport capacity, both new and existing, and actually, if you take just one project, which had a very small amount of capital associated with it, it goes up to about a third. So very good signs of increase in transport value, that we're beginning to see.

On EPB, asset earnings before DD&A were essentially flat, up $2 million. There, it's rate case impacts on SNG and WIC being offset by positives on CIG and the Elba Express pipelines. And looking ahead, we're very bullish on the opportunity presented by natural gas, and see exports, demand from electric generation and industrial uses, and the need to transport and process gas out of channels plays, I think we're seeing customers really beginning to view again transport outlets as a value-add.

In CO2, our segment earnings before DD&A were up $26 million or 7%, higher CO2 and oil volumes, and higher CO2 oil and NGL prices. The volume was driven, as Rich mentioned, by SACROC being up almost 4%, also Katz and Goldsmith.

We had record CO2 volumes for the quarter, driven by an 8% increase in Southwest Colorado volumes, primarily due to Doe Canyon coming on. We continue to pursue several large development projects (inaudible).

On products, the segment earnings before DD&A were up $4 million or 2%. Increases in Southeast terminal and transmix and Parkway offsetting year-over-year decreases at [SOPD] and Cochin. Cochin saw lower volumes at its origin point, in Fort Saskatchewan, Alberta.

Also of note, as Rich mentioned, is our refined products volumes are up. That's a good sign, that doesn't take CapEx, you have refined product volumes going up, and some tariff escalations as well, that's an overall positive. Looking forward, we continue to see really condensate and NGL-driven growth in this sector, with projects off of our KMCC system in Eagle Ford, in addition to our Cochin Reversal Project, and then UTOPIA.

On terminals, segment earnings were up $41 million or 6% from last year. $11 million of that is due to the acquisitions, both the Jones Act and two smaller acquisitions, but $26 million was organic growth, and that's expansion projects, but also, I think, good pricing on our services. We had $7 million improvement attributable to our Gulf Coast region alone, associated with price escalations on our tanks, or on of better terms on renewal.

Other highlights here, we brought on phase 1 of BOSTCO, in the Houston ship channel we brought on phase 1 of our Edmonton terminal expansion, as well. Both of those had expansions under contract before we even finished phase 1.

Kinder Morgan Canada, finally, segment earnings before DD&A were down $4 million, primarily the result of the weaker Canadian dollar, but the main story here continues to be the progress on the expansion. We passed another milestone there, we filed our facilities application in December, and we now have the schedule and order in hand. Long story short, it's going to be a full, fair, but finite process, and we have a deadline of July 2 of 2015 for the NEB order.

And hot off the presses, we just got our first set of information requests and a preliminary statement of conditions, so things are moving along very well there. And with that, I'll turn it over to Kim.

Okay thanks, Steve. Turning to the numbers, first on KMP today, we are declaring the Board-approved declared dividend of KMP of $1.38. That's a 6% increase over the first quarter of 2013, and this is on the first page of numbers for KMP, which is on the bottom of the GAAP income statement.

On the GAAP income statement, I will point out that net income is down, net income attributable to KMP is down $37 million, but this has all the certain items, which we will outline for you on the next page. The largest one being $141 million gain on the sale of Express, that was a benefit in 2013, and obviously not recurring in 2014.

So going to the next page, and looking at our calculation of distributable cash flow, which is reconciled back to our GAAP net income, we produced DCF per unit of $1.55 for the quarter, comparing that to the $1.38 for our declared distribution. That is $76 million in excess coverage in the quarter.

As we tell you almost every quarter, we expect to have excess coverage in the first quarter and the fourth quarter, and typically we will have negative coverage in the second quarter and the third quarter, and we will have excess coverage for the full year. Right now our excess coverage for the full year is nicely above our plan, as a result of the new contracts that we've signed on TGP and EPNG, and also as a result of the APT acquisition, which is why you see us guiding to our guidance, which we will declare at least $5.58 per unit.

On the $1.55 on a total basis DCF is $693 million. That's $143 million increase, or 26% increase over the prior quarter of 2013.

Looking at what drives the $143 million increase, segment earnings before DD&A $1.569 billion, that's up $293 million, or 23%. Steve took you through the pieces, but the biggest piece of the $293 million is $226 million increase in the natural gas segment, and then CO2 and terminals also contributed nicely to the $293 million. Versus our budget for the full year, we are expecting that we will exceed our budget for segment earnings before DD&A, largely, again, as a result of the APT acquisition, the contracts on TGP and EPNG, and then that's being slightly offset by the lower volumes on KMCC.

Interest in the quarter was $149 million expense, that's $26 million increase versus the first quarter of 2013. I'm sorry, that's G&A, and that is, G&A is above our budget for the quarter, and we expected to be above our budget for the full year, by about 2%.

Interest, $228 million expense in the quarter, that's up $41 million versus last year, largely on increases in balance associated with our expansion capital program. For the quarter, our interest is very close to the budget, and for the full year, we expect it to be close to our budget.

Now you would think that interest would be higher than our budget, because we issued incremental debt versus our budget of $500 million to finance about 50% of the APT acquisition. That higher balance is being offset by lower rates than what we budgeted, and higher capitalized interest.

Sustaining CapEx, a $24 million increase in the quarter, that is -- we are right now behind our budget in terms of spending, but that's going to be timing, because for the full year, we are expecting that sustaining CapEx will be slightly above our budget, probably about 2% or so as a result of the APT acquisition, and also some additional expenditures on the Texas intrastate. So $293 million coming from the segments, increased expenses of $26 million on G&A, $41 million on interest, $24 million increase on the sustaining CapEx, and then you have the GP increase as a result of the increase in the distribution and the increase of units of $52 million. That gets you to $150 million of the $143 million increase, and then there $7 million of small other items.

On these certain items for the quarter, they were $34 million. The largest piece was legal reserves, and that was associated with two unfavorable decisions that we got, two unfavorable court decisions.

You also see there, the insurance deductible and casualty losses, $8 million, that's timing. These are expenses that will be either reimbursed by customers as we rebuild their assets, or largely reimbursed by insurance.

And then we have severance of $6 million, and that is an item that will be paid by KMI, and not be borne by KMP. So that gives you the main certain items for the quarter.

Looking at KMP's balance sheet, there is $1.194 billion increase in total assets, and the APT acquisition is the biggest piece of that, at $960 million. We ended the quarter at $20.5 billion in debt, and that results in debt to EBITDA of about 3.8 times. We still expect that we will end the year at about 3.7 times, which is consistent with our budget.

The $20.5 billion in debt is an increase of just under $1 billion, versus the $19.5 billion at the end of last year. That's actually $996 million. Just looking at the sources and uses that drive that, we have $1.76 billion in acquisitions, expansion capital, and contributions to equity investments. The largest pieces of that are $960 million from the APT acquisition, and then we spent a little under $740 million on expansion CapEx.

We raised capital of $803 million through equity offerings, and then we had a use of cash of working capital and other items of about -- a little over $40 million, which is primarily accrued interest. It's the timing of when we make our interest payments, and then we had obviously $76 million of coverage, is the biggest offset to the use of cash from accrued interest. So that is KMP's balance sheet.

Turning to EPB, its GAAP income statement, you can see there that we are declaring a cash distribution today of $0.65, which is an increase of 5% or $0.03 over the first quarter of 2013. Looking at EPB's calculation of distributable cash flow, which is also reconciled to GAAP net income, DCF per unit is $0.75 for the quarter.

Comparing that to the $0.65 distribution, we've got coverage of about $21 million in the quarter. Still more story here on coverage, we expect to have positive coverage in the first quarter and in the fourth quarter, and we expect to have negative coverage in the second quarter, and probably slightly negative coverage in the third quarter. And for the full year, we expect to have positive coverage, and be on our budget.

Total DCF, $163 million, is down $6 million or 4% versus last year, and just reconciling that $6 million for you, earnings before DD&A, up $2 million versus last year. Steve took you through the reasons for that, G&A is flat, interest expense is actually down, meaning reduced expense versus last year of about $2 million, and that is a result of maturing debt being replaced with lower rate debt. Sustaining CapEx is about a $1 million increase in expense versus last year, and then the GP is about a $7 million increase in expense associated with the higher distribution per unit and more units outstanding, and then you had other items of about $2 million to get you to your total change in DCF of $6 million.

Looking at EPB's balance sheet, EPB ended the quarter at $4.1 billion in debt, which results in debt to EBITDA of 3.7 times, and consistent with our budget, we still expect to end the year at about 4 times debt to EBITDA at EPB. The $4.112 billion in debt at the end of March is a decrease of about $66 million from year-end, and to reconcile that decrease for you, we had about $17 million in expansion CapEx and contributions to equity investments.

We have raised equity of about $36 million, and we had working capital and other items that were a source of capital of about $47 million. The two biggest pieces of that being a source of working capital on accrued interest, and then coverage was $21 million in the quarter.

Finally, turning to KMI, KMI we are declaring a dividend today of $0.42. That is a $0.04 increase, or 11% over the first quarter of 2013. Cash available per share is $0.55, which is a 12% increase over the first quarter of 2013, and $0.55 versus the $0.42 results in about $138 million of coverage, similar to KMP and EPB, we expect to have positive coverage at KMI in the first quarter and the fourth quarter, negative in the second and third, and positive coverage for the full year.

Right now, we expect that our coverage will be slightly above our budget, and because we will be slightly above our $1.78 billion in cash available to pay dividends, and thus you see the guidance in the press release to meet or exceed our cash available to pay dividends. $573 million of cash available to pay dividends in the quarter is about a $60 million increase, or a 12% increase versus the first quarter of last year, and just breaking that down, the cash generated from KMP and EPB, so our investments in the two MLPs is up about $69 million as a result of the increase in the distributions at those MLPs and the increase in the unit count.

Cash generated from other assets is down about $11 million, as a result of the drop downs to KMP in the first quarter of last year. G&A is reduced by about $2 million versus last year. Interest expense is reduced by about $6 million, $160 million of expense, and that's a result of the pay down in debt from the drop downs, and then cash taxes are higher by about $6 million, to get you to your $60 million.

So we had a nice quarter at KMI. We are slightly ahead of our budget in terms of cash available to pay dividends, largely as a result of outperformance by NGPL and Citrus, and we expect most of that to carry through for the full year.

Looking at KMI's balance sheet, KMI ended the quarter with just over $10 billion in debt, and we still expect that we will end the year with debt to EBITDA at KMI on a fully consolidated basis at about 4.9 times. Debt increased about $181 million in the quarter, just going through the sources and uses.

Share repurchase was a use of cash was $94 million, warrant repurchase was a use of cash of $55 million. We made a pension contribution for $50 million, we had payments in the legacy El Paso marketing book and on some environmental expenses of about $30 million, and then cash available versus the cash actually received, there is a difference there of about $67 million, $22 million on that is the fact that we didn't sell the KMR units, and then the balance is timing on cash distributions we receive out of equity investments.

And then we had a source of working capital of about $117 million from other items. The largest piece of that is the $138 million in coverage for the quarter. And so, with that, I'll turn it back over to Rich.

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

(Operator Instructions)

Bradley Olsen, Tudor Pickering.

Quick question. On the Tennessee gas reversals it seems like you have been able to line one of these major bidirectional or reversal projects up on TGP every few months, and it seems like your projects are generally able to go from planning to realization faster than a lot of the other pipelines in the Northeast. How many more potential reversals could we see out of TGP, and would the reversal for the potential reversal for the NGL Y-grade pipeline down to the Gulf Coast impact how much of the pipeline could be used in a gas reversal?

I'll turn it over to Tom Martin, who runs our natural gas pipeline group.

I think we certainly have the opportunity to look at more backhaul or southbound capacity, and yes, there is capacity that we are creating for the NGL project, that ultimately, if that doesn't go, we could use that for additional gas service as needed. We are also very excited about the results of the non-binding open season to take Marcellus gas ultimately into New England.

Between those two projects, we could see anywhere from 1 to 1.2 Bcf a day incremental volumes going into the New England market, so we think growth from the demand that we are seeing southbound, as well as the interest to go to bring additional volumes into New England, we're very excited about our growth prospects, going forward.

Great. Thanks, Tom. And I guess just to maybe push a little bit harder on the Northeast reversals, is there a number we can think about, in terms of potential additional reversals on TGP, or is it difficult to give a precise number?

It all depends on what rates the market ultimately will bear, but I think, relatively speaking, the lower-cost expansion projects have been done, but I think we're continuing to see interest even at higher levels, so it's hard to speculate on volumes. But I think, we're certainly talking to our customers everyday, and there's still interest for more capacity.

I think again, Brad, the key thing here is, if you just look at these numbers, the numbers tell the story. Again, we expect to cross 15 Bcf of production this quarter, up there. There is not nearly that much demand, particularly at this time of year, in the Northeast.

If you look at this ramping up, in fact, Wood McKenzie would show it ramping up just in five years to 22.5 Bcf, so ramp up of 7 Bcf just in the next five years, and those volumes have to go someplace, and of course what we have is we have essentially, this is a little bit of a simplification, but essentially four big lines that were originally intended to go South and North.

We have, in essence, reversing two of them on what we've done so far, so there's more opportunity, but Tom is right, the further you get, the more expensive it gets, and we just have to see whether people are willing to pay the freight. But obviously, there's a tremendous need for more capacity to get natural gas, as well as NGLs out of Marcellus-Utica.

Great. And just one last one from me, on the natural gas front. Sounds like there's a lot of growth potential coming out of Mexican demand, and I would imagine, given the fact that country continues to import high-cost LNG, that could be a real growth market. When we think about how big that volume opportunity could get, are there limitations on the southern side of the border with PEMEX's pipeline system, or do you see quite a bit of running room to continue to expand exports southbound?

I think they will continue to expand their infrastructure South of the border. And the real test of that is, when they sign up for long-term contracts on our side of the border.

So, I think, we believe that over the next 10 years, demand will more than double from the present throughput that goes into Mexico today, and the reason is very simple. They are converting electric generation and industrial use of a form of natural gas, the opening of the energy business in Mexico, we believe, will concentrate primarily on oil, not on natural gas.

And the only alternative, as you switch to natural gas, is to import LNG, which is very expensive, and of course that led to, I don't know all the details, but essentially the closing of the Altamira plant, which I think was a mutually beneficial thing from both the Mexican importers and Shell, that could take that LNG and move it elsewhere. So the cheapest source of natural gas is clearly from Texas and the rest of the US, I think you'll see some Rockies gas, in fact, going into Mexico, and of course EPNG is just, again, if you think about Tennessee being ideally positioned in the Marcellus-Utica, EPNG is tremendously well-situated for the exports to Mexico.

There is one other point there. They are building out the infrastructure South of the border. It's not dependent, though, on PEMEX getting it done, so when CFB is -- these power plant development that they are putting up, they are having -- private companies coming in to develop and build out the transportation capacity that's going to be acquired South of the border to get it from our line basically to the power plants that are being sold.

Great. And when we think about $800 million of demand on EPNG for those new contracts that you mentioned in the press release, is it fair to assume that most, if not all, of that volume is coming from demand South of the border?

Yes.

A high percentage of it.

Some of it.

In addition to that, we think there will be significant additional opportunities. We think the $800 million is just a starter.

Great. Thanks so much, everyone.

Darren Horowitz, Raymond James.

Two quick questions for me. The first, regarding that March announcement that you made of additional $1 billion of CO2 investments.

If I'm just thinking about the $700 million that's going to be focused on drilling wells and building out that fuel gathering infrastructure at St. John's, can you give us a sense of the average unlevered rate of return across that project set? And am trying to think about it with regard to how that compares to the average unlevered IRRs on that $1.5 billion in EUR backlog CapEx that you outlined at the analyst day, over the next five years.

Jim Wuerth?

I think unlevered, we're looking in the midteens on the pipe, and in the infrastructure there. I think that's where it is, midteens.

Okay.

We'll be building a new pipe from St. John's over to the intersect with our Cortez system, just south of Albuquerque.

That's correct.

And overall, we think we will be in the mid to upper teens on the returns on that $1 billion investment.

Do you think, Rich, though, that just based on the large upfront capital that you have spent there, that your incremental returns theoretically should get better?

Well they could. It just depends on exactly how the contracts work out in the end.

Obviously, if you look at McElmo Dome 30 years ago when Shell and Mobil operated it, they had to make a decision to put in the Cortez pipeline. It's very expensive when you put that first build in, and the numbers don't look that great.

In today's world, it looks like a great investment. We have had it now for close to 14 years, and the volumes just continue to go up, with not a lot of infrastructure being added on the pipe. I think you'll see the same thing within St. John's in the Lobos pipeline.

Okay. And then last question for me, Steve. Back to the products pipe segment, and that growth in cash flow that you talked about, as we're thinking about the back end of this year and into the first half of 2015, can you give us an update on KMCC capacity utilization?

I know that we talked -- last time you said it was about two-thirds booked, but obviously there's this big supply growth of South Texas condensate that's moving east, so I'm wondering from your perspective how you think about -- if you do change the scale or scope of that $1.8 billion of capital that you're going to spend across the ship channel, so maybe some additional ship docks at Galena, or more interconnects between Galena and Pasadena? It seems like there's a lot of opportunity, and you could spend more money, so I'd love your thoughts there?

You're right, and capacity utilization tends to be -- is still running well under contractual commitment, so one thing to understand there is that we're getting cash in now, in deficiency payments, but we're not able to reflect that in our current results until we get -- either they start moving the volumes, or their makeup rights expire. So that's holding back the performance of KMCC a little bit, but again, the cash is coming in the door.

But you are exactly right. The way that system has now been developed, it has gone, in a very short period of time, it has gone from a point-to-point system to being a network. A network that we can build off of, and that we can invest and invest in, at very high returns on those incremental capital equipment.

So we have about $300 million of laterals and associated facilities like truck offloading and tank facilities that are in our backlog, that we haven't yet seen the revenue on, those are a fairly quick build outs that we can do, and we are doing. And I think we're going to continue to find more of that, and John, do you have anything to add to that?

I think there's a lot of optionality. Once it gets to the Houston ship channel, we can move it to petrochemical plants. (inaudible) I think there's tremendous flexibility for shippers and the rest of that capacity will go pretty soon.

Another example of that, so we had one lateral that we were able to get in-service early, but we don't have the pumps and the other facilities that are going to be necessary to achieve the full throughput. Well, we're unloading trucks into that lateral right now, and we will just ramp that up over the coming year. If you look at that system, it is now connected to multiple producers, CEPs, and also truck offloading facilities.

Connected to multiple producers and we can now take it to multiple markets. It goes to the Phillips 66 Sweeny refinery, just south of Houston, it goes to the Houston ship channel, and we're connecting it up with Double Eagle so it can go to Corpus as well, so just a great network that allows high return projects to be built off of it.

Thank you.

Brian Zarahn, Barclays.

I appreciate the project backlog update. What's the status of the Y-grade line, the Marcellus-Utica, where do we stand?

We continue to work on it, but we don't have commitments yet, so we are not putting it in the backlog. There's some indication from the market that people have been very focused on getting some of their dry gas outlets taken care of first, and then they are going to turn their focus and attention to additional liquids or NGL outlets.

I would say that the interest in the project continues to grow, so the update for the quarter, as people are interested, and more interested than they were the quarter before, but until that turns itself into signatures on contracts, again, it's not going into backlog, and we're not going to call it done. As Tom pointed out, we do have the ability to use that line, we are preserving the ability to do both, and that's our preference.

We want to do residue gas outlets on the TGP system. We want to preserve the Y-grade option, assuming customers are willing to sign up, but if ultimately they are not, then we can put that line in residue gas service and put it to good use that way. So long story short, we don't have the commitments we need yet, but I think interest from the customers continues to grow, and we will keep working on it.

And I guess that and the other projects that are not in your backlog, how should we think about the potential growth in the inventory through 2017, as some of these projects are added? You're currently at $16.4 billion. Could we get to a $20 billion number, or how should we think about the range of potential outcomes?

As you know, we are being very conservative about that. Different people take different approaches to how they articulate their backlog. People sometimes put in projects they think ought to get done or have good reason to get done, but we tend to put in the ones that are just very high probability.

So for example, UTOPIA, I think, is a project that gets done, but we're not quite there yet. We got to have an open season, we got to firm that LOI up into a real firm transport commitment, that's another $300 million-plus project there. if you remember from investor day, Tom articulated about $15 billion worth of projects in the natural gas sector alone, which includes and we keep adding on to what we've signed up here recently on EPNG, maybe getting a couple of those Northeast expansion, both of the Northeast expansion projects we did the non-binding open season in.

Those are $1 billion, multi-billion dollar moves or additions to the backlog, but again, we're going to continue, I think we're going to maintain the same methodology here. We'll identify some of those things for you, but we're going to keep the backlog limited to those things that we are highly confident we're going to put in service. [Here to say] I'd be highly confident that we will put in service.

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

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

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

We maintain the discipline under our hedging program, and we hedge whatever the price is, and obviously in a backwardated market, that hedge price in the outyears is lower than the front end. We believe that will probably change, but we're not in the business under our hedge policy of guessing on that, so we stay within our parameters.

Obviously, within those parameters, we try to pick off the days when the out years are a little stronger, but we're maintaining that, as we always do. We have -- we are more heavily hedged, obviously, in the front end, than in the back and.

And last one for me. On the warrants, how many are outstanding at the moment?

317 million.

Thanks, Kim.

Ted Durbin, Goldman Sachs.

Just want to come back to gas here and maybe again push a little bit more on, what's the incremental capital you think you need to put in, to free up, say, another Bcf a day of volumes up out of the Marcellus, to get to the Gulf Coast?

Tom?

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

Okay. And then, can you give us any more color around whether it's the most recent supply project, the project with Entero, or the future ones. How you're thinking about the option value of the capacity you have. Would you charge max rates? Should we expect negotiated rates that would be higher than what is on file with the FERC?

I think you can expect that on all our new products, these are negotiated rate contracts.

Got it.

It would be higher than an unfiled tariff, because they have to justify the capital expenditure.

Right. Got it. And then, if we're thinking about -- this is a small one, but just the impact of weather on some of the volumes, maybe in the gas segment or any other segments, can you quantify that are all?

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

I think that's the key. Rich is talking about the 2.8 Bcf, those contracts, those were 15-year average commitment, or nearly 15-year average commitment, so it's not about the weather. That's not about a cold winter.

That's about long-term need, or long-term demand for capacity. I think we saw benefits from the colder weather, certainly on the Texas intrastates, we saw it on NGPL, the NGPL asset. On a lot of our other assets, interstate assets, we're pretty much looking at demand charge, primarily demand charge-based revenue receipt, so it's a little less weather-dependent in the short run.

Again, everyone got a real wake-up about the need to hold firm transport capacity this winter, I think again that holds promise for demand for future capacity, and maybe for some of the expansions into the Northeast, for example, but that's not really a short-term phenomenon, that's really just driving long-term demand for transportation. And as I mentioned, we had record or very high storage withdrawals on the Texas intrastates, and some good sales opportunities for us there, as well.

Great. I'll leave it at that. Thank you.

Craig Shere, Tuohy Brothers.

Let's stay on the potential growth opportunities. Can you just update us on the FERC application at Elba, prospects for securing FTA-based exports contracts for Gulf LNG, and if you're any more optimistic around non-FTA authorizations, now that I think Elba is sixth in line and Gulf LNG is seventh, and Russia is saber rattling?

On the FERC application, we have filed a FERC application for Elba now, and of course, remember that's not contingent -- that's only contingent left is getting the FERC approval, because it's not contingent on non-FTA approval, although we think we'd like to have that. That would give our customer, Shell, a little more leeway, and includes the LNG out of Elba. But we filed, and are really [involved] on that, so that's a go.

On Gulf LNG we and our partner there, which is primarily GE, have now authorized the money on the pre-feed expenditure. We have a lot of interest there, and we think by the time we complete the pre-feed, we will have MOUs signed for that capacity at Gulf LNG.

Now, let me be very clear that MOUs are MOUs, and that doesn't mean they are fully binding on either side, because we will certainly want to go beyond a pre-feed to nail down the cost of the project, and our customers will want to nail down the cost of the tariff that's going to be charged them, but I think we've turned more optimistic on that, and we and GE together have decided to go forward with the pre-feed, based on the conversations we've had over the last two or three months.

I think this whole LNG export market has become a little more interesting. I don't know if they're going to move up the rapidity of approval on non-FTA requests, given what's happening in Europe. I would think they should, and that, as others have said, they should use FERC as the clearing agency, as opposed to DOE making decisions.

They should just approve everybody and let FERC sort it out, and let the contract world sort it out, but we'll see how that turns out. But we believe that Gulf LNG does have some potential, and more to come on that.

I think it's the only thing I would add is Gulf LNG is the last remaining brownfield expansion opportunity, and I think with our balance sheet, I think the customer response and interest has been very positive so far.

Great. And if I can get Jim for a second, looks like your production fell 1.5% sequentially, but obviously LTE up year-over-year. Can you provide any color around the progression of production this year, and do you have any updates you can share about potential CO2 supply sales into California, Yates, NGL flooding, or ROz?

The volumes, SACROC and [Cinda] used to be strong, month-to-date, we're still running about 32,000 barrels a day. And Yates, it's a slow decline there. We are trying to do we can, to maintain that is best we can.

The other two new ones, are both responding pretty well. The last few days at Katz, we have been close to 4,000 barrels a day, and at Goldsmith, we're over 1,500 barrels a day, so both those are moving up. So I think the outlook on the crude side is, volume is still real good.

As far as potential of CO2 to California, obviously, that's going to be a long haul project. We do have some interest out there from some customers.

We've signed some documents there, but the proof will be in the pudding, on can you get approval to move CO2 into California? So that's where we are working today. As far as the Yates hydrocarbon municipal project, we should be kicking that off here this quarter to test the pilot on that, and based on the results of that, we will move that forward.

And anything on ROz that you can share with us at this point?

Obviously, we have done some additional appraisal drilling, and continue to be very bullish on what we are seeing. We are actually out in the phase 1 area now, drilling. We started our first couple wells out there, so hopefully, we should have something where we are injecting CO2 by the end of the year.

Okay. One general question. When you say that CO2 is recycled over many years, each time it's not the same quantity right, so you are getting 30% to 50% each time. So ultimately, when you buy 100 million cubic feet of CO2 to inject, how many times do you think you're going to inject that? Is it twice, or three times?

One of the ways you can look at it is, on a normal field, you have to purchase about six Mcfs per barrel of oil. What really happens is, you have about 11 to 13 times that you inject volumes of CO2, so about double, a little over double. Basically, it rolls through at least twice.

Okay. That's very helpful. And, last question. Back to Rich, if Jim does as well as it sounds is possible in the ROz effort, and EUR is still looked at as a negative overall for KMP, could you see an argument long-term for why the broader CO2 segment may make more sense to trade separately, than, say, an EPB?

EBP, you mean as a separate MLP?

Well people always ask you once in a blue moon, would you ever consolidate EPB? Obviously, that make some sense over time. The question is, if it's getting no respect and it's laying down the rest of the business, and there's other natural interested investors in it, why long-term, wouldn't we just have a good portion of CO2 just trade separately?

Well we look at all alternatives, certainly. There is a lot of issues on what the tax basis would be, if you split it out. A lot of issues with doing that separately, and we are fairly bullish on the CO2 business right now, and not be the appropriate time to do something like that.

You saw at the analyst presentation the uptick in distributable cash flow we expect from those operations. You know it's unique entity because everybody right now is in love with the Permian Basin in terms of E&P activities there. Well, that's where we are, but the thing that separates us from most other people is we have our own in-house supply of CO2, which we certainly will and can sell to third parties, but we can also use for our own efforts.

Which gives us, I think, a tremendous leg up on being able to continue to grow things like the ROz, if that turns out. Certainly SACROC is just a big deal and seems to be getting bigger.

We're just really pleased with the way everything is going there. So we are very pleased with it. Again, we always consider all kinds of alternatives at Kinder Morgan, but we think CO2 is a good fit, the way it is.

Great. I appreciate the answers.

Mark Reichman, Simmons.

With all of the opportunities in the Natural Gas Pipelines segment, I was wondering if you can provide an update on investments and the partnership's coal terminals, and also by Kinder Morgan Resources. And somewhat related, I think the 2014 budget called for about a 23% increase in coal export volume, due to increased capacity along the Gulf. Is that still your expectation in light of the weak met coal pricing?

John Schlosser runs our terminals group. John?

We have actually a budget of 27 million tons. As we mentioned at the analyst meeting, 25 million of that is under a long-term take-or-pay. We were off slightly on tonnage in this quarter, 1.3 million tons, but we were actually up $2.3 million over our plan, owing to shortfall payments from our customers there.

We did complete one transaction at Kinder Morgan Resources, our first one. It was Blue Eagle in the Central App, and it was 25 million tons of proven reserves. The first one had a very nice high-teen return and we are looking forward to seeing others, as they progress.

Okay. And then also with regard to BOSTCO, I was wondering, how is the market for black oils right now, including bunker fuel, and how have your plans involved with regard to developing BOSTCO as you move into considering phase 2?

We just commissioned our 49th of 51 tanks last week. It's ramping up nicely. We expect it to be completely online by the end of the second quarter.

We are looking at a phase 3 expansion right now. Phase 3 can go one of two ways. We can look at more distillate, or more black oil there.

I personally believe it will be leaning towards the distillate side, as we go forward. The market seems to be very strong.

We're looking at further expansion at our Pasadena and Galena Park, on the gasoline side, and strong demand on distillates as well. Specifically on the export side.

Thank you very much.

Faisel Khan, Citigroup.

Just a few questions. On the broad run pipeline expansion and associated infrastructure investments, what do you expect for the revenue contribution from that $782 million investment?

We've got an attractive midteens unlevered rate of return on it. It really comes into service in two pieces, so we have a fairly low capital portion of it that will complete in 2015, but there's actually a fair amount of revenue that's associated with that, and then the rest of it comes online in 2017. I don't know -- I don't think we have the specific separate number representing what that revenue after the CapEx will be, but just use the kind of mid-teens referring to guidance.

Okay, fair enough. And on the CO2 business, with the expansion project you announced, how much of the 300 million cubic a day is for third parties versus yourself?

We will see how that turns out, what the exact mix is. We have a lot of demand for right now, and we are going to wait a little bit and see how this ROz wells turn out, before we make a decision on how much to sell to third parties. But it will be a mix of sales to third parties and utilization by ourself, and that's one of the nice positions that we are in, is we can kind of make that call, as we're drilling up St. John's, or building a robust pipeline.

Okay. Got it. And then can you give us a sense of how you're thinking about the timing on making a decision on whether there's a potential combination for EPB into KMP?

That would be up to the two sets of independent directors, Faisel. At some point, and I've said this all along, it probably does make sense to put the two together, but it's got to be on the terms that both of them agree.

And so we'll just see how that plays out over the remainder of this year, and again, we will complete the drop downs to EPB that we've agreed on, and get that done, and then we'll see how the whole thing plays out. But it will be primarily a decision of the two sets of independent directors.

Okay. Got it. I appreciate the time. Thanks a lot.

John Edwards, Credit Suisse.

I have just a couple questions. You have talked about the increase to the inventory backlog projects, and I know you had an inventory of identified but not put into backlog yet, at analyst day, and I think it was something like $24.5 billion or thereabouts, and I'm just wondering, what changes you are seeing there, and if you can give us a rough idea of where that stands?

Yes, we didn't really update that since the investor conference, so I think it's useful of a guidance, as anything. I think we have seen stuff, particularly in the gas sector, I think, pop on to the radar screen, not go into the backlog, but pop onto the radar screen since the conference.

I think one of the things we showed you at conference had never been on the backlog, but jumped from not on the horizon but to the backlog was the Magnolia project, for example. Our transport capacity off of Kinder Morgan Louisiana off the Magnolia project.

I think the trend, we haven't updated that number, but the trend generally is that we're seeing more opportunities, and it's driven by the things that Rich was talking about. Infrastructure investment in North America to support all of this production, and the demand side, which we're just speaking, and we're on the front lip of here on the GAAP side has a tendency, the direction on it is to add to that project level.

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

I guess everything that we are shipping now will be under expansion projects, so it's going to take additional capital to create more capacity. And as I said earlier, all the low-hanging fruit has been picked, so the cost of the next project will be greater than what we had to spend to do the Entero project, the [broad one] project.

I don't think we're done, but I think, as I've said earlier, I think the most cost-effective next expansion that we do will actually be the Marcellus project that ultimately feeds into New England, as opposed to coming back to the Gulf Coast. But we will certainly look at it, and we're seeing rates generally in the market from projects out in open seasons to be somewhere approaching $1 now from Marcellus to the Gulf Coast, so I think in general terms, that's probably a number to be thinking about.

Okay. That's helpful. So just to confirm then, when you say the low hanging fruit is now gone, at this point, there's not really a lot of available capacity, because you're having to spend some fairly significant dollars to do reversals. Is that a correct way to interpret that?

We've got everything under contract now to support all these expansion projects, and we're fully sold out.

Okay, great. And then, in terms of -- you did mention you bought back both warrant and KMI stock during the quarter. I think you said $55 million on the warrants and $94 million on the KMI stock during the quarter, so in terms of weighing those two, how are you looking at that trade-off between buying those back?

The analysis that we do is the same that we described to you in our quarters. During the quarter, the repurchases of stock were done first, and then we completed that $350 million authorization, and then you probably saw the 8-K in March, where we involved the $100 million authorization, and we spent about $55 million of that, and that was all warrant repurchase.

Okay, great. Thank you very much. That was all I had.

Christine Cho, Barclays.

Can we go over the expectation for the 4 times debt to EBITDA number by year-end 2014 at EPB? The Gulf LNG and Ruby assets will be coming with over $1 billion of debt, and I think your budget assumes $600 million of issuances. So taking all that with the EBITDA that the drops will contribute, partially offset by lower rates on SNG and WIC, I get a number closer to 4.3, and I was just wondering if something had changed, or if there's anything I'm missing.

Ruby and Gulf LNG are joint ventures, and the debt will not be consolidated, we do not believe, and so the 4 times is without consolidation of those joint ventures.

Okay, perfect. And then, just following up on the Ruby question that Brian asked, and I know you have talked about your intent to drop Ruby into EPB, but is a possibility of selling your half on the table at all, similar to what happened when the other partners have expressed [flat pull] their stakes?

Well, we would look at any reasonable offer probably, but we are not actively marketing it, Christine. We're in the process of dropping it down, and it's a good long-term asset, with a lot of good contracts that run out into the next decade, but we wouldn't rule out any possibilities on it.

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

We have not filed abandonment of it. We would want to see the commercial part of this mature further, but we believe we've worked closely with good advisors to articulate a clear path to get to abandonment, but we're not -- other than getting prepared, we're not at the point of filing.

And then, once you -- if and when you do file, it's about nine months, is that the process?

Probably more like a year.

Okay. And then, last one from me, this is just a broader question, as we try to figure out how gas rules are evolve in the next year or two. With respect to the NGPL reversal, once the gas gets into the system from REX, would shippers have the option to go North or South?

On a secondary basis, but on a firm basis, the path would be South bound.

Okay. Great. Thank you.

Okay. That's it, Holly, so we thank you very much for your questions. Good call. We think we had a good quarter, and we look forward to talking to you again soon.

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