Kinder Morgan, Inc. (KMI) Q3 2012 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. I would now like to turn the call over to Rich Kinder, Chairman and CEO of Kinder Morgan. You may begin.

Okay. Thank you, Craig. And welcome to the Kinder Morgan third quarter analyst call. As usual, we'll be making statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. We'll be talking about Kinder Morgan, Inc., which I'll refer to as KMI; Kinder Morgan Energy Partners, which I'll refer to as KMP; and El Paso Pipeline Partners, which I'll refer to as EPB. Together, these 3 companies make up the Kinder Morgan family of companies. We own and operate pipelines and terminals. We are the largest midstream energy company in North America and the third largest energy company of any kind in North America with an enterprise -- combined enterprise value of about $100 billion. I'll give an overview of the quarter, and then I'll turn it over to Kim Dang, our Chief Financial Officer, who will go through the detailed financials; and then, we'll throw it open for questions, and we've got our senior management team here, ready to answer any questions you may have. I'm going to try to be briefer than normal, so we have more time for question and answer. I know, particularly in the East, it gets a little late when these calls gets going. Post the El Paso merger, we've noticed in each call, we have additional participants on the line. So I think it's important that I sort of remind you of the philosophy of Kinder Morgan and the way we operate. We own and operate assets, about 75,000 miles of pipelines and 180-plus terminals around North America. These assets produce large amounts of cash flow, and our primary goal is to grow that cash flow and distribute it to our unitholders at KMP and EPB and to our shareholders at KMI. At our 2 MLPs, we view the key measurement as being distributable cash flow per unit. And at KMI, it's cash available per dividends per share. Post the El Paso acquisition, we said that between 2011, using that as the base year, and 2015, we could grow dividends per share at KMI by about 12.5% per year, that we could grow distributions per unit at KMP and its sister security, KMR, by about 7% a year, and we could grow distributions at EPB by about 9% a year. And we still expect to achieve those goals. Consistent with our philosophy and goals, all 3 of our entities raised their distributions, and all 3 improved the cash available per share or unit by measurable amounts during this past quarter. Let me start with KMI. We raised the dividend to $0.36 per share. That's up 20% from the dividend rate a year ago and represents $1.44 on an annualized basis. Our cash available for dividends increased by 93% from the third quarter of '11 and year-to-date, it increased to $972 million from $623 million during the first 9 months of '11. That's an increase of 56%. We expect to generate cash available for dividends well in excess of $1.325 billion for the full year 2012 and declare dividends -- and to declare dividends of at least $1.40. $1.40 would be an increase of 17% from the $1.20 that we declared in 2011. On a per share basis, which, as I said, is the most relevant measure, the cash available increased from the third quarter a year ago by 30%. It went from $0.27 to $0.35. And if you looked at the 3 quarters in the year-to-date, the increase was 28% from $0.88 in 2011 to $1.13 in 2012 for the first 3 quarters. Driving this performance, KMI benefited from strong performance by KMP and EPB and from the assets acquired from El Paso that are still housed at KMI prior to being dropped down to KMP and EPB. We continue to be pleased with the El Paso assets and their integration in the Kinder Morgan family and we're on our way to achieving annual cost savings of more than $400 million compared to our original estimate of $350 million. Now there are some other significant developments at KMI during the quarter. First, in August, KMI completed the drop-down of 100% interest in Tennessee Gas Pipeline and the 50% interest in El Paso Natural Gas pipeline to KMP for $6.22 billion, including assumed debt. Secondly, we expect the FTC mandated sale of certain of KMP's Rocky Mountain assets, which we had to sell to close the merger with El Paso, we expect that divestiture to be closed during November of this year. And third, just last week, on October 11, Goldman Sachs, The Carlyle Group and Riverstone Holdings sold the remaining portion of their KMI stock. As you probably know, neither KMI nor any of the KMI management sold any shares, and that leaves now only Highstar from the original investor group, and they have about 8% of the shares outstanding at KMI. At KMP, we increased the quarterly distribution to $1.26 per unit, that's $5.04 annualized, that's up 9% over the third quarter a year ago. And again, coming back to the most important measure of the distributable cash flow per unit before certain items, at KMP, it was $1.28 versus $1.19 last year, or an increase of 8%. Year-to-date numbers on the same per unit basis were $3.72 versus $3.40 a year ago and that's an increase of 9%. Driving that growth, all 5 of our business segments at KMP reported better results than in the third quarter of '11. The main drivers included the following: First, at the gas group, obviously, the contributions from the drop-down of TGP and EPNG, which were accomplished in early August of this quarter; second, at the Terminals group, a record export coal volumes again this quarter; and third, in our CO2 segment, strong oil production at SACROC and very good NGL production during the quarter. Now if you look across KMP and include the other KM companies, we now have over $11 billion of expansion projects in the works. These are projects that have customer commitments or were very close to having customer commitments on them, and they're in various stages of preparation and construction. The great bulk of that $11-plus billion is at KMP. We talked last quarter about having approximately $10 billion. That number has now escalated by well over $1 billion. We made progress on virtually all of these projects in the third quarter, and that progress is outlined with some detail in our release and in the interest of time, I won't go into it right now. In addition, we continue to pursue additional opportunities, which appeared to be numerous and growing. If you look at general trends that impacted all of the Kinder Morgan companies, on the positive side, we had a strong increase in natural gas used in electric generation. Let me give you some numbers that I find a little bit astounding. On our Tennessee system, for the quarter, throughput utilized for natural gas demand -- natural gas power demand was up 8% for the quarter and 20% year-to-date. On our Southern Natural Gas system, the SONA system, in the southeastern United States, we're up 26% for the quarter and 47% year-to-date. On the Colorado Interstate system, we were up 13% for the quarter and 44% year-to-date. So really strong growth in the utilization of our pipeline capacity to ship natural gas to be used for electric generation purposes. A second positive trend that we've seen is a strong and growing market for CO2 to be used in tertiary recovery, particularly in the Permian Basin. We've mentioned that for several quarters now and as we've detailed, we have a number of projects to hopefully capture additional portions of that demand. Third positive trend line has been export coal. That remains strong at our Terminals, both on the East Coast and along the Gulf Coast. And a fourth positive is that, as we all know, there's lots of drilling in the wet gas shale plays, and that additional drilling and production is leading to increased demand for the kind of infrastructure that we have in our footprint. Now I don't suppose there's ever a quarter or a year where there aren't negatives that partially offset the positives, and there are some negative trend lines as we see it today. So on the other side of the coin, we're experiencing weak refined products demand. We're seeing weakening domestic coal shipments. We're seeing a flattening of steel throughput across our system. And as you all know, we're seeing drilling declines in some of the dry gas plays. So that's sort of an idea of some of the trends that are affecting all of our companies. Now let me conclude with the EPB. There, we increased the quarterly distribution per unit to $0.58, that's up 18% over the third quarter of 2011. The distributable cash flow per unit was $0.71 versus $0.55 a year ago, that's up 29%. If you look at it year-to-date, '12 versus '11, it's $2.06 versus $1.89, or up 9%. These solid results really came across EPB's assets, driven by the drop-down that they got in May just before the El Paso-Kinder Morgan merger closed. And it was helped by additional demand for gas for power generation on both SNG and CIG, as I just detailed a moment ago. So in summary, we think the Kinder Morgan assets are generating record amounts of cash. We think we're very well positioned for the future, and we expect our footprint to continue to drive sustained growth in the months and years to come. And with that, I'll turn it over to Kim.

Thanks, Rich. And so starting with KMP, on the numbers, the first page of KMP numbers is the GAAP income statement. And as Rich said, today, the Board approved a distribution per unit of $1.26, which is a 9% increase over the third quarter of 2011. That leaves us year-to-date at $3.69 declared distributions, which is a 7% increase over the 9 months in 2011. The rest of the GAAP income statement, we don't find overly helpful in understanding our business. But for those of you who do use it, let me point out 2 things: Number one, you can see the loss on remeasurement of discontinued operations to fair value. We recognized an additional valuation adjustments in the quarter of $178 million related to the SEC asset. This valuation is based on a signed contract. And so other than small working capital changes, we wouldn't anticipate any significant changes in the future quarters. Of the $178 million, KMI is going to reimburse KMP $45 million of that. So the real economic impact of that is $133 million. But for GAAP purposes, that contribution by KMI will be shown as the capital contribution and will impact the balance sheet and not the income statement. The other thing I'll point out on this and we'll go through it, you'll see it more on the next page, is that because assets moved from KMI to KMP and because of their related entities, there are some special accounting rules. And so we have to go back and recap KMP's prior financials as if it owned EPB and the 50% of EPNG from May 24, the date they were acquired by KMP -- I mean, they were acquired by KMI. And so you'll see on the next page that we will pull out that income because KMP -- KMI got the cash from those operation, and KMP did not receive the economic benefits. Pushing to the next page, which is our calculation of distributable cash flow and what we use to -- what we base the dividend that we declare on. The DCF per unit for the quarter is $1.28. That compares to what we're declaring, $1.26. So about $6 million of coverage in the quarter. $3.72 year-to-date versus declared distribution of $3.69. So about $8 million of coverage year-to-date. For the full year, as Rich said, we still expect to distribute $4.98 per unit and we expect to generate coverage slightly above the distribution. That's a little bit better than what we talked about on the second quarter call, and that's just the result of a little bit better performance coming out of the segments and a little bit lower interest expense. Now looking at DCF, on a total basis, $455 million in the quarter, that's $61 million increase or 15% increase over third quarter 2011, and $1 billion -- $1.28 billion in the 9 months, which is an $80 -- $183 million increase or 17% over the 9 months 2011. Looking at where that $61 million of growth came from and the $183 million for the 9 months, if you look out at the top of the page, this segment -- $1.14 billion in earnings before DD&A, that's up $199 million on the quarter or 21%. And if you look at this segment, about 90% of that growth came from gas and CO2, and a similar story for the 9 months, $456 million of growth in the 9 months, 17%, again, with about 90% of that coming from gas and CO2 segment. So looking at the individual segments, products was up $7 million in the quarter. It's down $6 million year-to-date. On the quarter, we had 9 contributions from Cochin, and we had a very favorable volumes there. They were up 40% due to a new contract on an expansion project. We also had a favorable tax adjustment. Transmix, we benefited from pricing. And Southeast Terminals, we benefited from acquisitions and higher volumes. For the year, products, we expect to finish slightly below its budget, and they are slightly below their budget year-to-date. And that is Transmix, we had a contract that expired there. Kinder Morgan Crude and Condensate, the volumes came online a little bit later than what we anticipated. Ultimately, we think the volumes will be there, and it's just a timing issue. And then we've had lower volumes on SSTP and CALNEV, our West Coast pipeline, given lower demand and also competition from another pipeline. Those negatives have been then partially offset by nice volumes and a shipper settlement on our Cochin platform. Natural gas for the quarter, up $136 million year-to-date, up $239 million. As Rich said, significant benefit from the drops in the quarter. In the quarter, we also benefited from an acquisition that we did in the fourth quarter of last year on our treating business, as well as just better base performance there. In the Eagle Ford, we benefited from our JV that commenced shipping volumes in August of last year. We also benefited from a ramp-up in volumes of our Fayetteville Express Pipeline. And then those positives were somewhat offset by lower results on our pipes in the Rockies as a result of excess pipe capacity there. And also, on the Texas Intrastate, where we had an unexpected storage repair and some O&M timing. Year-to-date, natural gas is $96 million above its budget. For the full year, we expect it to be significantly exceeding its budget. And that is the result of the drops, net of the loss income from the FTC sale. Absent those 2 transactions, natural gas would be down for the year versus its budget. And that's just a function of the lower volumes in the dry gas area, primarily on KinderHawk, as well as a slower ramp-up in volumes versus what we expected in our budget in the Eagle Ford. CO2 is up $45 million in the quarter. It's up $176 million year-to-date. In the quarter, oil volumes were up; 1,400 barrels a day on a net basis, that was primarily capped at SACROC. EGL barrels were up 900 barrels per day. Oil prices were up, and then that was somewhat -- those positives were somewhat offset by NGL pricing down about $25 a barrel. Year-to-date, CO2 is below its budget and we expect them to be modestly below their budget for the full year. About $50 million, which is all a function and actually, more -- all function of more of the NGL prices. Terminals up $3 million in the quarter. It's up $37 million year-to-date. The growth in the quarter, about half of that was internal growth that came from -- on the liquids Terminals, for new contracts at higher rates, expansion projects, higher volume and then a -- and then export coal volumes. It is -- Terminals is slightly below their budget year-to-date, but we expect them to be on budget for the year, primarily as a result of stronger export coal volumes, offsetting reduced domestic coal and weaker steel volume. Kinder Morgan Canada, up $8 million in the quarter. It's up $10 million year-to-date, and it's up $10 million versus its budget year-to-date, and we expect it to exceed its budget for the year. And that's a function of higher volumes, both on Trans Mountain and Express, favorable booked taxes and then favorable incentive management fee that we get paid on Express, due to the higher volume. G&A, if you drop down about 6 -- 4 lines, G&A in the quarter, up $13 million. It's up $23 million year-to-date, and in the quarter, it's almost solely attributable to the TGP acquisition. Year-to-date versus our budget, we are within 1% of our budget if you exclude the TGP acquisition. So TGP G&A accounts for most of the variance year-to-date versus our budget. And we expect to be over our budget for the full year as a result of G&A associated with TGP. Interest -- it's $40 million increase in the quarter, $59 million year-to-date, almost solely attributable to increased balance. We did get a small benefit from lower rates in the year-to-date numbers. Versus our budget, we expect to be negative both -- we are negative year-to-date -- on the -- versus the budget. We expect to be negative versus the budget for the full year as a result of the drop-down. If you take out the impact of the drop-down, our interest expense would be positive for the year versus our budget due to lower rates. Looking at sustaining CapEx, it's up $23 million in the quarter. It's up $34 million year-to-date. It's actually positive versus our budget year-to-date. But that's timing. For the full year, we expect to be about $58 million above our budget. But that is attributable to the drop-downs. Without the drop-down, the remaining business segments in aggregate would be very close to their budget. Looking at the certain items for the quarter, we talked about the loss on remeasurement of $178 million. That's the biggest piece of the total certain items, which are $191 million. The other 2 large certain items are the 3 acquisition earnings allocated to the general partner. These are the earnings that KMP picked up for GAAP purposes prior to its acquisition date, and then we took a non-cash environmental reserve of $34 million. So that's the distributable cash flow for the quarter. Looking at the balance sheet, you will see that there's a significant change in total assets, about a $9.5 billion increase compared to 12/31/2011. And other than recurring items, there are 2 significant events impacting the balance sheet, which are the 2 significant -- the 2 transactions, the FTC sale and the drop-down. We talked about the FTC sales last quarter, which has the impact of moving assets from long term to current and classifying them as held for sale. And then the drop-down, the impact of this is that we have to record the drop-downs at KMI's book value. So KMP records them at KMI's book value even though it paid a different price. And in this case, it paid less in KMI's book value. And so you're going to see a large change in partners' capital. You'll see a $3.2 billion change in partners' capital. A significant portion of that $3.2 billion in partners' capital is the difference between the book value that we had to record these assets, which is KMI's book value; and the price that KMP paid. And that's considered a general partner contribution. Debt-to-EBITDA for the quarter, 4x. Now that is pro forma for the sale of the FTC assets. The -- we expected that the FTC assets will close in November, and that we will use all those proceeds to pay down debt. And so it's just a timing issue. We expect that we should let, as you can see on the footnote, $1.76 billion. And so if you adjust our debt for that, we're 4x. Without that adjustment, debt-to-EBITDA would be at 4.4x. If you look at debt, we ended the quarter at $7.4 billion, that's a change versus 6/30 of about $4.8 billion, so $4.8 billion increase in debt. As I said, there's about $1.8 billion of additional reduction that will happen. So if you netted that off, we would have only a $3 billion increase in debt. But reconciling the $4.8 billion for you is -- basically, there are $6.2 billion in acquisition, CapEx and contributions to equity investments and we raised about $1.4 billion in equity. And just to go through a little bit more detail, the drop value and my $6.2 billion is $5.66 billion. And all that is the $6.22 billion that you've seen in the press, less our share of that joint -- EPNG joint venture debt, which is not on our balance sheet. And so that's the biggest part of the acquisition. Expansion capital is about $388 million. The contributions to equity investments, $70 million. On the $1.4 billion raised, we raised about $727 million from the KMR offering. KMI sit back about $400 million in the drop-down transactions. We raised about $120 million in the ATM under the KMR distributions or about $125 million. So that's KMP. Now I will move to EPB -- oh, and just on KMP, we expect to end the year debt-to-EBITDA around 3.8x, just slightly better than what I mentioned on the last quarter call, which was 3.9x. Looking at EPB, again, we don't consider the GAAP income statement overly helpful in understanding our business. It does show the declared distribution per unit for the quarter of the $0.58. So on the second page, which is our calculation of distributable cash flow, distributable cash flow per unit was $0.71 in the quarter. So compared to the dividend or the distribution of $0.58, that's a little over $25 million of coverage in the quarter. Year-to-date, we have declared dividends of $2 -- or distributions of $2.06. That compares to -- or, sorry, we generated cash flow of $2.06. We have declared distributions of $1.64. And so, that's $87 million of coverage year-to-date. Looking at the distributable cash flow on a whole number, $149 million in the quarter. That's up $36 million or 32% versus the third quarter of last year. $427 million for the 9 months, which is up $58 million or 16% versus a year ago. Looking at what drove the growth up $36 million and $58 million for the 9 months, if you look out at the segment, earnings before DD&A, up $43 million. But as we discussed last quarter, that doesn't tell the whole story because EPB has acquired partial interest in pipelines from El Paso for -- and the way that, that shows up on the income statement is that it reduces your non-controlling interest expenses they acquired as additional interest. And so you have to look down to the non-controlling interest. So in the quarter, $43 million in earnings before DD&A. The non-controlling interest was reduced by about $4 million. So $47 million in growth coming out of the assets. About $25 million of that is associated with acquisitions, primarily Cheyenne Plain, and about $22 million of that is associated with the other assets that we owned at both periods, primarily expansions on Southern Natural Gas and increased gas firepower generation demand. There was about $12 million when you add together G&A, interest, the GP -- the increased GP incentive and sustaining CapEx offsetting that $47 million. The G&A was lower, primarily due to cost savings, as well as sustaining CapEx was lower due to cost savings. Interest was higher given more debt and the GP interest was an increase given the higher distribution per unit and more units outstanding. And so you now have the $12 million from the $47 million, that gives you about $35 million in growth on distributable cash flow. For the year, $50 million increase in earnings before DD&A. Again, looking down the page, you see a decrease in non-controlling interest expense of about $34 million. So about $84 million in growth, a little over $60 million that comes from the acquisition, and the balance is coming from assets on the both periods, primarily Southern Natural Gas. Offsetting that is about $30 million of increased expense, primarily increased interest expense and increased GP incentive to get you to the $58 million in growth. For the full year, as we said in the press release, we're still expecting to distribute $2.25 and have over $95 million in coverage. On EPB's balance sheet, EPB ended the quarter debt-to-EBITDA 4.2x. That's up a little bit from 12/31 of 2011. But it's down from the second quarter, which we reported at 4.7x. It's down for the quarter primarily because we did the equity offering in order to put the long-term financing in place on the drop-downs that were done during the second quarter. Debt is decreased by about $304 million in the quarter and just to reconcile that for you, we spent about $14 million in expansion CapEx, we issued $278 million in EPB units, we had about $26 million in excess coverage and then there was about $14 million in working capital and other items. Turning to KMI, as I said last quarter, the first page is our cash available for dividends, which we think is the most important measure for KMI. We tried to divide it into 2 sections: the top section, which we -- is the cash generated from the GP and LP interest in KMP and EPB, which I'll refer to as the GP section; the bottom section, which you can see is entitled, "El Paso Corporation's Cash Available for Distribution", is the asset section. And those are assets that we ultimately think will be dropped to the MLPs. As I said last quarter, it's not perfect. All the cash taxes, they're up in the top section. And all the acquisition interest as well as the EPC interest, some of which will remain after we get all the assets dropped or in the bottom section. The other thing we've done on the schedule is we pulled out the transaction cost to give you a sense of the recurring cash flow. But we detailed those for you in Footnote 11. Looking at the quarter, we generated $362 million of cash available to pay dividends. That's almost double what we generated in the third quarter of last year. That translates into $0.35 per share that compares to our declared distribution of $0.36 per share. So we have about $12 million of negative coverage. So that is what we expect in the second and the third quarter, given the timing of interest payments and tax payments. For the 9 months, $972 million, which is $349 million above the 9 months ended in 2011, that's $1.13 per share compared to the declared distribution of $1.03. So a little over $75 million in coverage year-to-date. For the full year, we expect cash available to be over $1.325 billion, and we still expect to pay at least $1.40. Looking at where the growth came from, the $174 million on the quarter and $349 million year-to-date, on the quarter, the increase from $429 million -- to $429 million from $354 million, $78 million increase in KMP's distribution to us. EPB distribution to us, $92 million increase due to the acquisition. So between our 2 interests in the MLPs, $170 million increase. That's offset by about $41 million increase in interest, taxes and G&A. The largest piece of that $41 million is $33 million increase in taxes, which is associated with the higher income. The cash available from the EPC assets, $48 million. And then we had a $3 million decrease in NGPL Cash Available for Distribution. That takes you to the $1.74. For the 9 months, $171 million increase in KMP's distribution to us, $174 million comes from the general partner and limited partner interests in EPC. So $345 million year-to-date coming from the 2 interests in MLP. There's an increase in interest and taxes and G&A of $66 million. Again, the biggest piece of that is over $50 million increase in taxes due to the higher income; $86 million coming from the EPC assets; and then NGPL is down about $16 million take you to $349 million in gross year-to-date. On KMI's balance sheet, looking down at the debt on KMI, we ended the quarter at $11.2 billion. Now that's up from $3.2 billion at the end of last year, but it's down from the $16.4 billion where we ended the second quarter. And so just very, very roughly and broadly, we started the year at $3 billion. We took on roughly $13 billion in the El Paso transaction between transaction itself and some of the transaction-related expenses. We paid down $5 billion in this quarter, and that leaves us at $11 billion. So when you look at the $5 billion pay-down in the quarter, it's actually $5.2 billion that we paid down. We got $5.275 billion of debt reductions coming from the drop-down. And that's $3.5 billion in cash that KMI got from those -- from KMP for those drop-downs, and then $1.8 billion in debt moved from KMI to KMP. It was debt on TGP that was assumed by KMP in the transaction. We had about $146 million in transaction-related expenses. The biggest piece of that was related to the El Paso merger litigation that we've now resolved. And then we also had $137 million in transaction-related tax benefits, primarily tax benefits related to the deferred comp that got paid at the closing of the transaction. So when you net those 2, it's $9 million of cash outflows associated with the transaction. We repurchased $26 million in warrants. As you know, we include KMR in the cash available for dividends as this is assets as if it was cash. We did not sell those shares in the quarter, so we've not yet converted that to cash. And then we made a little over $40 million in contribution to the 2 MLPs to maintain the 2% interest, and also in JV contributions to the JVs that are still held at KMI and expansion capital. And then we had $10 million in working capital and other items. And so that gets you to the $5.2 billion or, rounded, $5 billion reduction in debt. So that's it.

Okay. Thank you, Kim. And Craig, if you'll come back on, we'll be happy to take questions.

[Operator Instructions] The first question is from Darren Horowitz with Raymond James.

Two quick questions for me. The first is on the ramp in crude oil and condensate volumes that were detailed in your prepared commentary. How do you think about leveraging the $200 million investment in that condensate processing facility because you've got ample storage capacity at Galena Park, and, obviously, it looks like volumes of crude and condensate from the Eagle Ford are going to be moving through a lot of those new pipes that you've detailed. So is this the type of project where you could become more vertically integrated to the extent that capacity even exceeds that 100,000 barrel-a-day upside that you guys want?

Well, that's possible. But I think the most likely thing is we do have this whole collection of assets, and already, as you can see, as we detailed in this, the -- our Terminals group is -- has a contract also with BP to provide pretty significant storage, which BP is using as part of the operation of the condensate processor. So I think that's one way. Obviously, we believe we will upsize that condensate processing unit, and we're looking for other ways to maximize the utilization. Now of course, as we've pointed out last quarter, another very strange hook-up to this whole thing is the reversal of Cochin, which is actually, in the end, we believe, going to be used to move really oil [ph] processed out of the condensate coming out of Eagle Ford and moved all the way back up into Alberta. So there's a lot of things here we're continuing to explore, but I think we have a tremendous position, a great footprint here, and we're going to use it to every extent we can.

I appreciate the color. And last question. Just -- and I know you're in the process of coming -- ramping this up. But any sort of preliminary thoughts on how prolific you think you think that St. Johns CO2 source field could prove to be and the expected timing of when that source field could come online?

I'll ask Tim Bradley, the head of our CO2 segment to talk about that.

Our base case development plan at present is to develop sources on the order of 400-or-so million cubic feet per day of CO2 supply. But the timing on the critical path isn't going to be the field development activities, the drilling of the wells and such and the construction of facilities. The timing that's on the critical path is the construction of a pipeline from the state line in Arizona and New Mexico over to the Permian Basin. And we anticipate that, that could be a 3-year process, but it's still early in the game and that timing will likely shift somewhat. Hopefully, that addresses your question.

And the associated costs on that, Tim?

Order magnitude, this investment into the pipeline and the field development could be on the order of $1 billion. But it's still early in the game to sharpen that pencil too much better than that.

Your next question is from Brian Zarahn with Barclays Capital.

Can you, Rich, provide a little bit more color on FEP's performance in the quarter or what's driving the volume ramp and what you expect going forward?

Sure. It's Tom Martin. Here, Tom, do you want to just do that?

FEP?

Yes. FEP, yes.

Yes, FEP.

Yes, basically, it's a contractual ramp-up of the commitments that we have on the pipeline up to near capacity on the pipe. I think we're about...

85...

1.85.

Capacity of about 2 Bcf. And now it's fully ramped up to 1.85. We still have 150 million a day on that, that is not being utilized, not being sold.

And then on TGP and EPNG, are they -- just have the assets recently. But are they performing in line with the guidance you provided? And anything you can -- any color you can provide on performance and contribution you think you expect for 2013?

Yes, I think, well, we can't get into specifics on 2013 yet. We're starting our fun budget process beginning next Monday. Everybody around here is waiting for that. But maybe -- but I can give you some color on how things are going. Clearly, on TGP, obviously, the ability to access production from the Marcellus and the Utica is a tremendous plus. We're seeing all kinds of opportunities for expansions, some of which we've detailed in the earnings release and some of which are not quite to that stage yet to be released. But we're seeing very good demand on the Eastern part or downstream part of that system. So we're very pleased with it. And it is performing a bit better than we expected. On EPNG, the drop there is actually now 50%; at KMP, it's still 50%. And KMI will drop another 50%, I'm sure, sometime next year. On that, again, we've made no secret of the fact that the great upside there is not due to California demand but the ability to drop off volumes along the way, particularly into Mexico. And we talk about the Sasabe project, which, at $200 million-plus project, which would hook into additional volumes that would be picked up on the brand-new pipeline being built by other parties down in Mexico. We will hook at -- hook up at the border near Sasabe, Arizona. So just a lot of potential to drop more volumes off. And when you do that, we believe we will end up with more than one lateral going down there. And when that happens, you have 2 things: You earn on the money you've spent on those laterals, plus you're filling some of the capacity that is now not being utilized to ship gas to California. The other thing is that we continue to look at the potential to use portions of that system to convert it to other uses, perhaps moving crude oil west from the Permian Basin. That's very speculative at this point, but there are a lot of opportunities. It could be very exciting there. So we're very pleased with the way both of these are performing so far and look forward to a lot of upside opportunities in 2013 and beyond.

The next question is from the Vedula Murti with CDP Capital.

I'm wondering, in terms of after the El Paso acquisition, some of the assets you acquired or -- including Elba Island and the Gulf LNG facility, I'm wondering, given the significant interest in terms of potential liquefaction and export of natural gas and some of the controversies around that, can you talk a little bit about how you're viewing those assets in terms of their potential for you over the next 2 years and maybe some of the competitive advantages or challenges to those facilities or those sites may have compared to some of the other players who have already got agreements or have been working fairly aggressively the in the queue at FERC?

Yes, I'd be happy to. We believe that both of those terminals are -- have very great potential to be utilized for LNG export. In both cases, we have a DOE approval on the FTA volumes. No one knows for sure what's going to happen on the non-FTA. We believe we will be able to put together a project at Elba that will be non-FTA, and it will have some optionality to expand if and when we got FTA. On the Gulf, we think much the same thing. We think we will be able to do something, although it's a little more preliminary than our efforts on Elba. We think there's a good chance we can do something there that again would have maybe one train on an FTA, and then we've had to wait to get larger to see whether we get approval from DOE on a non-FTA. Our whole process in this is very conservative, I think, we don't want to spend a lot of money cranking up, based on getting non-FTA approval. So we're working very hard to secure commitments that are binding even without non-FTA approval. And so the whole projects would be constructed that way. And if you get non-FTA approval, there'll be upside, but we want base projects to stand on their own based on FTA, which we have in both instances. So we think both have met potential. We're not prepared to announce anything right now, but we think we will be prepared to give more detail on that in the not-too-distant future.

I guess just to follow up, how far along do you feel like you are in terms of finding the appropriate counter-party for the credit quality and duration that you seek?

Well, we wouldn't be talking about it in the terms I have if we didn't think we had -- if we weren't pretty far along in dealing with parties that are very solid from a credit standpoint. And that's obviously a key consideration. You're not going to do something with somebody who don't have good credit because these are very long-term agreements, obviously.

Your next question is from Craig Shere with Touhy Brothers.

So a quick follow-up first on Vedula's question. I think you said, Rich, that you're thinking maybe you could do 0.5 Bcf a day single train at -- both in LNG with FTA binding commitments. What were you thinking about size and potential online date for Elba?

Well, first of all, I don't think I said -- I think I just said an LNG train. I didn't mention the specific amount of gas throughput there. But we think that the potential at Gulf is to put together one train of FTA. At Elba, Tom, you want to comment on that?

Yes, I mean, I think we're looking at potentially somewhere in the neighborhood of 300,000 to 400,000 a day in the 2015-2016 time frame.

Great. And a couple of other quick questions just in terms of the consolidation. I just want to make sure I understand. Citrus Gulf LNG and Ruby are not consolidated but EPNG and midstream are, is that correct?

Yes, correct. They're KMI.

Right.

It's KMI. That's correct.

That's correct. It came on.

And what is the debt at Gulf LNG that is not consolidated?

I don't know exactly. We'll have to get that to you. I'm not sure exactly what it is.

Okay. And Rich, you had said that highlighted was all the positive trends, the power stack demand for nat gas. I wonder if you or anyone else on the team could speak a little more about more recent trends since gas has kind of gotten to maybe $3.50 and, from the fuel switching, may have moderated. Are you seeing any changes on your system?

Well, that's why I gave you the figures for both the third quarter and the year-to-date. And I think clearly, some of the moderation in the third quarter, to the extent that there is, on the pipes is also the cooler weather, at least during the latter part of the third quarter versus earlier parts. Now I think that's very difficult to see right now. Obviously, there is a price at which -- and it varies from system to system and it varies from customer to customer. There's obviously a price at which switching lessens. I don't think we're there for the most part yet, even in the mid-$3.50s -- mid-$3 range. But clearly, there's some point at which the pricing would turn the other way. But we're just kind of watching it day by day. But we -- or we've had this very good demand growth really pretty solidly the throughout the year thus far.

Great. And last question on EOR [ph]. I just want to make sure that the long-term thinking, at least, say, over a 3- to 5-year period, is that still, that Katz makes up, in terms of its growth, for the falloff in SACROC. And that would leave production about flat over that timeframe with -- including about $600 million of growth CapEx. Is that all about correct?

I don't think so. I mean, certainly, we think Katz is going to be a major addition to our production. But as you can see from the SACROC volumes, that're ramping up this year, we are what, Tim, 1,500 barrels above our plan on SACROC this year?

[Indiscernible].

So SACROC is doing much better than we expected it to do this year. The decline is not as fast. And we've said this on these calls before. We could play back all these calls and back in 2004 and '05, we were talking about SACROC would peak and start declining in the 2008-2009 timeframe. Then it was '11 and '12. Now it's '15 or '16. As Tim Bradley says, big fields get bigger. And we continue to rework parts of SACROC. And so I wouldn't at all say that the best we can do is flat if you add in the Katz volumes. I think my message will be just stay tuned and we're going to get growth at Katz. But increasingly, we're increasingly optimistic about SACROC's future also.

Well, that sounds great. I guess the last related question. I think the NGLs pretty much only come from SACROC. So would you see NGL percentage out of the total mix declining over time at least?

Tim?

And when you say NGL volumes declining, they've actually been increasing over the last 2 or 3 years. We are now averaging, on a monthly basis, between 19,000 and 20,000 barrels a day production out of the Snyder gas plant. And they will probably stay around that level for the next several months, if not 3 or 4 years. And that volume of NGL production is largely driven by gas production from the SACROC Unit. The gas production to SACROC Unit is filling to capacity. We intend to continue to keep that capacity filled, if not, expand it. So we would expect NGL production at SACROC to remain fairly stable for the foreseeable future.

And Rich, to address that other question on Gulf LNG, it's got about $800 million of debt.

$800 million. Okay?

The next question is from Ted Durbin with Goldman Sachs.

I'm really interested about this comment you made about converting EPNG from gas to crude. And maybe you can just talk a little bit more about how much oil you might be able to move out of the Permian. Would you be moving -- just converting portion of EPNG or the whole thing? Talk about maybe how much capital it'd take to do that.

Well, first of all, I want to emphasize again this is very early. I was responding to a question of what are the upside opportunities on EPNG. It's very early in the game. But we would not be converting all of it. We would still, if we did it all, be able to service all of our gas customers at the present level of demand or whatever throughput they want to sign up for, a level of throughput they want to sign up for and still convert -- we have multiple lines across there -- and still convert the line all the way from the Permian into Southern California. The volumes could be very substantial, maybe 300,000 or 400,000 barrels a day. And the effort to, or the opportunity to collect capital could be up to around $2 billion on that project. But again, I want to emphasize this is very early -- in the very early stages of our thoughts, that we have had some interesting conversations with potential shippers on that line who are very enthusiastic. What we're seeing is there's continued increase in production in the Permian, particularly as these different sands are being exploited there. And there's a lot of effort on a lot of people's parts to move this over at Houston, and we're certainly looking at some opportunities there, too. But we think there's also -- given the dichotomy in prices between California and Texas, there's certainly some real interest at the right price under the right conditions to move oil to the west. And we're certainly going to look at that as a possibility. Again, it's still speculative at this point but kind of interesting to think about.

Absolutely. And so the nature of the customers will be about producers, and I'm assuming the refiners would want some of the -- that discounted crude oil as well?

I really wouldn't want to give any more detail on the customers at this point. But we have a number of people interested.

Got it. That's helpful. And then can you just talk about the thinking behind the sales price of TGP and the portion of EPNG at the 8x multiple? And you arguably have -- and you talked about these pretty good growth projects for TGP and the Marcellus. I'm just wondering how we should think about future assets, kind of the EBITDA multiple, the relative attractiveness of the other assets, how you're thinking about the future drop-downs.

Park?

Yes, I mean, I think the price that you saw associated with those assets is reflective of the prices that you're likely to see going forward. There's not any question that KMI wants to do what's right for KMP. And so KMP and EPB will acquire assets at attractive prices. And that makes a lot of long-term sense for KMI, in addition to short-term benefits for KMI.

Okay, that's helpful. And then you mentioned briefly, I think, just a small portion of the authorization on the warrants that's used this quarter. I'm just wondering how you're thinking about that buyback potential relative to other capital allocation opportunities out of KMI.

Well, our Board has authorized us to buy back $250 million worth of warrants. We publicly disclosed that. And we bought back $130 million?

38.

$138 million. So almost $140 million thus far. We bought a lot of it at lower prices than where it's trading now. I think we we're in at prices substantially below where the present market is. And we just continue to look at that on a regular basis to see when we ought to be buying and when we don't want to buy. But we plan to hopefully fill out the rest of that $250 million.

And the daily volume has a big impact on how much we buy as well.

Your next question is from John Edwards with Crédit Suisse.

Just, Rich, if you could just comment briefly. You said in the press release here that this summer, Kinder Morgan Canada commenced an extensive engagement with communities on Trans Mountain for the proposed routing there. I was just wondering if you had any thoughts about how that's going and the confidence and securing permits, that kind of thing.

Well, that's a good question, John. And let me sort of bring everybody up to speed on it. We applied to the NEB, National Energy Board, to do a bifurcated process. And we said we wanted to come in first and get approval on the total arrangement that we had with our customers who signed 20-year agreements with us. There were some opposition to that. The NEB just recently ruled in our favor that they would proceed on that basis and set the first -- the hearing on that issue. Now this is not the environmental permitting or routing issues. This is just approving the toll structure so that we know -- we and our customers know that our contractual arrangements for 20 years have been blessed by the regulator. That's going to start in February, and we believe that will be brought to conclusion, hopefully with approval for the process as we've structured it, by some time -- about this time next year. Then we are working with all of the applicable constituencies here, from First Nations to people who are along the pipeline right of way to users, to consult with them on moving forward toward the filing that we will make in late '13 for the environmental and routing permits to actually get the permit to construct the line. And that will be a, we know, a long process. We are going to try to do as much as we can to satisfy people's concerns before the hearing opens. We're not naive. We know that there will still be opposition and that the NEB will have to balance the interest of a lot of different players here. But we certainly believe, given the economic advantages to the country of Canada and certainly to the producers in Alberta and the favorable tax benefits that this project will have for Canada, for B.C. and for Alberta, that we certainly think we're on the right side of the arguments. But I've never minimized it, never guaranteed anything here. We think we have a very good case, and we intend to make it.

Okay, that's helpful. And you had mentioned also that your total CapEx opportunity has gone up from $10 billion to $11 billion. And I guess you've got more on -- more that you have yet to announce, it sounds like, from your narrative. The -- I just -- can you remind us, what was the -- how -- what's been the major mover for taking it from $10 billion to $11 billion?

Yes, and we detailed some of that in the release. But since the last quarter, our projects on the terminal side have gone up by over $100 million. We've had additional projects on the natural gas side, and those have been the main drivers, a little bit more on the product side. But we think there's a lot more to come. We haven't included all of the -- as I said, all of the projects that seemingly are out there. What we've tried to do in that, and it's really over $11 billion now, we have tried to -- and that -- and we're going to share with you at our analyst conference exactly where we stand project by project. But we've tried to foot -- to -- with projects that are really in advanced stages where we either have customer commitments or we have letters of intent to commit to customer commitments, that kind of thing. So these are very viable projects, and I think we're just going to continue to grow that backlog. I know I've said it until I'm blue in the face, and you guys are probably tired of hearing it, but you cannot overemphasize the power of the footprint that we now have in North America. And we are going to drive that footprint as hard as we possibly can only when the projects make sense on an economic basis. But we're going to take advantage of that footprint to continue to get additional projects in the front door.

Your next question is from John Tysseland with Citigroup.

This question might be directed more toward Tim, but I was curious how producer interest for CO2 supplies is holding up in light of kind of the large ramp-up in the Permian towards some of the tight oil plays. And when it comes to producers allocating capital between projects, how is the profitability of CO2 flooding compared to some of these tight oil plays in the region? Or -- and can you not really compare the 2?

Well, I'll take the second one first. I'm not an expert in the shale plays and so forth, but things that I've seen in the public domain in terms of the break-even crude price required from many of them, the average is around $60 a barrel to get an NPV of $15. I think CO2 flooding is a little bit below that but not way out of that range, and I really can't take that commentary much further. With respect to CO2 demand, we are presently turning customers away that want more. I wish that, that was not the answer, and that's clearly a driver for our St. Johns acquisition and development planning that we're doing now, but we have customers that are taking virtually all of their contract quantities and wanting to increase them. And quite frankly, we've had some modest proration this past year. We may have a bit of that next year as well until we could expand Doe Canyon and get it online at the end of next year and do further expansions at McElmo Dome that will be forthcoming. So it's been a great market. There's a lot of activity in the Permian, and it's going our way as well as other directions as well.

That's definitely helpful. And then lastly, in the second quarter on Cheyenne Plains, I think there's a fairly large percentage of the contracted capacity that rolled off. And it looked like all of that got re-contracted for a pretty long-term commitment. Are you seeing similar things for other pipelines in long-haul capacity because I think the common thought might have been that, that might not have gotten re-contracted, but it appeared like it did. Is this mainly a demand-driven type of event? Or how would you explain that?

Well, I'll have Tom Martin handle that...

I mean, in Cheyenne Plains, we've been working with some customers who had an interest in renegotiating contracts and extending. And so that's -- that may be what you're seeing in Cheyenne Plains. We had 2 particular transactions that we renegotiated and extended those agreements. Producer related.

Okay. So is it -- so is it fair to say that even though the Rockies and bases [ph] is still relatively tight, you're seeing -- you're still seeing producer demand for long-term, firm gas transportation agreements?

I think that's a fair point. Particularly, I mean, there's rich pockets in the Rockies as well. We're certainly seeing opportunities to explore converting lines to rig service up in the Rockies and gather gas, processed gas, into our lines from these rich plays in the Rockies as well.

And there are no questions at this time.

Okay. Thank you, Craig. And thanks to all of you. We appreciate your attention, and have a good evening. And thank you very much.

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