金德摩根 (KMI) 2012 Q3 法說會逐字稿

Welcome to the quarterly earnings conference call. At this time all participants are in a listen-only mode until the question-and-answer portion of today's 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 Creighton, and then and welcome to the Kinder Morgan third quarter analyst call. 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 talking about Kinder Morgan, Inc., which I will refer to as KMI, Kinder Morgan Energy Partners, which I will referred refer to as KMP, and El Paso Pipeline Partners, which I will refer to as EPB. Together these three 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 will 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 will 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 questions and answers. I know particularly in the East it gets a little late when these calls get going. Post the El Paso merger we've noticed each call we have additional participants on the line. So I think it is 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 unit-holders at KMP and EPB and to our shareholders at KMI. At our two MLPs, we view the key measurement as being distributable cash flow per unit, and at KMI it is cash available for 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 three of our entities raised their distributions, and all three 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 is 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 nine months of 2011. That is an increase of 56%. We expect to generate the cash available for dividends well in excess of $1.325 billion for the full year 2012 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 look at the three quarters in the year to date, the increase was 28%, from $0.88 in 2011 to $1.13 in 2012 for the first three 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 into the Kinder Morgan family, and we are on our way to achieving annual cost savings of more than $400 million, compared to our original estimate of $350 million.

Now there were 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 a 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. 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 KMI management sold any shares. 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 is $5.04 annualized. That is 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 is an increase of 9%. Driving that growth, all five 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-downs of TGP and EPNG, which were accomplished in early August of this quarter; second, at the terminals group, 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 we're very close to having customer commitments on them, and they are in various stages of preparation and construction, the great bulk of that $11-plus billion dollars 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 in 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 appear 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 SONAT system, in the southeastern United States, we were 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 today. 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 have 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. A fourth positive is that, as we all know, there is 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 is ever a quarter or a year where there aren't negatives that partially offset the positives, and there are some negative trendlines as we see it today. So on the other side of the coin, we are experiencing weak refined products demand. We are seeing weakening domestic coal shipments. We are seeing a flattening of steel throughput across our system, and as you all know, we are seeing drilling declines in some of the dry gas plays. So that is sort of an idea of some of the trends that are affecting all of our companies.

Now let me conclude with EPB. There we increased the quarterly distribution per unit to $0.58. That is up 18% over the third quarter of 2011. Distributable cash flow per unit was $0.71 versus $0.55 a year ago. That is up 29%. If you look at it year-to-date, '12 versus '11, it is $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 close, 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 that Kinder Morgan assets are generating record amounts of cash. We think we are very well-positioned for the future, and we expect our footprint to continue to drive sustained growth in the months and years to come. With that I'll turn it over to Kim.

Thanks, Rich. 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 leads us year-to-date at $3.69 of declared distributions, which is a 7% increase over the nine 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 two things. Number one, you can see the loss on remeasurement of discontinued operations to fair value. We recognized an additional valuation adjustment in the quarter, $178 million related to the FTC assets.

This evaluation is based on a signed contract, and so other than small working capital changes, we wouldn't anticipate any significant changes in 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 a capital contribution and will impact the balance sheet and not the income statement. The other thing I'd point out on this, and we will go through it, you will 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. So we have to go back and recast KMP's prior financials as if it owned PGP and the 50% of EP&G from May 24, the dates they were acquired by KMP, I mean they were acquired by KMI. So you'll see on the next page that we will pull out that income because KMP, KMI got the cash from those operations and KMP did not receive that economic benefit.

Flipping to the next page, which is our calculation of distributable cash flow, and what we based the dividend that we declare on. The DCF per unit for the quarter is $1.28. That compares to what we are declaring, $1.26. So about $6 million of coverage in the quarter. $3.72 year-to-date versus the 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 is a little bit better than what we talked about on the second quarter call, and that's just a 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 is a $61 million increase or a 15% increase over third quarter 2011, and $1.28 billion in the nine months, which is a $183 million increase, or 17% over the nine months 2011. Looking at where that $61 million of growth came from and the $183 million for the nine months, if you look up at the top of the page, note the segment, $1.14 billion in earnings before DD&A. That's up $199 million on the quarter, or 21%. If you look at the segments, about 90% of that growth came from gas and CO2, and a similar story for the nine months, $456 million of growth in the nine months, 17%, again with about 90% of that coming from gas and CO2 segment.

So looking at the individual segments, products where up $7 million in the quarter. It is down $6 million year-to-date. On the quarter we had nice contributions from Cochin, and we had 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 some 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. 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 is just a timing issue. Then we've had lower volumes on SFPP and CALNEV, on our West Coast pipeline, given lower demand and also competition from another pipeline. So the negatives have been partially offset by nice volumes and a shipper settlement on our Cochin pipeline.

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 on our Fayetteville Express pipeline, and then those positives were somewhat offset by lower result 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 to be significantly exceed its budget, and that is a result of the drops net of the lost income from the FTC sale. After those two transaction, 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 is 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 Katz and SACROC. NGL volumes were up 900 barrels per day. Oil prices were up, and then that was somewhat, those up 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 a function and more of the NGL prices.

Terminals up $3 million in the quarter. Its up $37 million year-to-date. The growth in the quarter, about half of that was internal growth. It came from, on the liquids terminals for new contracts at higher rate, expansion projects, higher volumes, 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 volumes.

Kinder Morgan Canada up $8 million in the quarter. It is up $10 million year-to-date, and it is up $10 million versus its budget year-to-date and we expect to exceed its budget for the year, and that is a function of higher volumes both on Trans Mountain and Express, favorable book taxes, and then favorable incentive management fees that we get paid on Express due to the higher volumes.

G&A, if you drop down about four lines, G&A in the quarter up about $13 million, is up $23 million year-to-date, and in the quarter it is 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, its $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 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 is 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 is timing. For the full year we expect to be about $58 million above our budget, but that is attributable to the drop-down. 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 is the biggest piece of the total certain items, which are $191 million. The other two large certain items are the pre-acquisition earnings allocated to the general partner. These in the earnings that KMP picks up for GAAP purposes prior to its acquisition date, and then we took a non-cash environmental reserve of $34 million. So that is distributable cash flow for the quarter.

Looking at the balance sheet, we will see that there is a significant change in total assets, about a $9.5 billion increase, compared to December 31 of 2011, and other than recurring items, there are two significant events impacting the balance sheet, which are the two transactions, the FTC sales and the drop-downs. 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. Then the drop-downs, 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 than KMI's book value. So you're going to see a large change in partners' capital. You 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 is considered a general partner contribution.

Debt to EBITDA for the quarter, four times. Now that is pro forma for the sale of the FTC assets. We expect that the FTC assets will close in November, and that we will use all those proceeds to pay down debt. So it is just a timing issue. We expect that we should net, as you can see in the footnote, $1.76 billion, and so if you adjust our debt for that, we are four times. Without that adjustment, debt to EBITDA would be at 4.4 times. If you look at debt, we ended the quarter at $7.4 billion. That is a change versus June 30 of about $4.8 billion. So $4.8 billion increase in debt. As I said, there is about $1.8 billion of additional reduction that will happen. So if you netted that off, we would've had only a $3 billion increase in debt, but reconciling the $4.8 billion for you, is there basically there are $6.2 billion in acquisitions, CapEx, and contributions to equity investments, and we raised about $1.4 billion in equity. Just to go through a little bit more detail, the drop value in 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 the joint EP&G's joint venture debt, which is not on our balance sheet. So that is the biggest part of the acquisitions.

Expansion capital is about $388 million, and contributions to equity investments, $70 million. On the $1.4 billion raised, we raised about $727 million in the KMR offerings. KMI took back about $400 million in the drop-down transaction. We raised about $120 million in the APM, and then the KMR distributions were about $125 million. So that's KMP. Now, I will move to EPB. Just on KMP, we expect to end the year debt to EBITDA around 3.8 times, just slightly better than what I mentioned on the last quarter call, which was 3.9 times. 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.

On the second page, which is our calculation of the 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 is a little over $25 million of coverage in the quarter. Year-to-date, we have declared dividends of -- or distributions of $2.06. That compares to -- sorry, we generated cash flow of $2.06. We have declared distributions of $1.64, and so that is $87 million of coverage year-to-date. Looking at the distributable cash flow on a whole number, $149 million in the quarter. That is up $36 million, or 32%, versus the third quarter last year. $427 million for the nine months, which is up $58 million, or 16% versus a year ago.

From looking at what drove the growth of $36 million, and $58 million for the nine months, if you look up at the segments 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 interests in pipelines from El Paso Corp, and the way that shows up on the income statement is that it reduces your noncontrolling interest expenses. They acquire that as additional interest, and so you have to look down at the noncontrolling interest. So in the quarter, $43 million in of earnings before DD&A, the noncontrolling 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 Plains, and about $22 million of that is associated with the other assets that we owned in both periods, primarily expansions on Southern Natural Gas and increased gas fired power generation demand. There is about $12 million when you add together G&A, interest, the increased GP incentive, and sustaining CapEx offsetting that $47 million. The G&A was lower, primarily due to cost savings, as well as the sustaining CapEx was lower due to cost savings. Interest was higher, giving more debt, and the GP interest was an increase, given the higher distribution per unit and more units outstanding. So you net off the $12 million from the $47 million. That gets 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 noncontrolling interest expense of about $34 million. It's about $84 million in growth. A little over $60 million of that comes from the acquisition, and the balance is coming from assets owned in 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 4.2 times. That is up a little bit from December 31, 2011, but it is down from the second quarter, which we recorded at 4.7 times. It is down for the quarter, primarily because we did the equity offerings in order to put the long-term financing in place on the drop-downs that were done during the second quarter. Debt 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've tried to divide it into two 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 that GP section. The bottom section, which you can see is entitled El Paso Corporation Cash Available For Distribution, is the asset section. Those are assets that we ultimately think will be dropped to the MLP. As I said last quarter, it is not perfect. All the cash taxes are 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 of the assets dropped, are in the bottom section. The other thing we've done on the schedule is we've we pulled out the transaction costs to give you a sense of the recurring cash flow, but we've 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, but that is what we expect in the second and the third quarter, given the timing of interest payments and tax payments. For the nine months, $972 million, which is $349 million above the nine months ended in 2011. That is $1.13 per share compared to the declared distribution of $1.03 per share. So 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 the $349 million year-to-date. On the quarter, the increase 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 two interests in the MLPs, $170 million increase. That is offset by about a $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 add a $3 million decrease in NGPL cash available for distribution. That takes you to the $1.74. For the nine months, $171 million increase in KMP's distributions to us, $174 million comes from the general partner and limited partner interest in EPB. So $345 million year-to-date coming from the two interests in the 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's down about $16 million, takes you to $349 million in growth 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 is up from $3.2 billion at the end of last year, but it is down from the $16.4 billion where we ended the second quarter. 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 the 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 is actually $5.2 billion that we paid down, we got $5.275 billion of debt reductions coming from the drop-downs. That is $3.5 billion in cash that KMI got from KMP for those drop-downs, and then $1.8 billion in debt moved from KMI to KMP, it was debt on PGP 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 we had $137 million in transaction-related tax benefits, primarily tax benefits related to the deferred comp that got paid at the closing of the transactions. So when you net those two, it's $9 million of cash outflow associated with the transaction.

We repurchased $26 million in warrants. As you know, we included KMR in the cash available for dividends as if it was cash. We did not sell those shares in this quarter so we've not yet converted that to cash. Then we made a little over $40 million in contribution to the two 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. So that gets you to the $5.2 billion, or round it to $5 billion reduction in debt. So that is it.

Okay. Thank you, Kim. Creighton, if you will come back on, we will be happy to take questions.

(Operator Instructions)

Darren Horowitz, Raymond James & Associates.

Two quick questions from me/ The first is on the ramping crude oil and condensate volumes that were detailed in your prepared commentary. How do you think about leveraging that $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've outlined?

Well, that is 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've detailed in this, our terminals group 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 is one way. Obviously, we believe we will upsize that condensate processing unit, and we are looking for other ways to maximize the utilization. Now of course, as we pointed out last quarter, another very strange hook-up to this whole thing is the reversal of Conchin, which is actually in the end, we believe going to be used to move diluent processed out of the condensate coming out of the Eagle Ford and moved all the way back up into Alberta. So there is a lot of things here we are continuing to explore them, and 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 ramping this up, but any sort of preliminary thoughts on how prolific you think that St. John CO2 source field could prove to be, and the expected timing of when that source field could come online?

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

Our base case development plan at present is to develop the source that is on the order of 400 or so million cubic feet a day of CO2 supply. The timing on the critical path is not going to be the field development activities, the drilling of wells and such and the construction of facilities. The timing that is on the critical path is the construction of a pipeline from the state line Arizona/New Mexico over to the Permian Basin. We anticipate that could be a three-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 cost on that, Tim?

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

Okay. I appreciate it, thank you.

Brian Zarahn, Barclays Capital.

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

Sure, Tom Martin, you want to just do that.

FEP?

Yes.

Yes. Basically it is the contractual ramp-up of the commitments that we have on the pipeline, up to near capacity on the pipe. I think we are about 1.85.

Capacity of about two 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 [soaked].

Then on PGP and EPNG, are they just have the assets recently, but are they performing in line with guidance you provided, anything you -- any color you can provide on performance and contribution, you expect for 2013?

Yes. I think, well can't get into specifics on 2013 yet. We're starting our fun budget process beginning next Monday. Everybody around here's waiting for that with baited breath, but I can give you some color on how things are going. Clearly, on TGP, obviously the ability to access production from the Marsellais and the Utica is a tremendous plus. We are seeing all kinds of opportunities for expansions, some of which we detailed in the earnings release and some of which are not quite to that stage yet to be released, but we are seeing very good demand on the eastern part, or downstream part of that system.

So we are very pleased with it, and it is performing a bit better than we expected. On EPNG, the drop there is actually down 50% at KMP, and still 50% at KMI, and we will drop that other 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 California demand, but the ability to drop off volumes along the way, particularly into Mexico, and we talk about the Sasabe project, which is $200 million-plus project, which would hook into additional volumes that would be picked up on a brand new pipeline being built by other parties down in Mexico.

We would 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 two things. You earn on the money you've spent on those laterals, plus you are billing 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 is very speculative at this point, but there are a lot of opportunities that could be very exciting there. So, we are 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.

That is helpful. Thanks, Rich.

Vedula Murti, CDP Capital.

I'm wondering in terms of after the El Paso acquisition, some of the assets you acquired, including Elba Island and the Gulf Island facility, I'm looking 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 two years, and maybe some of the competitive advantages or challenges those facilities or the sites may have, compared to some of the other players who have already got agreements, or have been working fairly aggressively in the queue at [ferq]?

Yes, I'd be happy to. We believe that both of those terminals are at 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 is 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 then 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 is a little more preliminary then our efforts on Elba. That we think there is a good chance we can do something there that again would have maybe one train on an FTA, and then we would have to wait to get larger to see whether we got 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 are working very hard to secure commitments that are binding, even without non-FTA approval. So the whole projects would be constructed that way, and if you get non-FTA approval, there'd be upside, but we want base projects that will stand on their own based on FTA, which we have in both instances. We think both of them have potential. We're not prepared to announce anything right now, but we think we will be prepared to get 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 counterparty for the credit quality and duration that you'd seek?

Well, we wouldn't be talking about 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 is obviously a key consideration. You're not going to do something with somebody that doesn't have good credit, because these are very long-term agreements obviously.

All right. Thank you very much.

Craig Shere, Thule Brothers.

Quick follow-up first on Vedula's question. I think you said, Rich, that you are thinking maybe you could do 0.5 BCF a day single train both in LNG with FTA binding commitments. What were you thinking about size and potential online dates 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?

I think we are looking at potentially somewhere in the neighborhood of $300,000 to $400,000 a day in the 2015/2016 timeframe.

Great, and 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, at KMI.

KMI, that is correct.

That is correct at KMI.

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 with 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 gone to $3.50, and some of the fuel switching may have moderated. Are you seeing any changes on your system?

Well, that is why I gave you the figures for both the third quarter and the year-to-date. I think clearly some of the moderation in the third quarter, to the extent that there is on the pipes, is also cooler weather, at least during the latter part of the third quarter versus earlier quarters. I think that is 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, but 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 is some point at which the pricing would turn the other way. We are just watching it day by day, but we've had this very good demand growth, really pretty solidly throughout the year thus far.

Great, and last question on EOR, I just want to make sure that the long-term thinking, at least say over a three- to five-year period is that still that Katz makes up in terms of its growth for the fall-off in SACROC, and that would leave production about flat over that timeframe with including about $600 million of growth CapEx. Is that, all of that 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, they are ramping up this year. We are what, Tim, 1500 barrels above our plan on SACROC this year?

Approximately, yes.

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 2005, we were talking about SACROC would peak and start declining in the 2008/2009 timeframe. Then than 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 would be just stay tuned, and we're going to get growth at Katz, but increasingly we are 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?

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

Great. Thank you very much.

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

About $800 million.

Okay.

Ted Durbin, Goldman Sachs.

I am really interested about this comment you made about converting the 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 a portion of EPNG or the whole thing? Talk about maybe how much capital it would 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 is very early in the game, but we would not be converting all of it. We would still, if we did it at 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, level of throughput they want to sign up for, and still convert. We have multiple lines across there, and still convert a 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 [pull] our capital could be up to around $2 billion on that project.

But again, I want to emphasize this is very early, at the very early stages of our thoughts. We have had some interesting conversations with potential shippers on that line who are very enthusiastic. What we're seeing is there is 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 to Houston, and we are certainly looking at some opportunities there too, but we think there is also, given the dichotomy in prices between California and Texas, there is certainly some real interest at the right price under the right conditions, to move oil to the West, and we are certainly going to look at that is a possibility. Again, it's still speculative at this point, but kind of interesting to think about.

Absolutely, and so the [makes] for the customers would be above producers, and I'm assuming the refiners would want some of the discount in crude as well?

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

Got it. That is helpful. Then can you just talk about the thinking behind the sales price of TGP and the portion of EPNG at the eight times multiple, and you arguably have, and you've talked about this, pretty good growth projects for TDP in the Marsellais. I'm just wondering how we should think about future assets, kind of the EBITDA multiple, the relative attractiveness of the other assets, how are you thinking about the future drop-downs?

Mark?

Yes. 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 is not any questions that KMI wants to do what is right for KMP. 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 is helpful. Then you mentioned briefly, I think just a small portion of the authorization on the warrants was used this quarter. I'm just wondering how you're thinking about that buyback potential relative to other capital allocation opportunities you have at KMI?

Well, our Board has authorized us to buy back $250 million worth of warrants. We've publicly disclosed that, and we've bought back $138 million, so almost $140 million thus far. We've bought a lot of it at lower prices than where it's trading now. I think we were in at prices substantially below where the present market is. 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.

Okay, that's it for me. Thanks, guys.

John Edwards, Credit Suisse.

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 is going, and the confidence in securing permits, that kind of thing.

Well, that is 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 toll arrangement that we had with our customers who signed 20-year agreements with us. There was some opposition to that. The NEB just recently ruled in our favor that they would proceed on that basis and set 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 is going to start in February, and we believe that will be brought to conclusion, hopefully with approval from the process as we've structured it, by sometime 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-a-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. That will be, we know, a long I long process. We are going to try to do as much as we can to satisfy people's concerns before the hearing opens. We are not naive. We know that there will still be opposition, and that the NAB 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 would have, for Canada, for BC, and for Alberta, that we certainly think we are 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 is helpful. Then you had mentioned also that your total CapEx opportunity you've gone up from $10 billion to $11 billion, and I guess you've got more that you have yet to announce, it sounds like from your narrative. Just, can you remind us what was the -- what's been the major mover for taking it from $10 billion to $11 billion.

Yes, and we've 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 in 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've tried to in that, and that we're going to share with you at our analyst conference exactly where we stand project by project, but we've try to put 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 were 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. 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 are going to take advantage of that footprint to continue to get additional projects in the front door.

All right, thank you. That is very helpful. That is all I have.

John Tysseland, Citigroup.

This question might be directed more toward Tim, but I was curious how producer interests 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 does the profitability of CO2 flooding compared to some of these tight oil plays in the region, or can you not really compare the two?

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 break even crude price required for many of them, the average is around $60 a barrel to get an MVP 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. John's acquisition and development planning that we are 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 Dell Canyon and get it online at the end of next year, and do further expansions at McAllen Modown that will be forthcoming. It has been a great market. There's a lot of activity in the Permian, and it is 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 contract basket 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 capacities? I think the common thought might've been that that might not have gotten re-contracted, but appeared like it did. Is this mainly a demand-driven type of event, or how would you explain that?

I'll let Tom Martin answer that.

On Cheyenne Plains we've been working with some customers who had an interest in renegotiating contracts and extending, and so that maybe may be what you're seeing on Cheyenne Plains. We have two particular transactions that we renegotiated and extended those agreements, producer related.

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

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

That is helpful, thank you very much.

And there are no questions at this time.

Okay, thank you Creighton, 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.