金德摩根 (KMI) 2013 Q4 法說會逐字稿

Welcome to the Kinder Morgan quarterly earnings conference call.

(Operator Instructions)

Today's conference is also being recorded. If anyone has any objection, you may disconnect.

(Operator Instructions)

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

Thank you, Holly, and welcome to the Kinder Morgan Analyst call. We will be discussing Kinder Morgan Inc., which I will refer to as KMI, Kinder Morgan Energy Partners referred to as KMP, and El Paso Pipeline Partners referred to as EPB. As usual, we are likely to make statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. I will do an overview of the results and recent developments; Steve Kean, our Chief Operating Officer, will give the details of business segment performance and discuss our backlog of future projects; and Kim Dang, our CFO, will go through the financial details for both the fourth quarter and full year 2013. And then, we will take any questions you may have.

Let me start with KMP. We raised the quarterly distribution on KMP to $1.36. For the full year 2013, we declared $5.33 in distributions. That is up 7% compared to 2012, and 5% above our original plan for 2014 of $5.28. Our full year DCF per unit, which we believe is an important way of measuring our success, was $5.39, up 6% from a year ago. Indicating how strong our performance at KMP was, our total DCF was up 28% for the fourth quarter and 26% for the full year, and segment earnings before DD&A was up 22% for the quarter, and 27% for full year 2013.

Steve will discuss the drivers of this growth, but overall, we were pleased with the performance of all five business segments. But I think particularly noteworthy were the integration of the Copano and El Paso assets in our natural gas group, a nice increase in refined products volumes at our products pipelines group, and increased oil and NGL production in our CO2 segment, particularly at our SACROC unit. I am also proud of the progress we have made on numerous growth projects at KMP that position us for a strong future. We have detailed those in our earnings release, but especially important in my view were these recent developments.

First, the series of expansions on our Kinder Morgan crude and condensate line running out of the Eagle Ford into the Houston ship channel, where we have now committed about a $1 billion in capital, and we have long-term commitments for over 200,000 barrels per day when this capital is fully ramped up. Secondly, our very successful binding open season on Tennessee Gas Pipeline for incremental north to south natural gas transportation. Third, our purchase of American Petroleum Tankers and State Class Tankers for $962 million, which we expect to close this month. Fourth, our joint venture with Imperial Oil for a major crude-to-rail terminal in Edmonton, Alberta. And fifth, our letter of intent with NOVA to construct a new NGL pipeline from Harrison County, Ohio to connect with our Cochin pipeline at Riga, Michigan, which in turn will transport the product to Windsor, Ontario.

All of these and a host of other projects resulted in a backlog of $13.5 billion at KMP alone, and I think bode well for continued growth at KMP for the future. As we have previously announced, we expect to declare distributions for 2014 of $5.58 per unit, and that is up 5% from 2013.

At EPB, the story is not as robust, at least not in the short-term. Total distributions declared for the full year 2013 were $2.55. That is up nicely, 13%, from 2012, but distributable cash flow per unit was $2.62 for 2013, down from $2.82 in 2012. Cash generated by EPB's pipeline assets improved year-to-year, and there were a number of moving factors there, but the GP incentive paid to KMI increased by approximately $65 million as a result of higher LP distributions and a slightly higher number of EPB units outstanding. Also, EPB faced some headwinds from two rate case settlements, and from some contract renewals on some of our western pipelines.

The significant recent development at EPB is that Shell has notified us that they will move forward with Phase 2 of the Elba Island LNG JV, which at max volume would involve an additional CapEx of around $500 million, bringing the total investment in that facility to about $1.5 billion. There will also be additional investment and earnings for EPB from required expansion of pipelines connecting to that facility and other ancillary facilities. At EPB, as we have previously stated, we expect to declare a distribution of $2.60 for 2014, and we expect to drop KMI's interest in Gulf LNG and the Ruby Pipeline to EPB during 2014.

Let me turn to KMI. I think we had another fine year at KMI. Again, I believe the numbers speak for themselves. For the full year of 2013, KMI generated cash available to pay dividends of $1.713 billion. That is up 21% from 2012, and exceeding our budget number of $1.632 billion. We declared dividends of $1.60 per share for 2013. That was up 14% from 2012, and our cash available for dividends per share was $1.65 per share. With a total backlog of $14.8 billion in projects at KMP and EPB, we think we have excellent growth in the future at KMI, and that that growth will extend for years to come. We expect to declare dividends for 2014 of $1.72, an increase of 8% over what we declared in 2013.

Now I would be remiss, if I didn't speak of one other topic before turning this over to Steve. While we had an excellent year at the Kinder Morgan companies, both financially and operationally, our units and stocks underperformed the market by a wide margin. Now perhaps we failed to adequately communicate our story, although we certainly tried, and maybe we did communicate it, and the message was not accepted. I don't know the answer to which it was, but I do believe that particularly at KMI and KMP, these securities are trading at the greatest disconnect to appropriate valuation since the period in 2006, just before we took the first KMI private.

Like now, back in 2006, we had an enormous backlog of projects, and like now, many experts opined that we were too big to be able to continue to grow at an acceptable rate. We proved the doubters wrong the first time around, and I anticipate the same result this time. Reflecting this belief in the Kinder Morgan companies, as many of you know, I have been a buyer of KMI shares. I have purchased over 800,000 shares in December alone. So I guess my message to those who saw the story less positively was you sell, I will buy, and we see who comes out best in the long run. And with that, I will turn it over to Steve.

All right. Thanks, Rich. I am going to start with the project backlog. As Rich mentioned, we have been updating this backlog, really starting with the Investor conference in January of 2013, and intend to do it probably quarterly going forward. In the fourth quarter, the backlog increased from $14.4 billion to $14.8 billion, and this is a combined KMP and EPB look. And we had that increase even though we had over $900 million worth of capital projects go into service and come off the backlog during the quarter. So the project additions grew the total backlog, while offsetting the projects that went into service. The larger projects that went into service were on our TGP system, both the Northeast upgrade project and the Marcellus pooling point project, as well as some export coal terminal facility expansions in our terminals business segment.

Now a few facts about how we put this backlog together. First, it is made up of those projects that we are highly confident will get done. Not guaranteed, but highly confident. High probability. We would expect to actually do more projects and invest more capital than what we have in the backlog, but until we consider a project highly probable we don't add it in.

So for example, we don't have in the backlog our current Joint Venture Y-grade project from Pennsylvania to Texas. We believe that project is very attractive as a solution for producers in the Utica and Marcellus, and we are actively marketing it. But we won't put it in the backlog until we see strong indications of commitments coming through.

Now the business unit by business unit composition and change in the backlog is as follows. The gas group went down in the quarter from $2.9 billion to $2.7 billion. That is because we had over $500 million worth of expansions come on line in the gas group during the quarter, and that was partially offset by additional expansions, primarily at EPB associated with our liquefaction JV with Shell at Elba Island, and the associated pipeline expansions.

One other development to keep an eye on. We had a recent very deep freeze as everybody knows a little over a week ago, and we were able to keep all of our firm customers whole. We met all of our firm requirements, including two electric generators who had firm transport capacity on us. But as most of you know, there was a lot of gas generation that was offline in the US Northeast, and was being replaced by more expensive and less environmentally benign fuel sources. What that tells us is that the US Northeast needs a lot more firm transport, and we are actively dealing with customers to try to put something together in the way of an expansion. We think it is going to drive additional investment opportunities for us, but we are not yet putting it in our backlog.

At the products group, it's up slightly to $1.1 billion in the backlog, due to projects further expanding our crude and condensate network in the Eagle Ford. Terminals is up a little under $200 million since the last update to $2.3 billion. We had a little under $100 million worth of projects go into service and come off the backlog during the quarter. But these were more than offset by the tanker buildouts associated with the Jones Act ships acquisition, as some of those -- of which are under construction, along with additional expansions of our crude-by-rail capabilities.

Now there is another point worth noting here, that a lot of activity in two hubs in North America, Edmonton and Houston, and we are rapidly expanding our already large positions there. So in Edmonton, we are increasing our storage capability by 50% to about 6.8 million barrels, and our huge position in the Houston ship channel by 26% to just under 40 million barrels of capacity. So put that in context, we have we believe the largest independent liquids terminal facility in the world in the Houston ship channel, and we are growing that by 26% in capacity. So activities at those two hubs continue to drive midstream investment opportunities for us.

On CO2 source and transportation, the part of the business where we produce CO2 and transport it for our use and for third-party use, we continue to see strong demand. We are up slightly here on the backlog, but still rounds to $1.8 billion as it did last time. In our enhanced oil recovery portion of CO2, we are up from -- up to a little over $1.5 billion from a little under $1.2 billion in our last update, primarily due to additional projects at SACROC and in our residual oil zone recovery new developments. Now in this area, unlike the rest of our business where we are doing these expansion projects with a lot of third-party contracts, this part of our backlog can change based on changes in our development plans, and we had some changes in those plans in the quarter.

And, of course, our biggest project is in Canada. The $5.4 billion Trans Mountain expansion, unchanged from our last update, but we did cross a key milestone in the quarter. We got our voluminous facilities application on file with the National Energy Board, which starts that process under a defined time frame by the federal authorities and -- as we seek approval for that project.

In our recent investor presentations, we have also divided our projects across the years, and we have had some back-end loading associated primarily with TMX, and some front-end loading associated primarily with just the newer projects that we have gotten developed. We have kind of a hollowed out middle, if you will, 2014 and 2015 in the backlog. And that is because it takes us a year or two to develop the projects.

We said we would probably be filling in that middle as we took projects from development stage into the backlog, and that in fact happened. So since January when we first did this to the current update, we have added $2.4 billion worth of projects in 2014 and 2015. So bottom line is we are continuing to find new opportunities that are more than offsetting the projects we are putting into service.

So now we will go through the segment review, and I am just going to focus on 2012, the full year performance versus 2012, and then a little bit about the outlook. So the gas, starting with the gas segment, gas segment of KMP was up 70% in 2013 on a segment earnings before DD&A on a full year basis compared to 2012. And that increase, the result of dropdown transactions TGP and EPNG, and closing of the Copano acquisition in May of 2013, and those acquisitions more than offset the decline year-over-year associated with having divested certain assets in the Rockies associated with our El Paso acquisition. This segment also successfully, and the corporate group as well, successfully integrated the Copano assets, and we exceeded the economics in our acquisition model for the year.

On EPB, asset earnings before DD&A were up slightly on a full year basis. The negatives, which Rich mentioned, electric generation on the SNG system and impact of rate case settlements, were offset by the other EPB assets on a year-over-year basis. Looking ahead here, we continue to be very bullish on the opportunities presented by our natural gas pipeline storage and processing network.

We had a couple large projects come online, as I mentioned, but we continue to add projects, and overall continue to identify and capture opportunities and expansions that are driven by, one, exports to Mexico LNG and even Canada now, Eastern Canada. Two, the demand from electric generation and industrial and pet chem uses; and three, the need to transport gas out of the shale plays, primarily Eagle Ford and Marcellus. And our really epic open season on Tennessee Gas Pipeline for backhaul capacity out of the Utica and Marcellus is evidence of that. The headwinds in the gas segment are rate cases, and the decline in basis spreads on some portions of our network.

CO2 segment earnings share before DD&A were over $1.4 billion for the year, up 8%. Growth was driven by higher volumes and higher prices. I think noteworthy here, oil volume growth was due to performance at SACROC, which was over 32,000 barrels a day in the fourth quarter, up almost 6% on a quarter year-over-year basis and on a full year basis. Growth also came from improved volumes at Katz and the addition of the Goldsmith unit in 2013. Katz averaged just under 2,700 barrels per day. That is up 56% from the average in 2012, and ended the year at around 3,500 barrels a day.

We continue to see strong demand for CO2, and we brought on additional supplies in the quarter with the in-service of our Doe Canyon source field expansion in southwest Colorado, which came in slightly better than budget, way ahead of schedule, and at higher production than planned. So very successful expansion there, and we continue to pursue several large development projects to get more CO2 to our fields and to others.

In the products group segment earnings before DD&A were $784 million. That is up 12% versus last year, and essentially flat to plan. It was essentially flat to plan, even though it was negatively impacted by the California Court of Appeals rate decision disallowing the tax allowance in the second quarter of 2013. That was offset by strong performance at Cochin, Transmix, and the terminals facilities within the product segment. It was very good work by the products team to overcome that regulatory negative and get within 1% of plan for the year.

Also of note here is we are finally seeing some increase in refined products volumes on a year-over-year basis, with volumes up 6.3% with plantation, 2.6% without plantation in Q4, and 4.5% on a full year basis. We also saw the first material increase in volumes year-over-year on our Pacific system since 2007, and we were up [2.1]% on a full year basis on the main line volumes. Looking forward, we continue to add projects to the backlog in this segment, primarily building off our KMCC system in the Eagle Ford, and with additions to our Cochin system, or additional projects on our Cochin system.

Terminals here, our segment earnings before DD&A were $798 million, up 6% from 2012, but below plan. But this group had, I think, even though being below plan had a very good business development year, in terms of laying the ground work for their future and developing additional projects. Highlights here, we started bringing online our BOSTCO terminal project in the Houston ship channel, and our Edmonton terminal expansion. Those projects both had expansions under contract before the first phase was done. So again, highlighting the strong demand for our services in those two locations. And again, we continue to identify and capture numerous opportunities for expansion there.

Kinder Morgan Canada segment earnings were $199 million for the year, down 13% from 2012 due to sale of Express and increases in book taxes. But the main story here continues to be the expansion of Trans Mountain from 300,000 barrels a day to 890,000 barrels a day, expansions under long-term contracts approved by the NEB. We got our facilities application on file, and we expect to complete construction still at the end of 2017. And that is it for the segment overview. And with that, I will turn it over to Kim.

Great. Thanks, Steve. Just going through the numbers, looking at the first page of numbers in the KMP press release is our GAAP income statement, and on that you can see the declared distribution today of $1.36, which results in a distribution of $5.33 for the year.

I am going to turn to the second page and walk you through our calculation of distributable cash flow and the drivers of the growth. That distributable cash flow is reconciled to the GAAP numbers on the first page. The $1.36 -- we generated DCF per unit, as Rich said, of $1.44, which was up 7% versus the $1.36 distribution. That resulted in $36 million of coverage in the quarter. Consistent with what I told you last quarter, we expect to have positive coverage in the fourth quarter.

We also have positive coverage for the year. For the year, distributable cash flow per unit was $5.39, up 6% versus our declared distribution of $5.33. That is $22 million in excess coverage for the year. That comes in just slightly below our budget -- $12 million below our budget of $34 million in coverage.

Total DCF, $635 million in the quarter. That's up $140 million, or 28% versus the fourth quarter a year ago. And just to walk you through the pieces of that, the segments are up $279 million or 22%, with approximately 70% of that $279 million or about $191 million of the increase coming out of the gas group for the reasons that Steve mentioned. $55 million is the growth in CO2, $27 million in products, $23 million in terminals. And then as Steve said, Kinder Morgan was down for the quarter, about $17 million due to the Express sale and book taxes.

Now as you know, book taxes have no impact on our total DCF. Because in our calculation of DCF, we add back book taxes and subtract out cash taxes, and there was not a corresponding increase in the cash taxes. And then, the Express sale overall is accretive to KMP; it's just that it is negative in the segment. We use the proceeds to reduce debt and reduce our equity issuance, and so the benefit of that transaction shows up in other lines.

In the quarter, G&A expense was $127 million. That is $19 million increase in expense. That is largely associated with the El Paso acquisition and the Copano acquisition. Interest expense was $225 million in the quarter. That's up $45 million, so $45 million in incremental expense. In the quarter, that is primarily associated with balance, which is up on average about $2.9 billion. And then in the quarter, we had increased sustaining capital versus the fourth quarter of last year of about $6 million.

So if you take the $279 million increase in the segments, you subtract out the $19 million increase in G&A, $45 million in interest and $6 million on sustaining CapEx, you get to the $140 million increase in distributable cash flow for the quarter.

For the full year, total DCF $2.24 billion, up 26% or $466 million. The segments generated $5.55 billion of earnings before DD&A, up $1.17 billion or 27%. Similar to the quarter, natural gas pipelines, they generated over 80% of the growth. Natural gas pipelines was up $962 million, with the biggest piece of that coming from the drops. Well north of $800 million, close to $850 million came from the combination of the dropdown assets, and the -- including the half of midstream that we bought from KKR.

CO2, it for the year, up $106 million, products up $81 million, terminals up $46 million. And then, Kinder Morgan Canada down $29 million for the same reasons as I discussed that impacted the quarter. G&A expense for the quarter was $521 million. That is up $89 million versus 2012. Also largely similar to the quarter, largely as a result of the El Paso dropdown assets and the Copano acquisition. For the full year versus our budget, G&A was $19 million incremental versus our budget. So $19 million negative, associated primarily with the Copano transaction.

Interest expense was $850 million for the year. That is increased expense of $218 million, and that is a combination of balance and rate. On the -- the balance on average was up about $3.6 billion. And then on the rate, the debt associated with the dropdown transactions, which was assumed with those transaction was at a slightly higher rate than KMP's existing portfolio, and that is largely what drove up the rate. Versus budget, interest expense was very close to budget, within $2 million, and that's -- we had increased interest expense associated with the Copano transaction, and that was offset by increased capitalized interest as a result of incremental expansion during the -- added to our expansion CapEx during the year.

Sustaining CapEx was an incremental $42 million in 2013 versus 2012, and actually came in about $12 million positive versus our budget. Our budget was -- about $6 million of the $12 million was timing, and about $6 million was incremental -- was positive capitalized overhead versus what we originally budgeted. So that is KMP's DCF.

Looking at KMP's balance sheet, I am going to look at the bottom, total debt. Total net debt, we ended the year at $19.5 billion in debt. That results in debt to EBITDA of 3.8 times, and consistent with where we told you we would -- last quarter where we would end the year. Our original budget was 3.7 times, but once we revised it to incorporate the Copano acquisition, we expected to end up at 3.8 times.

The change in debt for the quarter and for the full year -- for the full year, I am going to reconcile to our actual December 31, 2012 debt balance of $15.35 billion. And what you have on the balance sheet is consistent with GAAP, but it has been restated. So it is not actually a recast for common control accounting. So it is not our actual debt balance at December 31, 2012. So the -- using the actual debt balance, the change in debt for the quarter was $458 million, and for the full year, it was $4.2 billion increase in debt.

For the quarter, we had -- we spent cash on expansions and contributions to equity investments of a little over $980 million. We issued equity of almost $440 million. We had -- we received insurance proceeds of about $48 million associated with claims on Hurricane Sandy to rebuild the terminals in the Northeast, and we had coverage of about $36 million.

For the full year, we spent about $10.6 billion on acquisitions, expansions and contributions to equity investments. And then this also includes the first half of the debt associated with EPNG that came on to KMP's balance sheet when they acquired the second half. We raised $6 billion in equity. And just as aside, we raised $1.1 billion in equity through our ATM during the year.

Express proceeds were about $320 million net of tax. We unwound some swaps for $96 million. We had contributions from our JV partners of $126 million. These are for investments or actually assets where we consolidate the asset but -- and then we receive contributions for our partners for their share of the CapEx. And then, insurance proceeds for the full year, $89 million. And then we had a working capital -- use of capital of about $234 million, which is largely associated with AP and AR, storage gas, and also some of the acquisition expenses on the Copano transaction. So that is KMP.

Turning to EPB. The first statement, the statement of income, you can see our distribution of $0.65, which is up 7% and results in $2.55 for the full year, up 13%. So turning to the second page of numbers, our calculation of distributable cash flow, which like KMP, is reconciled back to our GAAP income statement. We generated DCF per unit of $0.66 in the quarter versus a distribution of $0.65. So about $2 million in excess coverage. For the full year, generated $2.62 of DCF per unit versus $2.55 distributions. So about $16 million in excess coverage, and that is about $10 million below our budget due to the delay in the drop of Gulf LNG.

Total DCF was $144 million, down $19 million in the quarter. And just to walk you through that, the earnings for DD&A were $307 million in the quarter. That is down $11 million, as both Steve and Rich mentioned. Primarily the rate cases on WIC and SNG are the reason for the reduction, as well as lower contract renewals on WIC. G&A during the quarter, $20 million expense. That is about $3 million incremental from the fourth quarter of last year. Interest is essentially flat. Sustaining CapEx was a reduced expense, at $15 million, of about $2 million. The higher GP incentive was $7 million, and that gets you to the $19 million change for the quarter.

For the full year, the $569 million in DCF is a $21 million reduction versus a year ago. Looking at the drivers there, the assets generated about $28 million. You can see $20 million of that on the line earnings before DD&A, and then $8 million is a result of reduced non-controlling interest because we acquired the incremental interest in CIG. $20 million decrease in G&A as a result of some cost savings. Interest was $11 million increased expense, primarily increase in rate as we termed up debt associated with the May of 2012 dropdowns at -- towards the end of 2012, and then the GP incentive was higher by about $66 million.

The $28 million increase from the assets, about $40 million similar, then all of that was associated with acquisitions, and then that was offset by the rate case impacts and the other things that I mentioned impacting the quarter. That is EPB's distributable cash flow.

Looking at EPB's balance sheet, we ended the year at total debt of $4.178 billion. That resulted in debt to EBITDA of about 3.8 times. That is up from the third quarter 3.6 times, due to some timing on working capital which I will go through in a second. But the 3.8 times is consistent where we expected to end, what we told you last quarter. The change in debt for the quarter, we had a $67 million increase in debt. We spent $28 million on expansions and contributions to equity investments, and then we had coverage of $2 million, and working capital and other items of a little over $40 million. And the working capital is just timing on accrued interest and property taxes.

For the full year, we had a $55 million reduction in debt. We spent over $100 million, about $104 million on expansions and contributions to equity investments. We issued $87 million of equity. We had positive coverage of $16 million, and then working capital for the full year was a benefit or a source of about $56 million.

Turning to KMI, KMI's distributable or cash available to pay dividends, $482 million in the quarter. That is up $43 million or 10%. That results in cash available per share of $0.46. And so, versus our $0.41 distribution or dividend, results in coverage of $55 million. The increase in cash available to pay dividends of $43 million -- let me just reconcile that for you quickly. The cash coming from our two investments in the MLPs and for the investment of KMP and EPB was up $83 million in the quarter or 15%. G&A was relatively flat.

Interest was a reduced interest of about $12 million. So it was a benefit, and that is largely associated with paydown in debt as a result of dropdown transactions. And then assets, the assets, the other assets that we own, we had a reduction in the cash that we received from those of about $31 million as a result of dropdowns. We had a $21 million increase in tax because of increased income. That gets you to the $43 million.

For the full year, as Rich said, $1.713 billion in cash available to pay dividends results in cash available per share of $1.65, which is $49 million in excess of the declared dividend of $1.60. The $1.713 billion is an increase of a little over $300 million versus the fourth quarter of last year, and is also in excess of our budget by approximately $80 million. On the $300 million increase from 2012, the cash generated from our investments in the two MLPs, up $505 million.

G&A was increased expense of about $15 million, as a result of the full year of the El Paso transaction. Interest expense was increased expense of $27 million, and that was the increased interest associated with the El Paso acquisition, offset by the paydown in debt associated with the dropdown transaction to KMP. The other assets, or a reduction in income of $64 million as a result of the dropdown transactions, and then cash taxes, an increase of $97 million associated with the increased income. And that gets you to the $302 million.

KMI balance sheet, KMI ended the quarter at $9.8 billion in net debt. That is down from $11.4 billion at December of 2012. The $11.4 billion, similar to what I explained on KMP, is our actual ending debt balance at December of 2012. What you see on the balance sheet, the published balance sheet is a recast number. So the $9.8 billion is -- results in debt to EBITDA on a fully consolidated basis of 5.1 times, and on a stand-alone basis of about 3.5 times. The change in debt for the quarter and the year, for the quarter we had a $48 million increase in debt, and that was we spent about $174 million on share and warrant repurchase.

We had about $47 million in outflows associated with some legacy El Paso items, such as the marketing business and environmental. We had coverage of $55 million. And then, we had other items -- a source of cash of $118 million, with the largest piece of that, even more than that, being associated in the difference with the cash taxes that we have in the metric versus the cash taxes that we actually pay. Because we are in an NOL position, the cash taxes that we actually pay are much lower than what is in the metric. The metric only assumes about a $300 million use of the NOL.

For the year, the change in debt is $1.6 billion reduction. We have a $2.2 billion reduction from asset sales. We have share and warrant repurchase of -- which is a use of cash of 600 -- and almost $640 million. We have pension contribution of $50 million. Investments in the MLPs, including the units we took back associated with the dropped KMP, of $66 million. Contributions to equity investments -- this was before we dropped most of the investments to KMP -- was $49 million.

The legacy El Paso, we spent about $95 million. Coverage was a positive $49 million. And then, we had working capital and other items of about -- or inflow of $232 million. Again, all of this and much more is associated with the difference between the taxes, and reflected in the metric and the actual cash taxes that we pay. So that's it for the numbers, Rich.

All right. And with that, Holly, if you want to come back on, and open the line for questions for us?

Thank you.

(Operator Instructions)

The first question comes from Darren Horowitz with Raymond James. Your line is open.

Darren, how you doing?

Fine, thanks, Rich. Good afternoon. Two quick questions for me. The first, and I recognize you are going to provide a lot more detail at the Analyst Day in a few weeks, but I would like just your macro thoughts on the downstream expansion or repurposing opportunities on KMCC? And I know that you have got that lateral in Gonzalez County, so that gives you access to the ship channel, and also the joint venture with Magellan gets you there as well as Corpus. And Steve provided a lot of detail, which we appreciate, on all those terminal expansions. But when you think about the overall demand pull that drives the export of higher end distillates and gas oil to areas like Latin America, let's just say, if you could just outline the opportunity set and require capital that might be necessary in order to meet that demand beyond 2015, that would be helpful?

Well, first of all, from a macro standpoint, of course, we continue to extend KMCC outward into the Eagle Ford. And one of the benefits of the Copano acquisition was the ability to connect KMCC to Double Eagle, and so we can now provide a producer with optionality. He can connect and either go all the way to the Houston ship channel on KMCC. Or if he is in the right place, go down Double Eagle to Corpus. So that is our initial contribution to moving the condensate around.

Obviously, I agree with you that the exporter of refined products is increasingly in vogue. We are handling a fair percentage now that, in all of our assets along the Houston ship channel, and we will continue to expand that by more connectivity, by more berths that we are building, and by more storage capabilities. For example, in conjunction with the splitter, which is an outgrowth of KMCC, and in which we are investing about $360 million per 100,000 barrel splitter that is fully subscribed by BP, we are building two sets of new tanks for that, and that will facilitate the ability to move the split product out. That is not refined products, but it will facilitate that ability. So I think we are pretty much on top of it, given all of the connectivity we have, and I think we will be able to continue to benefit from what we see as a significant trend. Steve, anything else on that?

Yes. I mean, the KMCC right now is about two-thirds full under contract, so there is more room for shippers to get in there. As Rich mentioned, it's interconnecting with Double Eagle, so there is really kind of a network down there now, connecting either Corpus or the Houston ship channel. And then, in connection with the splitter project, we are putting in three new cross channel lines between Galena Park and Pasadena, adding to the existing cross channel lines we have there. About five, I think.

Six.

Six. Okay, and with BOSTCO, we are adding ship docks, adding 12 barge berths, looking at the potential to connect Pasadena and Galena Park with BOSTCO, all those things. It's very hard, Darren, to say well, how much total capital will you put to work there? It's really a question of how much growth there is -- it looks like there is going to be a lot -- and what customers will sign up for. But we are very happy with the network that we have got and its expandability.

Right, I appreciate that. And Steve, last question: I just want to go back to the comments that you made about TGP's open season for that backhaul capacity out of the Northeast. And I know that you said in the prepared comments you are looking at additional expansions there. But can you just give us an idea, as you are looking at basis differentials and talking with producers, what you think the scale and scope necessary to meet that production profile to get incremental gas to the Gulf Coast could be? Because it seems like, recognizing you are not going to build it before commitments are signed, but it seems like it could be significantly larger than existing capacity in the ground?

That's -- we believe that is absolutely true, and so we are out talking to the market right now about another potential expansion. I am sure others are as well. It may have as much to do with how much gets expanded into New England. So how much of the gas ends up going that direction, or into the Northeast generally? But we were -- I guess, maybe some people said they weren't surprised.

I was surprised. And it was a very strong open season, and it has prompted us to start very quickly on the next round. And I think we just have to see whether the -- the first ones are cheaper; the next ones are more expensive. We have to see if the customers are there for a higher price point, and they may not be immediately. It may take some time and some build up, and some ramp up in production in the Utica for people to really get a sense of what they have. But we expect there is more to come. Tom, do you want to add anything to that?

Yes, I think the reconnaissance that we are doing out there (inaudible) in excess of a BCF, maybe closer to 2 BCF. All that is (inaudible) something we will get, but I think it's certainly a representation of what kind of scale is out there, and we are certainly (inaudible) option that we have to head back to the Gulf Coast and/or take it to (inaudible).

What is happening is that the production of the Marcellus and Utica, as all of you on this call know, is so huge that while there is need for more connectivity into the Northeast, particularly New England, the amount of production there has -- is in the process and has already in some respects swamped the demand that can be sucked up by the Northeast. And so, lines like Tennessee are obviously going to become in some respects bifurcated lines. They are going to move a huge chunk of gas downstream from the producing areas of the Marcellus and Utica into the North.

And then, as we found in this open season, we are going to move a lot of gas south to where we think the huge demand is going to be, down here along the Gulf Coast with all of the new downstream facilities being built. So I think it is a very good opportunity for us. The caution would be that obviously, as Steve said, that the cheapest expansibility, the low-hanging fruit is always the first one. And that is why I think we were so tremendously oversubscribed in the open season. But now we are working to see what the next level of demand is, and I think we will capture some of it. Certainly, others will capture some too.

Thank you.

The next question comes from Brian Zarahn with Barclays. Your line is open.

Hello, Brian.

Hello, Rich. Good. Looking forward to seeing everyone in two weeks. First question is on the long-term distribution growth guidance, Is that unchanged with 9% to 10% at KMI, 5% to 6% KMP and EPB; and is that from a full year 2012 base?

So right now, we are going to be able to give you more of update on that. We are right now, that is certainly the last guidance we have given, and we have talked about that 5% to 6% at KMP, 9% to 10% at KMI. And now in preparation for the conference in a couple of weeks, we are now updating that and extending it out to 2018. So we will have an update. We haven't even completed running those numbers, but that will give you -- a horse shoes and hand grenades look from 2014 out through 2018, and we will have it for you at the conference.

Okay, we will stay tuned on that. On dropdowns, what are your thoughts regarding FGT? Previously you mentioned that would be dropped this year; it seems like it's going to stay a little bit longer at KMI. So any color around the ownership of FGT long-term?

No, right now we are keeping it -- we budgeted for the year staying up at KMI. We are just going to continue to look at it. We are going to drop the two other assets to EPB this year, and we just haven't made the decision on when we -- (inaudible).

Okay, and on the marine transportation acquisition, can you provide some color onto the strategy and expanding of that business, and about the timing of the EBITDA ramp up from the $55 million now, and I guess to the $140 million or so you are expecting?

Happy to. I think some people looked at that as this was a big step out for us, and although I think most people saw through as to what our real reasoning is, but let me just take you through it. We are in the midstream transportation business, and the greatest single opportunity -- and why in my roughly 35 years in this business, this is the most interesting time we have had, is we have all of this tremendous increased production coming from areas, and this is true of across-the-board, whether you are talking about crude oil, natural gas, condensate, or indirectly even refined products. We have a tremendous need to transport that from new production areas to market areas. And there are a lot of ways of moving it, and we are primarily a pipeline company, of course. And so, the cheapest, most effective long term way of moving all these products is by pipeline.

That said, and we have discussed this before, there are a lot of reasons, some of it is infrastructure not being built on a timely basis or permitting delays. Some of it is optionality that producers or others want, but there are reasons why pipelines don't satisfy everybody's need. An outgrowth of that is obviously crude by rail. Another outgrowth of that is the Jones Act, and that is why we are pretty bullish on this area.

If you are think about it, if you are talking about moving crude oil, for example, from the Eagle Ford. Very simple to take it down to Corpus, and you can put it on a barge and move it over here to Houston, or over to New Orleans; or you could put it on a Jones Act ship and take it up to the refineries in the Northeast. And I am sure you have seen these figures, and I may be off a little bit on the numbers. But in 2011, there was something like 5,000 barrels a day moving out of Corpus.

This year in 2014, I think the projection is something along the lines of between 350,000 and 400,000 barrels a day moving out of Corpus. Now some of that will go by barge. Some of it will go by Jones Act tanker. So we think this is an asset -- the Jones Act tankers -- that are very important to the energy infrastructure. And there are at least two or three ways in which they are going to grow, the demand for them is going to grow. One is, some of the Bakken crude, as you know, is now being shipped by rail, or at least there is talk of this, going to Oregon and Washington, and then going down by ship to the LA and San Francisco refineries. We think that will see some growth.

Obviously, another area of growth is, as the Panama canal is completed, increasingly we are talking to people -- no firm commitments -- who think that they will use Jones Act tankers that have to be Jones Act to take production out of Texas and move it through the canal and back up to California. And then finally, of course, the Colonials line is completely full on refined products. There may be opportunity to move refined products. So I think that is what is driving the increase in dayrates. As you know, and we showed, I think, in our release, our average dayrates under these long-term contracts are in the $55,000 to $60,000 per day range.

The market today is at least $70,000, and Exxon just did a one year charter which was publicized about two weeks ago for $100,000 a day; and that was for one year, not five years. But we think there is going to be increased demand. We think this is a nice place to be in. We have a good operator who is doing the operatorship for us. So we look at this as an adjunct, another alternative in the area of transportation that we can offer our customers. And we think it is going to pay real dividends for us. And we like the fact we have a whole lot of this cash flow locked in, including all of the new ships being built.

I appreciate the color. On the ramp up to the $140 million of EBITDA, is that over sort of a 2017 time frame, would you expect?

Dax, you want to?

November of 2015 through October of 2016 are the vessels will be coming on. (Multiple Speakers).

So by, everybody, all of the new vessels will be on by the end of 2016.

Right.

Okay.

So it ramps up, and I think it's actually more than $140 million, it is a $140 --?

It's about $146 million.

$146 million that we expect for 2017 once they are all in.

Okay, great. And lastly for me, can you update the number of warrants outstanding at KMI?

Yes, 348 million.

Okay. Thanks, Kim.

Our next question comes from Ted Durbin with Goldman Sachs. Your line is open.

Hello, Ted, how are you?

How you doing? Thanks, Rich. I want to follow-up on some of your opening comments there on the underperformance of the stock and talking about how you think it is cheap. Maybe -- can you be a little more specific around any kind of actions you might actually be able to take? It seems like you alluded to it, but I am just wondering if you can give us anything more there?

Well, the action I hope is that you guys will be so impressed with our performance that the stock price will rise meteor-like, but somehow I don't see that happening in the next 24 hours anyway. (Laughter).

You never know.

What we are looking at, trying to do a better job of communicating the story. I am befuddled, because we have this tremendous backlog, and each of these projects has so much potential. If you take the Trans Mountain expansion, and you look at the spread between our cost of capital and what we are going to make on an unlevered basis on $5.4 billion, and start calculating that and then split it between KMP and KMI. And that alone is a huge growth mover. If you look at some of the projects in the CO2 field, where we are bringing all of this additional CO2 on, and the new developments in the ROZ on the other end of it, tremendous growth. We just took our Board on a tour of the ship channel yesterday right here in Houston. Kinder Morgan is spending $1.8 billion along the ship channel. That is the total projects along there, both in the terminals and the products group. All of these are coming online. We will fill the rest of KMCC.

We started out with one commitment on Kinder Morgan crude and condensate which was from Petra, now BHP for 25,000 barrels a day the first year and 50,000 thereafter. And that justified a 15% unlevered return on a $220 million investment, which -- as you know, we converted some of our natural gas lines to hold down the cost of the investment. Today we have extrapolated that into spending $1 billion dollars in the area, that we now have long-term commitments for over 200,000 barrels a day, and we are going to be adding volume on top of that. That lead to the splitter; indirectly, it led to the reversal of Cochin, which is about a $300 million project.

You look at what we just signed up with NOVA. To connect into to Cochin, to the east end of Cochin, we will be spending $300 million or so building a pipeline there. It, too, will have expansibility. So I look out there, and I see this huge damp footprint across North America; and every time we turn around, we see more ability to extract value out of it. But I guess I haven't been successful in convincing the rest of the world of that, because a lot of people don't see it.

That is where we think we have such an in advantage and such a growth profile for the future. That is why I have never sold a share, and I just keep on stupidly buying more. But that's the guts of it, Ted. I don't know what we -- again, we try to make these points. I am looking at some of Kim's preliminary presentation for two weeks from now. It makes me sit up and take notice, when you look at the tremendous growth next year. We have a growth that is sustaining CapEx next year which we built from the bottom up, which is a little over $100 million growth in sustaining CapEx at KMP. If we had held a sustaining CapEx flat to this year -- if you just take $100 million and divide that out from what it would have done for KMP and KMI, it would have been a whole different story. So we are going to try to do the best job we can of explaining, but we think this is an incredibly strong story. And again, look at the footprint, and look at the opportunities to expand off of that footprint.

That's very helpful, and appreciate all of the color there. Next question for me is just I am thinking about your Y-grade pipeline out of the Marcellus. And I guess, I am a little worried here about any abandonment issues you might have with the FERC. You just mentioned there is tremendous demand to move gas north to south. Is there any risks that the FERC says, we need to keep this pipeline in gas service, and we can't take it out of service?

Yes, look, we are in a very good position there, Ted. This is pipe that is in demand, and it's in demand for gas service, and we think it may be in demand for Y-grade service. And so, that does raise the concern that you identify. But we do think, and what we are aiming for is the prospect of doing a further expansion on our -- on TGP to move additional gas south, and still being able to make room for the Y-grade. Now we will have to do it realistically, and the Y-grade line will have to pay for, or bear the some of the burden of making sure that there is additional capacity on TGP to replace what is being used. But we are shooting for both. We are shooting for the expansion of gas service and Y-grade conversion. But you are highlighting a good problem to have, which is we have got pipe in the ground that is in demand.

And on these -- the sort of backhauls, are you just basically charging max rates? Is that the way we should think about that on TGP now for the gas?

Not max rate, but they are market-rate and they are going up.

But you've got head room effectively if you wanted to go to max, is that fair?

(inaudible).

Does that answer your question Ted?

Yes. No, sorry, I was just asking, is there a lot of room between sort of market and max, I guess is what I'm trying to ask, and get out there.

He didn't hear the answer.

Yes. No, there's room. I can't get into specifics, but yes, we have got room between the market-rates and the max rate.

Got it, sorry, I didn't -- (Multiple Speakers).

It's actually forward movement. We are actually physically moving molecules from North to South. And I think the market continues to refer to it as backhaul. But as an old pipeliner, this is really a forward haul, and that -- those molecules are going to end up in the Gulf Coast, tremendous demand for that, and as Steve says, it is a whale of a nice problem to have.

Yes. Okay. I will let it go there. Thanks.

Thank you.

Next question comes from Craig Shere with Tuohy Brothers. Your line is open.

Hello, Craig.

Hello, good afternoon. Looking forward very much to getting together, and hearing that wonderful presentation down in Houston.

Yes, well, Kim is going to be the star. We are just the supporting cast, but go ahead.

As always. So a couple different questions. Let's start maybe with LNG. How is the FTA contracting going for Gulf LNG? Any update on how you see authorizations coming through for non-FTA requests for Gulf and for Elba? And can you remind us, if you do get that, just how large can the growth pipeline expand?

Well, there's a lot of things assumed in that question. First of all, let's look at our efforts as an LNG developer. The right way to think about Elba Island, even though we are certainly like everybody else applying for non-FTA, is we don't need non-FTA for that. And Shell in December, just exercised its option on the first part of Phase 2.

Now there is another option that can be exercised at the end of this year. But all of that, and if they exercise the second option, we will end up there with a project on a [dayrate] basis something in the $1.5 billion range, and it will be moving about 350 million cubic feet a day through there. That is relatively small by LNG standards, but it is a very nice project for us. We own 51%, Shell owns 49%. And in addition to that, it gave us the opportunity to spend money on other infrastructure necessary to get the LNG there and associated facilities around the terminal. So it's more than just our 51% of $1.5 billion or so, so great opportunity for EPB.

On the Gulf LNG, we continue to look at opportunities there. We talk to customers. We don't have anything to announce at this point. Another big part of the LNG story, of course, is the ability of our pipeline network to serve the LNG facilities, particularly those along the Gulf Coast, and we will have a role at Magnolia, assuming that gets built. We think we will have a role at Cheniere, some of the additional trains at Cheniere, 5 and 6. We certainly believe we will furnish a significant part of the gas at Freeport. And so all along here, we have as many miles of pipeline or more than anybody else, and the ability to connect all kinds of sources of supply and get it to these LNG facilities.

And in the long run, that may be the greatest opportunity for the Kinder Morgan family of companies. We are going to continue to look at opportunities at Gulf LNG. We will see how it plays out. We don't do anything unless we get firm commitments on it, so we will see there. But the opportunity for serving these facilities through our pipelines is enormous. It comes back to what I was saying a question ago, which is the size and scope of our footprint.

Great, and let me follow-up on Brian's question about Citrix. How full is FGT now? Is there still that -- what was it 20%, 30% capacity on the old Phase 8 expansion that was originally uncontracted? And does the tax status have implications of any dropdown decisions?

Dax, do you want to answer that? (Multiple Speakers).

What was that again, Rich?

Well, the first question was on the capacity. Is there any remaining on Phase 8, and the answer is yes. I am not sure what the percentage is, and then the second question was on tax status.

Yes, the -- there is approximately 184 a day remaining of capacity that we are still on a little bit of an interruptible basis, and we are constantly looking at the market to see what we might be able to sell on a term basis. We have had conversations with several people. Tough to tell if we will get anything done on a near-term basis. And from a tax perspective, we certainly, we have some NOLs and some depreciation associated with the Phase 8 expansion that will be running out over, call it, the next four or five years, and the cash tax obligation of Citrix will ramp up over what I would call, the next four years pretty substantially so.

Great, and last line of questioning is around the EOR ops. I noticed a nice bump sequentially from third quarter for Katz Is that finally on track with the modeled performance, and was the 9% jump from the third quarter in SACROC expected or well ahead of expectations? It looked like a nice jump there. And if the market continues to be flustered by that business, which I don't understand why since you have had it for so many years, and it is a smaller part of the business today. But if it is, would there be any way to monetize a portion of the assets, to reduce their overall size, minimize rollover concerns, and help fund growth projects?

Let me start with Katz. We believe Katz is on track. There are no guarantees, but certainly, we have -- we just went through a review a few days ago with the CO2 team, and we think it's in good shape and moving up. As we have said so many times, it was delayed response, but we believe we will get the same amount of barrels out of there as we expected when we first developed it. It is just they are coming a little later.

SACROC, we have said before the old phrase that Tim Bradley taught me, which was that big fields get bigger, and I think that is what we are finding at SACROC. We are just finding a lot of additional opportunities to drill there, a nice increase. That increase is continuing through January. We are averaging between 32,000 and 33,000-barrels a day there. I don't think anybody on this call mentioned the fact that also last year, we set an all-time annual record on the NGL side at about 19,500 barrels a day of NGLs associated with SACROC. So it's going very well, and we think we are going to have additional opportunities to continue to grow SACROC.

I think monetizing these assets would be very difficult. We are not in the game of selling things. We are in the game of buying and expanding, and so we don't have any intention of doing that now. And you are quite correct, I mean CO2, we hold it to a higher level of expected return than our pipeline investments, and rightfully so, and it is a declining part in terms of the overall Company. We are happy to have it. It's a good asset, and remember a big chunk of it and a big chunk of the future growth there, is not on the EOR side it is over there on the S&T side where we are finding some really good ability to produce more CO2, and get it to the Permian Basin.

Right, and one last follow-up on that EOR question. Can you update us -- it seems like propane is recovering, even ethane pricing some degree. Can you talk about what you are seeing in terms of trends there, and also for the basis differentials?

Yes, we are seeing -- we typically look at NGLs as a percentage of crude, and obviously that is climbing up primarily driven by propane, and we continue to see that. We expect that to continue to happen over the next few years.

Thank you. Our next question comes from John Edwards of Credit Suisse. Your line is open.

Hello, John, how are you?

Doing well, Rich, and hope -- it sounds like things are continuing to move forward. Just following up a couple of the earlier questions, just I am curious on the TGP expansion on the gas side, and then comparing that to the proposal to move NGLs? I am just curious which opportunity do you view as bigger, the further backhaul opportunity, or would the NGL transport opportunity, would you view that as larger?

I guess, I would say John, it's bigger if we can do both. And so, we are trying to figure out a way to do both, and that is a function of being able to expand our backhaul, our gas backhaul capacity on TGP, and still leave room for a Y-grade option, and that is really the path that we are on. Now the thing that we have -- there are a few things that have to come together, in order to make that happen. The biggest one of which is that Utica and Marcellus producers have to be ready to commit. And so, as you know we extended the open season.

We and MarkWest extended the open season on the Y-grade line and to the end of February, and we are working actively with customers. We think it's a good project. We think it's a good solution. I think MarkWest -- I know MarkWest thinks it's a good solution and a necessary outlet for producers up there. But it sometimes takes awhile to have that materialize into commitment. But our approach is, we think there is a way to do both. And so, that is what we are pursuing right now. But it's not entirely within our hands, it is up to the market in part.

Okay, fair enough. I mean, can you comment at all on what you think might be -- what is causing the hesitation to commit, or is that something you can't talk about?

Well, no. I mean, I think it is -- look, if you look at the numbers people are projecting a million barrels of additional NGL volume coming out of the Marcellus and Utica, or the Martika, I guess, the combined -- (Laughter). And if that's the case, I mean, you can fill up two pipelines expanded, right? But there is a time lag between projections and -- projections coming true, and people being confident in what they have, and needing an outlet, and signing up for an outlet. And so, it's really just a function of a natural producer. It has a -- where they are working -- not so sure it's a hesitation. They are working first on their production and figuring out how to get it out of the ground, and what it is that is coming out of the ground. And then they start looking for their downstream solutions, and that's a question of timing. They are going to need them. We are convinced they are going to need them. We are convinced that an outlet to Mont Belvieu is going to be part of the answer, but they have to be prepared to sign up.

Okay. That's really helpful. And then, with the -- moving over to SACROC, with the increased production you are seeing, and maybe you will get -- cover this further at Analyst Day. But as far as you keep pushing out the year when you see production rolling over, is it fair to say that is going to be pushed out further once again? And is it now going to be pushed out to say, somewhere around 2018 or so? If you could talk a little bit about that?

Yes, I think there is a number of things that are obviously impacting the infields, we are finding from the seismic we have run, are working out very well. We still have a lot of opportunities there. Our platform areas are doing better recovery than we expected. We are doing some horizontals up there, that are looking really good. These horizontals will allow us to go back in and pick up some bypass pay. This will extend SACROC out several more years, and we will get into that in the conference. But I think you will be surprised how many years out it will extend it.

Our Harvest wells continue to do well. In fact, we are backing off of those a little bit, just to -- we started those when we needed CO2. Now we have kind of got, with Doe Canyon coming on full strength, we have got a little bit more CO2 coming into the basin, so we backed off the Harvest a little bit, not doing as many of those as we had planned this year or next year probably. But still we are around the 2,900-barrels a day with the Harvest well, so that's a good project there too.

Next question comes from Jeremy Tonet with JPMorgan. Your line is open.

Good afternoon.

Good afternoon.

I was just wondering -- I had a couple questions. If you were looking at the natural gas pipeline segment, and you took out what happened with the Copano acquisition, just wondering how that baseline business stacked up against the original budget for the year, if you have that available?

Sure. I think Kim covered that but -- (Multiple Speakers).

I can take you through it. So natural gas versus its budget or versus the original budget was up about 10%. Without Copano, without any benefit of the Copano acquisition, it would have been down about 3%. And the reason that it would have been down was poor performance out of our treating business, lower storage revenues coming on our Texas intrastate, and then our investment in Eagle Hawk, our 25% investment in a JV with BHP didn't ramp up as quickly as we expected it to in our budget.

Got you, great. And then for Kinder Morgan Canada as well, how did things look if you excluded the impact of the Express Platte sale?

If you exclude -- and Express has an impact on Trans Mountain as well, because we had a management fee that Trans Mountain was getting. And so, if you just look at Trans Mountain, other than the loss of revenue from Express, Trans Mountain would have been on its budget.

Great. That's it for me, thank you.

Thank you.

The next question comes from Kevin Kaiser with Hedgeye Risk Management. Your line is open.

Go ahead, Kevin.

The first question I have here is on -- on the natural gas segment, transport volumes were down 5% year-over-year in the quarter, and gathering volumes down 3.4% year-over-year in the quarter. Can you talk about what is driving that?

Yes, I think at least on the gas transport side I think it was, and Tom you correct me, we had record electric generation volumes associated with relative coal to natural gas pricing that was probably a contributor. Not sure if it was the whole story there.

In 2012 versus 2013.

Yes, in 2012 versus 2013, right. I think our sales volumes were actually up, so I think you may be right on transport and gathering, but the sales volumes were up on our Texas intrastate. And then gathering, probably a function of the KinderHawk or the KinderHawk investment -- (Multiple Speakers) Yes, KinderHawk volumes. And so, both on the transport side, and in that case if that's the explanation, at KinderHawk, we have minimum commitment. So it's demand-based on the gas transportation side, and it is take-or-pay, effectively demand-based on the KinderHawk asset as well. Contract minimums.

Okay. Moving to the CO2 segment, what was the EOR side -- in the EOR side of that business, what was capital expenditures in the fourth quarter? Total CapEx for EOR in 4Q 13?

I don't have it with me. Hang on a second.

EOR versus the rest of CO2.

Go to your next question, and we will see if we can find it.

Okay. And KMP, what is the coverage guidance for 2014, DCF versus the guide to distribution?

We haven't given it yet, and we are going to go through the entire budget in two weeks at the Analyst conference, or week and a half, two weeks at the Analyst conference (Multiple Speakers). And the expected coverage on KMP, EPB and KMI.

Okay. And the last question I have is, have you considered amending KMP's partnership agreement for how sustaining capital was defined there? I mean, if you look back at when the partnership agreement was put in place, there wasn't E&P. There wasn't shipping, there wasn't coal royalties. So do you think that amending that partnership agreement would be appropriate to protect the limited partners from dilution?

I don't think we have any present plans, Kevin, to change the partnership agreement. We think it has worked very well. It was something that was put in effect in 1992, long before we bought it, and that we think it does a good job of protecting the limited partners.

And we think our limited partners have gotten a very nice return over those 12 years.

I agree.

And we expect them to continue to get a nice return in the future. The expansion capital for 2013 for the S&T business was a little over $200 million, and we spent about $675 million total in CO2.

You are talking about S&T though?

S&T, and the rest would be oil and gas.

About [$475 million].

And I think, Jim, if I am remembering correctly, if you look at SACROC and Yates together, the total CapEx in there was about $330 million, $340 million. The total DCF on a combined basis was a little over a $1 billion.

Correct.

Thank you. Our last question I'm showing comes from Becca Followill with US Capital Advisors. Your line is open.

Good afternoon. On EPB, flat distribution this quarter and your guidance is for flat distribution for the rest of 2014. Can you talk about what visibility you have, on being able to maybe increase that distribution beyond 2014?

Again, we are going to take you through all of that in two weeks at the conference, and that is what we are working on now, looking out as I said across all of the companies out through 2018. But -- horse shoes and hand grenades, the key thing on EPB is that it is relatively flat. It has very good solid contracts, but has some headwinds, relatively flat. It obviously has -- it will get a nice bump when the Elba Island assets come on line, but we are going to take you through that. Like I said, we are running numbers out through 2018, and going to be able to take you through, on all three companies in two weeks.

Thanks. And then on SACROC, it's probably the biggest bump in production that I have seen on a quarter-to-quarter basis. Is that -- I think you spoke to -- I just want to clarify, is that largely being driven by horizontal drilling?

I think so, and particularly in the North platform. One of the things we are seeing there is, the oil bank was probably pushed more towards the well bores, prior to us even injecting. Because there had been CO2 injected in that area back probably in the late 1990s with [Penz] Energy, so CO2 had already been on the ground. And that's the upside on this is, is we are seeing in tight zones that longer the CO2 sits in there, it starts making that oil bank.

And we drilled some horizontals -- we had trouble getting delays in getting permits from the Railroad Commission for two or three months, and we are producing 400 or 500-barrels a day out of those horizontals that we are using now as injectors. So that gives you an idea of the oil bank that was already there. And that is what gives us a huge opportunity for some of the bypassed oil back in some of the other areas in Bullseye and so forth, where we put a lot of CO2 into the Middle Canyon, and just didn't produce the barrels out we thought we would. There is a great opportunity to go in with horizontals and get that back in there.

Can you speak to how many horizontals you drilled during the quarter?

I believe we drilled four during the quarter.

And then plans for 2014?

We have -- I can't remember all of them. I know we have got a couple of -- that we are going into test the bypass oil, and then I think we have just got our regular development up in the platform area, I think we have got four or five of them set to go there.

Thank you. And then last question, on per unit DD&A, in the CO2 business, it looks like it was a sizeable drop quarter to quarter, about $2 a barrel. Anything in particular going on there?

A drop in the DD&A?

Per unit.

Per unit, I think the key thing there was just the additional barrels that we produced in -- at SACROC, lower rate that we have been able to push in there. We have got a lot more barrels. The infrastructure is now getting to a point where we aren't having to add a lot of extra infrastructure to get to additional oil. And so, that over time is just going to push that rate down.

Thank you, and I am showing no further questions at this time.

Okay. Well, thanks to all of you. I appreciate your sharing some time with us. Thank you, and have a good evening.

Thank you. This does conclude the conference. You may disconnect at this time.