Kinder Morgan, Inc. (KMI) Q4 2013 Earnings Report, Transcript and Summary

Welcome to the Kinder Morgan Quarterly Earnings Conference Call. [Operator Instructions] Today's conference is also being recorded. If anyone has any objections, you may disconnect. [Operator Instructions] And I would now like to turn the call over to Rich Kinder, Chairman and CEO of Kinder Morgan. You may begin, sir.

Okay. Thank you, Holly. Welcome to the Kinder Morgan Analyst Call. We'll be discussing Kinder Morgan, Inc., which I'll refer to as KMI; Kinder Morgan Energy Partners, referred to as KMP; and El Paso Pipeline Partners, referred to as EPB. As usual, we're likely to make statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. I'll do an overview of the results and recent developments, as 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'll take any questions you may have. And 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's 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. 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 5 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'm also proud of the progress we've made on numerous growth projects at KMP that positioned us for a strong future. We've 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 $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 our 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 derail terminal in Edmonton, Alberta. And fifth, our letter of intent with NOVA to construct the 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 these and a host of other projects result 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've previously announced, we expect to declare our distributions for 2014 of $5.58 per unit, and that's 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's up nicely 13% from 2012. But distributable cash flow per unit was $2.62 for '13, down from $2.82 in '12. 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 the higher LP distributions and a slightly higher number of EPB units outstanding. Also, EPB faced some headwinds from 2 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've previously stated, we expect to declare 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 2013, KMI generated cash available to pay dividends of $1.713 billion. That's 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 the total backlog of $14.8 billion in projects at KMP and EPB, we think we have excellent growth in the future of 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'd 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 will find 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've been a buyer of KMI shares. I've 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'll buy, and we see who comes out the best in the long run. And with that, I'll turn it over to Steve.

All right. Thanks, Rich. I'm going to start with the project backlog. As Rich mentioned, we've 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's 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 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're 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's because we had over $500 million worth of expansions come online in the gas group during the quarter, and that was partially offset by additional expansions, primarily to 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 2 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 U.S. Northeast and was being replaced by more expensive and less environmentally benign fuel sources. What that tells us is that the U.S. 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's going to drive additional investment opportunities for us, but we're not yet putting it in our backlog. At the Products group, it's up slightly to $1.1 billion in the backlog due out of 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, some of those are -- which are under construction, along with additional expansions of our crude by rail capabilities. Now there's another point worth noting here, that a lot of activity in 2 hubs in North America, Edmonton and Houston, and we are rapidly expanding our already large positions there. So in Edmonton, we're 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 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 2 hubs continue to drive midstream investment opportunities for us. CO2 source of 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're 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're 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're 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've also divided our projects across the years, and we've had some back-end loading associated primarily with TMX and some front-end loading associated primarily with just the newer projects that we've gotten developed. We've kind of a hollowed-out middle, if you will, 2014 and '15, in the backlog, and that's because it takes us a year or 2 to develop the projects. We said we would probably be filling in that middle as we took projects from development stage into end of the backlog. And that, in fact, happened. So since January, when we first did this to the current update, we've added $2.4 billion worth of projects in 2014 and '15. So bottom line is we're continuing to find new opportunities that are more than offsetting the projects we're putting into service. So now we'll go through the segment review, and I'm just going to focus on 2012 -- 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. That increased the result of the drop-down transactions, TGP and EPNG, and the 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 Pipelines storage and processing network. We had a couple of 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 petchem 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 [ph] 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 32,000 -- 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's 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 a 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's up 12% versus last year, essentially flat to plan. It was flat to plan even though it was negatively -- essentially flat to plan even though it was negatively impacted by the California Court of Appeal's 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 Products segment 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're finally just 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% [ph] on a full year basis on the mainline 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 in our Cochin system. Terminals here, 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 here in terms of laying the groundwork for the 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 2 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 the 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 NEB. We've got our Facilities Application on file. We expect to complete construction still at the end of 2017. And that's it for the segment overview, and with that, I'll turn it over to Kim.

Okay. 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'm 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's $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 it's negative in the segment. We used 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's $19 million increase in expense. That's 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's 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 segment, 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 and 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 as 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 drop-down assets and the -- including the half of midstream that we bought from KKR. CO2 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's up $89 million versus 2012, also, largely similar to the quarter, largely as a result of the El Paso drop-down 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's increased expense of $218 million, and that's 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 drop-down transaction, which was assumed with those transaction, was at a slightly higher rate than KMP's existing portfolio, and that's 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 of 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 -- that's KMP's DCF. Looking at KMP's balance sheet, I'm 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 3.8x, consistent with where we told you we would -- last quarter, where we would end the year. Our original budget was 3.7x, but once we revised it to incorporate the Copano acquisition, we expect it to end up at 3.8x. The change in debt for the quarter and for the full year. For the full year, I'm 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's been restated. So it's not actually a recast for common control accounting. So it's not our actual debt balance at December 31, '12. So 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 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 get -- -- 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 the acquisition expenses on the Copano transaction. So that is -- that's KMP. Turning to EPB. The first statement, statement of income, you can see our distribution of $0.65, which is up 7%, 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 distribution, so about $16 million in excess coverage, and that's 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's 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's about $3 million incremental from the fourth quarter of last year. Interest is essentially flat. Sustaining CapEx was 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 noncontrolling 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 drop-downs 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, so more than 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's 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 3.8x. That's up from the third quarter, 3.6x, due to some timing and working capital, which I will go through in a second. But the 3.8x is consistent, where we expect it 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 was 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 a 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's 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 2 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's largely associated with pay-down in debt as a result of drop-down 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 drop-downs. 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 from the 2 MLPs, up $505 million. G&A was increased expense of about $15 million as a result of a 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 pay-down in debt associated with the drop-down transaction to KMP. The other assets -- or a reduction in income of $64 million as a result of the drop-down 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's down from $11.4 billion at December of 2012. $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 5.1x and on a stand-alone basis of about 3.5x. 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 with the difference in 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's 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 $2.2 billion reduction from asset sales. We have share and warrant repurchase, which is a use of cash of $600 million 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 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.

[Operator Instructions] And the first question comes from Darren Horowitz with Raymond James. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Two quick questions from me. The first, and I recognize you're going to provide a lot more detail at the Analyst Day in a few weeks, but I'd like just your macro thoughts on the downstream expansion or repurposing opportunities on KMCC. And I know that you've got that lateral in Gonzales 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 dis/splits [distribution and splits] and gas/oil to areas like Latin America, let's just say, if you could just outline the opportunity set and required 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's in the right place, go down Double Eagle to Corpus. So that's our initial contribution to moving the condensate around. Obviously, I agree with you that the export of refined products is increasingly in vogue. We're 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 in which we are investing about $360 million per 100,000 barrel splitter that's fully subscribed by BP. We're building 2 sets of new tanks for that. And that will facilitate the ability to move the split product out. It's not refined products, but it will facilitate that ability. So I think we're pretty much on top of it, given all the connectivity we have. And I think we'll 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 2/3 full under contract, so there's more room for shippers to get in there. As Rich mentioned, that's interconnecting with Double Eagle, so there's really kind of a network down there right now, connecting either Corpus or the Houston Ship Channel. And then, in connection with the splitter project, we're putting in 3 new cross-channel lines between Galena Park and Pasadena, adding to the existing cross channel lines we have there, about 5, I think.

Six.

Six, okay. And with BOSTCO, we're 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 we have put to work there. It's really a question of how much growth there is. It looks like there's going to be a lot, and what customers sign up for. But we're very happy with the network that we've got and its expandability. Darren Horowitz - Raymond James & Associates, Inc., Research Division: 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. I know that you said in the prepared comments you're looking at additional expansions there, but can you just give us an idea, as you're looking at basis differentials and talking with producers, what you think the scale and scope necessary to meet the production profile to get incremental gas to the Gulf Coast could be? Because it seems like recognizing you're 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're out talking to the market right now about another potential expansion. I'm 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 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's more to come. Tom, do you want to add anything to that?

Yes, I mean, I think the kind of [indiscernible] that we're doing out there which is [Audio Gap] excess of a bcf, maybe closer to 2 Bcf. [Audio Gap] Not all that is something we'll get, but I think it's certainly a representation of what kind of scale is out there, and we're certainly [Audio Gap] option that we have to head back to the Gulf Coast and/or take it to the [Audio Gap]

Look, what's happening is that the production of Marcellus and Utica is, 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're going to move a huge chunk of gas downstream from the producing areas of Marcellus and Utica in to the North. And then, as we found in this open season, we're 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 the new downstream facilities being built. So I think it's a very good opportunity for us. The caution would be that obviously, as Steve said, that the cheapest expansability [ph], the low-hanging fruit is always the first one. And that's why I think we were so tremendously oversubscribed in the open season. But now we're working to see what the next level of demand is, and I think we'll capture some of it. Certainly, others will capture some, too.

The next question comes from Brian Zarahn with Barclays.

First question is on the long-term distribution growth guidance. Is that unchanged with 9%, 10% of KMI, 5% to 6% KMP and EPB? And is that from a full year 2012 base?

Right now, we're going to be able to give you more of an update on that. We're, right now, that's certainly the last -- the guidance we've given and we've talked about that, the 5% to 6% of KMP and 9% to 10% at KMI. And now, in preparation for the conference in a couple of weeks, we're now updating that and extending it, Kim, out through 2018. So we'll have an update, we haven't even completed running those numbers, but that will give you, horseshoes and hand grenades, look, from '14 out through '18 and we'll have it for you at the conference.

Okay, we'll stay tuned on that. On drop downs, what are your thoughts regarding FGT, previously you mentioned that would 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?

Right now, we're keeping it -- we've budgeted for the year staying up at KMI. We're just going to continue to look at it. We're going to drop the 2 other assets to EPB this year. And we just haven't made a decision on when we -- [Audio Gap]

Okay. And on the marine transportation acquisition, can you provide some color on to the strategy and expanding to that business, and about the timing of the EBITDA ramp-up from the $55 million now to, I guess, to the $140 million or so you're 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're in the midstream transportation business, and the greatest single opportunity, and why, in my roughly 35 years in this business, this the most interesting time we've had, is we have all this tremendous increased production coming from areas, and this is true of across the board, whether you're 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're primarily a pipeline company, of course. And so, the cheapest, most effective, long-term way of moving with all these products, is by pipeline. That said, and we've 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 to that is obviously crude by rail. Another outgrowth of that is the Jones Act. And that's why we are pretty bullish on this area. If you think about it, if you're 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 can put it on a Jones Act ship, and get take it up to the refineries in the Northeast. And I'm sure you've seen these figures, and I may be off a little bit on the numbers, but in 2011, there were something like 5,000 barrels a day moving out of Corpus. This year, in '14, I think the projection is something along the lines of between 350,000 and 400,000 barrels a day moving out of Corpus. 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 2 or 3 ways in which they're going to grow. The demand for them's going to grow. One is, some of the Bakken crude, as you know, is now being shipped by rail, or at least there's 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're 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 Colonial's line is completely full on refined products, there may be opportunities to move refined products. So I think that's what's driving the increase in day rates. As you know, and we showed, I think, in our release, our average day rates 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 1 year charter, which was publicized about 2 weeks ago, for $100,000 a day. And that was for 1 year, not 5 years. But we think there's going to be increased demand. We think this is a nice place to be in. We have a good operator who's 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's going to pay real dividends for us. And we like the fact that we have a whole lot of this cash flow locked in, including all of the new ships being built.

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

Upon completion, Dax, you want to...

November of '15 through October of '16 are the -- vessels will be coming by.

So by -- everybody, all the new vessels will be on by the end of '16. So it ramps up, and I think it's actually more than $140...

Yes, it's about $146 million.

$146 million, that we expect for '17, once they're all in.

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

Yes, $348 million.

Our next question comes from Ted Durbin with Goldman Sachs.

I want to follow-up on some of your opening comments there and the underperformance of the stock and talking about how you think it -- 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'm 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. What we're looking at, trying to do a better job of communicating the story. I'm befuddled because we have this tremendous backlog, and each of these projects has so much potential. If you take the Trans Mountain expansions, and you look at the spread between our cost of capital, what we're 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're bringing all 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's the total projects, along there both in the terminals and the products group. All of these are coming online. We'll fill the rest of KMCC. We started out with 1 commitment on Kinder Morgan crude and condensate, which was from Petrohawk, now BHP, for 25,000 barrels a day the first year and 50,000 thereafter. And that justified a 15% unlevered return on the $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've extrapolated that into spending $1 billion in the area. We now have long-term commitments for over 200,000 barrels a day, and we're going to be adding volume on top of that. That led to the split or indirectly 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 Cochin, to the east end of Cochin, we'll be spending $300 million or so building a pipeline there. It, too, will have expansability [ph]. So I look out there, and I see this huge damn 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's where we think we have such an advantage and such a growth profile for the future. That's why I've never sold a share, and I just keep on stupidly buying more. But that's the guts of it, Ted, and I don't know what we -- again, we try to make these points. I'm looking at some of Kim's preliminary presentation for 2 weeks from now, I mean, it makes me sit up and take notice when you look at the tremendous growth next year. We have a growth that's 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 would've done for KMP and KMI, it would have been a whole different story. So we're 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 I appreciate all of the color there. Next question for me is just thinking about your Y-Grade pipeline out of the Marcellus. And I guess I'm a little worried here about any abandonment issues you might have with the FERC. You just mentioned there's tremendous trip [ph] demand with gas, north to south. Is there any risk that the FERC says, "Hey, we need to keep this pipeline in gas service and we can't take it out of service?"

Yes. Look, we're in a very good position there, Ted. This is pipe that's in demand, and that's in demand for gas service and we think it may be in demand for a Y-Grade service. And so that does raise the concern that you identified. But we do think, and we're -- what we're aiming for, is the prospect of doing a further expansion on our -- on TGP to move additional gas out, and still be and able to make room for the Y-Grade. Now we'll 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's additional capacity on TGP to replace what's being used, but we're shooting for both. We're shooting for the expansion of gas service and the Y-Grade conversion. But you are highlighting a good problem to have, which is, we've got pipe in the ground that's in demand.

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

On max rates -- I mean they're -- the market rates and they're going up, so.

You've got some headroom, effectively, if you wanted to go to max, is that fair? [Audio Gap]

Did 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 that's what I'm trying to ask, get out of there and --

Yes, no, there's room. I can't get into specifics, I guess we're -- we've got room between the market rates and the max rates.

It's actually forward moving, we're actually physically moving molecules from north to south. And I think the market continues to refer to it as backhauls, but it's an old pipeline. 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's a whale of a nice problem to have.

Next question comes from Craig Shere with Tuohy Brothers.

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 guys see authorization, authorizations coming through from 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're 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's another option that can be exercised at the end of this year. But all of that, and if they exercise that second option, we will end up there with a project on a [indiscernible] basis, something in the $1.5 billion range. And it will be moving about 350 million cubic feet a day through there. That's relatively small by LNG standards, but it's 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 terminals. So it's more than just our 51% of $1.5 billion or so. So a 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'll 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're going to continue to look at opportunities at Gulf LNG, we'll see how it plays out. We don't do anything unless we get firm commitments on it, so we'll see there, but the opportunity for serving these facilities through our pipelines is enormous, 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 Citrus. How full is FTT 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 any implications of any drop-down decisions?

Dax, you want to answer that?

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'm not sure what the percentage is. And then, the second question was on tax status.

Yes, the -- there's approximately 184 a day remaining of capacity, that we're still having a little bit on an interruptible basis. And we're constantly looking at the market to see what we might be able to sell on a term basis. We've had conversations with several people, talked to [indiscernible], we're getting things 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 we'll be running out over, call it, the next 4 or 5 years. And the cash tax obligation of Citrus will ramp-up over what I'd call the next 4 years, pretty substantially, so.

Great. And last line of questioning is around the EOR ops. I noticed the nice bump sequentially from third quarter for Katz. Is that finally kind of on track with the model performance? And was the 9% jump from the third quarter in SACROC expected or well ahead of expectations? 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 had it for so many years and it's a smaller part of business today, but if it is, would there be any way to monetize a portion of the assets to reduce the overall size, minimize production rollover concerns and help fund the growth projects?

Let me start with Katz. We believe Katz is on track. There are no guarantees but certainly, we've -- we just went through a review a few days ago with the CO2 team. We think it's in good shape and moving up as we said, so many times. It was a delayed response, but we believe we'll get the same amount of barrels out of there, as we expected when we first developed it. It's just they're coming a little later. SACROC, we've said before, the old phrase that Tim Bradley taught me, which was, big fields get bigger. And I think that's what we're finding at SACROC. We're just finding a lot of additional opportunities to drill there. A nice increase, that increase is continuing through January. We're averaging between 32,000 and 33,000 barrels a day there. I don't think anybody on this call's 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're going to have additional opportunities to continue to grow SACROC. I think monetizing these assets would be very difficult. We're not in the game of selling things. We're in the game of buying and expanding, and so we don't have any intention of doing that now. And you're quite correct, I mean, CO2, we hold it to a higher level of expected return than our pipeline's investments and rightly so. And it's declining part in terms of the overall company. We're 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 OR [ph] side, it's over there on the S&T side where we're 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's recovering, even ethane pricing to some degree. Can you talk about what you're seeing in terms of trends there, and also for the basis differentials?

[indiscernible]

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

Our next question comes from John Edwards with Crédit Suisse. John Edwards - Crédit Suisse AG, Research Division: Just following up a couple of the earlier questions. Just -- I'm curious on the TGP expansion on the gas side, and then comparing that to the proposal to move NGLs. I'm just curious, which opportunity do you view as bigger? The further backhaul opportunity, or with the NGL transport opportunity, would you view that as larger?

I guess, I would say, John, it's bigger if we could do both. And so we're 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's really the path that we're 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 a while to have that materialize into commitments. But our approach is, we think there's a way to do both, and so that's what we're pursuing right now. But it's not entirely within our hands, it's up to the market in part. John Edwards - Crédit Suisse AG, Research Division: Okay, fair enough. And I mean, can you comment at all on what you think might be -- what's causing the hesitation to commit, or is that something you can't talk about?

Well, no. I mean, I think it's -- look, if you look at the numbers, people are projecting 1 million barrels additional NGL volume coming out of the Marcellus and Utica -- or the Martica, I guess, the combined play. And if that's the case, I mean, you can fill up 2 pipelines, expanded, right? But there's 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, I think, a natural producer, with their working -- not so sure it's a hesitation -- they're working first on their production and figuring out how to get it out of the ground and what it is that's coming out of the ground, and then they start looking for the downstream solutions. And that's a question of timing, they're going to need them, we're convinced they're going to need them, we're convinced that an outlet to Mont Belvieu is going to be part of the answer, but they have to be prepared to sign up. John Edwards - Crédit Suisse AG, Research Division: Okay, that's really helpful. And then with the -- moving over to SACROC, with the increased production you're seeing, maybe you'll 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, that's going to 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's a number of things that are obviously impacting the in-fields we're finding from some of the seismic we've run, we're working out very well, we still have a lot of opportunities there. Our platform areas are doing better recovery than we expected, we're doing some horizontals up there that are looking really good, these horizontals will allow us to go back in amidst [ph] some -- pick up some bypass pay. This will extend SACROC out several more years, and we'll get into that in the conference. But I think you'll be surprised how many years out it will extend it. Our harvest wells continue to do well. In fact, we're backing off of those a little bit, just to have -- we started those when we needed CO2. Now we've kind of got, with Doe Canyon coming on, full strength. We've 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'll run the 2,900 barrels a day with the harvest wells, so that's a good project there, too.

Next question comes from Jeremy Tonet from JPMorgan. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: I was just wondering, I had a couple of questions, if you're working 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, [indiscernible]

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 trading business, lower storage revenues coming on our Texas intrastates, and then our investment in the Eagle Hawk, our 25% investment and JV with BHP didn't ramp-up as quickly as we expected it to in our budget. Jeremy B. Tonet - JP Morgan Chase & Co, Research Division: Got you, great. And then for Kinder Morgan Canada as well, how do 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.

Next question comes from Kevin Kaiser with Hedgeye Risk Management.

The first question I have here is 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's driving that?

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.

'12 versus '13.

Yes, in '12 versus '13. I think our sales volumes were actually up, so I think you may be right on transporting, gathering, but the sales volumes were up on our Texas intrastates. And then gathering, probably a function of the KinderHawk or the KinderHawk volumes. And so, both on the transport side, and in that case, if that's the explanation that KinderHawk -- we have minimum commitment, so it's demand based on 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.

[indiscernible] EOR versus the rest of CO2.

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

Okay, and KMP, what's the coverage guidance for 2014 DCF versus the guided distribution?

We haven't given it yet, and we're going to go through the entire budget in 2 weeks at the Analyst Conference, or 1.5 weeks, 2 weeks at the Analyst Conference.

Including the expected coverage.

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's worked very well, something that was put into effect in 1992, long before we bought it. And we think it does a good job of protecting the limited partnership.

We think our limited partners have gotten a very nice return over those 12 years. 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're talking about S&T though...

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

[indiscernible] about 4 75.

And I think, Jim, if I'm 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 $1 billion.

And our last question that I am showing comes from Becca Followill with U.S. Capital Advisors.

On EPB, flat distribution this quarter and your guidance is for flat distributions for the rest of '14, can you talk about what visibility you have on being able to maybe increase that distribution beyond '14?

Again, we're going to take you through all that in 2 weeks at the conference, and that's what we're working on now, looking out as I said, across all the companies, out through '18. But horseshoes and hand grenades, the key thing on EPB is that it's relatively flat, it has very good, solid contracts but has some headwinds relatively flat, that obviously has -- will get a nice bump when the Elba Island assets come online. But we're going to take you through that. Like I said, we're running numbers out through '18 and going to be able to take you through on all 3 companies in 2 weeks.

And then on SACROC, that's probably the biggest bump in production that I've seen on a quarter-to-quarter basis. Is that -- I think, you spent 2 -- I just want to clarify, is that largely being driven by horizontal drilling?

Yes, I think so, and particularly in the north platform, one of the things we're seeing that 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 90s with Penns [ph] Energy. So CO2 had already been in the ground, and that's the upside on this, as we're seeing that in tight zones, that the longer the CO2 sits in there, it starts making that oil bank. And we drilled some horizontals. We had trouble getting delays and getting permits from the railroad commission for 2 or 3 months and we're producing 400, 500 barrels a day out of those horizontals that we're using now as injectors. So that gives you an idea of the oil bank that was ready there, and that's 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 lot of CO2 into the middle canyon, and just didn't produce the barrels out that with that we would. It was a geat 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 4 during the quarter.

And then, plans for '14?

We've -- can't remember all of them. I know we've got a couple of -- that we're going in to test the bypass oil and then I think we've got just our regular development, up in the platform area, I think we've got 4 or 5 of them set to go there.

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

Drop in the DD&A per unit.

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

And I am showing no further questions at this time.

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

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