Kinder Morgan, Inc. (KMI) Q2 2014 Earnings Report, Transcript and Summary

Welcome to the quarterly earnings conference call. [Operator Instructions] This call is being recorded. If you have any objections, you may disconnect at this time. And I would now like to turn the call over to Mr. Rich Kinder, Chairman and CEO of Kinder Morgan. Sir, you may begin.

Okay, thank you, Anna. As usual, welcome to the Kinder Morgan Second Quarter Investor Call. As usual, we'll be making statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. Overall, it was another strong quarter for the Kinder Morgan Companies. Looking at the full year, now that we're halfway through it, we expect all 3 companies, KMI, KMP and EPB, to meet or exceed their distribution targets for the full year 2014. Let me cover just a few significant matters and then I'll turn the call over to Steve Kean, our Chief Operating Officer, who will talk in more detail about our operating performance and the growth in our backlog of new projects; and then we'll turn it over to Kim Dang, our CFO, who will go through the detailed financial numbers for the quarter and year-to-date. On the operating performance side, we had a continued very strong performance from our largest segment, our Natural Gas Pipeline segment, primarily as a result of very good performance at Tennessee Pipeline, El Paso Natural Gas and also positive results from the Copano acquisition, which was made a little over a year ago. In our Products Pipeline segment, our refined products volumes were up again this quarter, up 6.5%. That seems like a very strong number, but that is a little misleading because it includes the volumes on our new Parkway Pipeline project. If you strip that out and go to what I would call a same-store basis, it's -- our volumes for refined products are up 4.4%. That's still about double the EIA number for the second quarter, which was 2.3%. Also in that segment, our new Cochin Reversal project began service on July 1, on time and on budget. In our CO2 segment, we recorded record CO2 production in our source fields in Southwest Colorado, and we had growing oil production led by a 7% increase at our SACROC Unit in the Permian Basin. In our Terminals segment, we had solid growth in earnings before DD&A. About 60% of that was organic, with the balance coming from -- primarily from our APT Tanker acquisition, which we closed in January of this year. Now on the business development front, we had another very productive quarter. Steve will discuss the project backlog, which increased to $17 billion. That's a net increase of $600 million from the first quarter, even after removing from the backlog $700 million in projects that went into service during the quarter, which means that we added about $1.3 billion to the backlog in the second quarter. The bulk of that came in our Natural Gas Pipeline business. Now in the first quarter call, I talked about the tremendous increase in demand for natural gas transportation. Given the increase in demand and the disconnect between where that demand is located, primarily the Gulf Coast, and where much of the new supply is being developed, primarily the Northeast, Marcellus, Utica, that leads to great opportunities, we believe, at Kinder Morgan, where we move about 1/3 of all the natural gas consumed in the United States through our 70,000 miles of gas pipeline. I'm a huge believer, as some of you know, in anecdotal evidence, and there were 2 interesting pieces of anecdotal evidence that surfaced this week. The EIA said on Monday that Marcellus production will be at 15.5 billion Bcf per day in August, and they projected it will surpass Qatar's gas production in September. Now Qatar is the world's third-largest producer of natural gas. I think that gives you an idea of the extent of the production ramp-up that's occurring in the Marcellus. In another matter, another estimate of CapEx of -- estimated to be needed to transport all of this rapidly increasing natural gas production, came from the Inga Foundation this week, and they estimated that there would need to be $114 billion spent on gas infrastructure between now and 2020. Again, 2 more indicia that support the idea I've been talking about, which is this tremendous opportunity to build additional natural gas infrastructure to move this gas around the country from the place it's produced to the place it's really needed. Now putting that into perspective at the Kinder Morgan Companies, we talked about some of this back in the first quarter call. But if you look across the KMP, KMI and EPB gas pipelines, you go back to the beginning of December 2013 until now, we've secured commitments of slightly in excess of 3.5 Bcf a day. These are long-term firm commitments to natural gas transportation capacity. Further, we have now another approximately 1.7 Bcf a day of pending transactions. The majority of this 1.7 is related to third-party LNG facilities, all of which are credible LNG export projects. Now these LNG commitments, together with another approximately 300 million of other per day -- of other pending commitments would bring the total long-term capacity signed up across Kinder Morgan's gas pipelines to approximately 5.3 Bcf per day since the beginning of December. Now to put that in context for you, that represents over 7% of the current daily U.S. natural gas demand. So it's a very significant, very important number. Now among the many projects in the planning stage but not in the backlog is our Northeast Energy Direct Project, where we are targeting execution of preceding agreements during the third quarter. This is a very significant project, and it could move 1 Bcf a day or more from the Marcellus supply area across New York and New England to Dracut, Massachusetts. Again, we expect to have Preston [ph] agreements -- preceding agreements by the end of this quarter. Now the horse is not in the corral yet, but we wanted to make you aware of the potential of that very large project. And we detail the status and progress on numerous other expansion projects and some acquisitions in our earnings releases, including our own LNG projects, additional infrastructure for NGL and crude and condensate transportation and the development of additional CO2 supply for the booming Permian Basin. I won't go into all the detail on all of these, but we're confident that our expansion opportunities will be real growth drivers for years to come at the Kinder Morgan Companies. And with that, I'll turn it over to Steve.

All right, thanks, Rich. We'll start with the backlog. We've been providing quarterly updates for the backlog of our high probability expansion projects for a couple of years now. In this quarter's update, we increased the backlog from $16.4 billion to $17 billion, and that number is combined across KMP, EPB and KMI, so we added $600 million to the backlog, but we were putting in service over the quarter $700 million of projects. So our project additions of about $1.3 billion grew the backlog, while we rolled some of those offsetting projects into service. Of the projects that went into service, the bigger ones were the Terminals group's $250 million BOSTCO project in the Houston Ship Channel; 51 tanks where we completed construction of those in the quarter. The Gas group put into service about $200 million worth of projects, including the first phase of our expansion of southbound capacity on the TGP system. We also had about $115 million worth of projects come into service in the CO2 segment. So overall, the Gas group and the Terminals group led the way. On a net basis, Gas added about $500 million to the backlog, again at KMP and EPB, and Terminals had a net addition of about $200 million. We also added -- we keep track of how we're doing in filling in kind of the middle years of the backlog. We added about $500 million to the backlog for the years 2015 and 2016. Generally, we have a backlog that's front-end loaded for the projects we're working on in the near term and then back-end loaded for our big projects, Trans Mountain and EPB's liquefaction-related projects at Elba. As we proceed, we expect to keep adding those middle years. And if you look back a year ago, the second quarter of 2014, from then until now, we've added $2 billion worth of projects to 2015 and '16 along the way. So again, continuing to show that as we work our way through time, we continue to add to those middle years. So bottom line is we're continuing to find new opportunities and they're more than offsetting the projects that we're putting into service. Backlog is growing. That's a result of the great opportunities we're seeing really across the North American natural gas, oil and condensate network. Now I'm going to go through the segments individually. And here, I'll compare really year-over-year, so second quarter of 2013 to second quarter of 2014, talk about it on a segment earnings before DD&A basis, and then cover some of the key developments. Starting with gas, KMP earnings before DD&A was up $76 million or 13% year-over-year. That's driven by the year-over-year impact of Copano. We had a May 2013 close on that asset. Also, strong performance at TGP; about $41 million associated with TGP itself. And those 2 factors were offsetting declines at EagleHawk gathering and in KM treating in our midstream business unit. At EPB, the earnings before DD&A was up $22 million. Now that's adding back joint venture DD&A to get that year-over-year change. And here, the rate case impacts on SNG and WIC, plus some weaker renewal rates on the WIC system, were more than offset by the benefits of the drop-downs of Ruby and Gulf LNG from KMI to EPB. The key development here, as Rich mentioned, is the demand for long-term firm transport capacity. And really, essentially all the trends that we've been watching and talking about for years, whether that's LNG exports or the growing shale production or exports to Mexico, all those things that we've been watching materialize and grow over these years are now turning into firm, long-term commitments. So those trends have ripened enough that people are now putting ink on paper and signing up to multiyear agreements for significant amounts of capacity. And that has a couple of facts. If you look at the 5.3 Bcf Kinder Morgan-wide that Rich pointed out, over 700 million of that is existing system capacity that was previously unsold. And a significant part of the expansion projects make use of the existing system as well. So what that means is these things, this trend, this capacity sign-up is driving not only investment opportunities for us, it's also driving values on our existing system. And we're not through yet, we think. If you look at -- I talked about the trends that have really manifested themselves and turned into firm transport contracts, there are other trends that we're all aware of that have not fully translated into firm transport agreements yet. So they haven't fully played out. For example, growth in natural gas-fired power demand, increasing conversions from coal to natural gas, et cetera, on the power demand side. Also, industrial demand and petchem demand. We are starting to see in our Midstream group customers in the industrial side signing up for some slightly longer-term commitments as they see demand for capacity in the future increasing, but there are -- you can read these estimates. Some of them are mind-boggling, but $100 billion of investment in Louisiana alone, tens of billions of dollars in Texas, well over $100 billion across the Gulf Coast. And we're just on the front edge of that. So I think there's more to come in terms of what our network will be called upon to do. The other big thing is that I think some of these trends, particularly power demand but also LNG, they're going to become consumers of storage. And storage values have been depressed. And I think we're at the beginning of seeing some of that turn around as well. Now it's not all good news. There are difficult basis spreads in some parts of the country still, particularly in the Rockies region. But overall, the trend is very good and the performance year-over-year is very strong. Turning to CO2. Earnings before DD&A is up $9 million or 3% on a year-over-year basis. There, the growth is driven by higher CO2 and oil volumes. We also had higher CO2 and NGL prices. On the oil price side, we had higher oil prices but we sell at Midland. And the Midland-to-Cushing spread really completely offset that for us. But we did experience higher CO2 and NGL prices. And on the volume side, really good growth; SACROC continues to perform extremely well, above its plan and up 7% on a year-over-year basis. Adding to that improved volumes on a year-over-year basis at Katz and the addition of the Goldsmith Unit. And those more than offset somewhat lower volumes at Yates. And looking forward, we continue to work on several large development projects to bring more CO2 to our fields and to the market as well. Turning to products. Earnings before DD&A, up $30 million or 17% on a year-over-year basis. The year-over-year improvements were at Transmix, KMCC and SFPP, and those were offsetting a decline at Cochin. Cochin, in the second quarter, we were really in the thick of physically turning the system around from being a NGL and propane north-to-south-flowing facility to a condensate south-to-north-flowing facility, which we started taking initial receipts in on July 1 on that conversion. Key developments here, improved refined products volumes year-over-year, as Rich mentioned, and ramp-up of KMCC volumes year-over-year, but also especially in the latter part of the second quarter. We covered refined volumes, but we also saw biofuel volumes go up 7% year-over-year and increased our share, if you combine what we handle in the Products group with what we handle in Terminals to 33% of the ethanol handled nationwide. Looking forward, we continue to advance the growth projects we have, primarily building off of KMCC system in the Eagle Ford Shale and our Cochin Reversal Project, and we continue work on the UTOPIA and UMTP prospects as well, although neither of those are in our backlog at this point. In the Terminals business unit, earnings before DD&A is up $36 million or 18%. That's split about 60-40 between organic growth and acquisitions. On the acquisition front, the main impact is about $12 million year-over-year attributable to the APT Jones Act vessel acquisition. On the organic side, we had some big expansions coming online, and the year-over-year uptick from that at Edmonton and BOSTCO and the Houston Ship Channel. Overall, year-over-year liquids throughput was up 8.3%, primarily crude and biofuels there. And if you look at where we stand now compared to last year, we have added capacity to the tune of 16%. We're up to 72 million barrels of liquids capacity, but our utilization has stayed essentially flat at 95%. So we're putting that capacity on, and it's getting fully utilized. On the bulk side, we saw improvement in petcoke, that's our BP Whiting expansion, also on steel volumes, offset somewhat by higher labor and utility costs. And we had weak coal volumes. It didn't really have an impact on the year-over-year financial results because we have take-or-pay contracts, but overall, volumes were weak in the coal markets, and we had expansions that came online over that period. But netting it all out, total bulk volumes were up about 2% year-over-year. During the quarter, we also added a new-build Jones Act vessel to the fleet. We'll be taking delivery in 2017. It's already under long-term charter with a major shipper. And looking forward here, as you can tell by the utilization numbers going hand-in-hand with those capacity increases or in spite of, if you will, those capacity increases, we continue to see very strong demand for liquid storage and handling, particularly in Houston and Edmonton. That bodes well for expansion but also for our renewal rates going forward. And some of those expansions are kind of the traditional tanks and terminal-ing facilities but also seeing expansions in crude-by-rail opportunities. And again, the hub of those things is in Edmonton and the Houston Ship Channel, for us, Edmonton and the Houston Ship Channel. Kinder Morgan Canada. As usual, the big story here continues to be our Trans Mountain expansion, where we're expanding our existing system from 300,000 barrels a day to 890,000 barrels we've got under long-term contracts. Those contracts' structure and the economics are all approved. We're working our way through the NEB process, and our key objectives here are complete our work, meet the NEB standards, consult with the First Nations, accommodate provincial and local authorities, et cetera. We do have one recent update here. We, yesterday, got a revised schedule order from the NEB. And essentially, the issue here that is being addressed is the last about 5 kilometers of build from Burnaby Mountain, which is where our tank farm is, down to the dock. It's a heavy urban build. We've looked at multiple routes to accommodate local concerns. And the NEB has set aside a separate kind of 6-month process to evaluate which of those routes on that last piece of the build is the most optimal. And they have allowed an extra 6 months for that process, a little over 6 months. And they extended the deadline and the procedural schedule by that same 6.5 or 6 months and 3 weeks from what was going to be a July of 2015 date to a January of 2016 date. So that will have an impact on the schedule. That will have a delay, cause a delay of the schedule, but we don't know what the magnitude of it is just yet. There are a lot of hands to be played here in terms of looking at how we're going to approach construction, staging of the construction, et cetera, what we might ask for on the procedural front to try to move things along a little more quickly. We're in the early days; this just happened yesterday, in the early days of evaluating it. But -- so where we were on a very tight schedule for the very end of 2017, we feel like we are going to get pushed into 2018 with this order. It's just a question of how far, and we'll be evaluating the best way to handle that from here. All right. That's the segment update. With that, I'll turn over to Kim for the rest of the numbers.

Okay. All right. So looking at the financials on KMP on the first page of financials, which is a GAAP income statement, today, the KMP board approved a distribution per unit of $1.39, which is a $0.07 increase or 5% increase over the second quarter in 2013. That results in a year-to-date distribution per unit of $2.77, which is $0.15 or a 6% increase over the first 6 months of 2013. On the GAAP income statement, there's not a lot to focus on here from my perspective. I'll just point out one thing. You can see that net income attributable to KMP is down $339 million in the 3 months. That's largely effect -- that is the effect of certain items, with the largest of those being the $558 million revaluation gain that we had in the second quarter of 2013 when we had to revalue the second half of our Eagle Ford -- or the first half of our Eagle Ford investment at the same value, at the same price we paid for the second half that we bought in the Copano transaction. Those certain items is really why we focus your attention on the second page, which is our calculation of distributable cash flow. And obviously, we reconcile this, our distributable cash flow, back to our GAAP numbers. But DCF per unit in the quarter was $1.23, up from $1.22 in 2013, so about a 1% increase; year-to-date, $2.77, so up $0.10 or 4% from the first 6 months of 2013. The $1.23 versus the $1.39 of our declared distribution means that we have negative coverage in the quarter of about $75 million. And as we tell you every quarter, we expect to have negative coverage in the second quarter and the third quarter, positive coverage in the first and the fourth and excess coverage for the full year. Year-to-date, we are right on top of the declared distribution. We've generated $2.77 and declared $2.77, so flat coverage year-to-date. Total DCF is $561 million in the quarter. That's up $56 million or 11% versus the second quarter of 2013. Year-to-date, we generated $1.254 billion in distributable cash flow, which is up $199 million or 19% versus the first 6 months of 2013. Now I'm going to reconcile for you guys where the $56 million increase comes from for the 3 months and where the $199 million comes for the 6 months. So if you look up at the total segment earnings before DD&A, $1.478 billion in the quarter, that's up $141 million. As Steve took you through, $76 million of that is coming from natural gas. So about 50% of the $141 million is coming out the Natural Gas segment; and then Products is delivering about $30 million of the $141 million; and Terminals, $36 million of the $141 million. If you look year-to-date, segment earnings before DD&A is up; at $3.047 billion, is up $434 million or 17%. Natural gas is up $302 million, so it comprises about 70% of the $434 million in growth. And then you also have nice increases coming from CO2, Products and Terminals. Year-to-date, from total segment earnings before DD&A, we are right on top of our budget. For the full year, we expect to exceed our budget by about 1% on total segment earnings before DD&A. And let me take you through a couple of the segments. Natural gas, as we say in the press release, we expect to exceed our budget for the year, primarily based on outperformance at TGP and EPNG based on new transport contracts. CO2, we expect to be very close to this budget, to meet its budget. And there, we are -- we have a benefit from a higher WTI price, but a lot of that benefit is being offset by the negative Midland-Cushing differential that Steve mentioned earlier. On Products, we expect to come in slightly below its budget, primarily due to lower volumes than we anticipated on KMCC. And Terminals, we expect to exceed its budget, largely a function of the APT transaction. Without APT, Terminals would come in below its budget, primarily due to weaker coal volumes and some slight delays that we've had on expansion projects, some higher OpEx and some negative FX. G&A in the quarter was $136 million of expense versus $134 million in the second quarter of 2013, so about $2 million in incremental G&A in the quarter. Year-to-date, G&A is increased expense of about $28 million, and that is actually above year-to-date versus our budget. We are exceeding our budget, so G&A expense is higher than our budget year-to-date. And we expect that it'll be a little bit higher, maybe 1% higher, than our budget for the full year. So we do have some timing between the year-to-date and the full year. On interest, $233 million in the quarter; that's up. That's increased expense of $16 million in the quarter. We have an increase in interest expense of $57 million year-to-date. Almost all of that year-to-date is on balance. In the quarter, it is primarily balanced, but we do have a little bit of benefit from lower rate in the quarter. Year-to-date, of course, is our budget. Interest expense is slightly positive, and we expect to be slightly positive for the full year at this point in time. And then the last big component to get to your $58 million -- $56 million increase in distributable cash flow and the $199 million for the year, the last big piece other than the GP is the sustaining CapEx, up $29 million in the quarter, up $53 million in the year-to-date. But we are actually running behind our budget in terms of expenditure. So we're running a positive variance, but that's all going to be timing. For the full year, we think that we will be slightly ahead of our budget or spend slightly more on sustaining CapEx than we budgeted, largely because of the APT acquisition which was not in our budget. And then the GP incentive in the quarter is up $48 million; and in the year-to-date is up $100 million. And that gets you roughly -- those numbers, if you take the $141 million for the quarter and increase in earnings before DD&A, you take out $18 million of incremental expense on G&A and interest, $29 million on sustaining CapEx and $48 million on the GP, that gets you to roughly $56 million increase in the quarter. Now our budget for the full year in DCF per unit, right now, we expect that we would exceed our DCF per unit budget at KMP. So that's it for the DCF at KMP. Looking at KMP's balance sheet. KMP's total assets increased by about $1.8 billion, and that's largely a function of acquisitions and its expansion program. We ended the quarter at $20.7 billion in debt, that's about 3.7x debt-to-EBITDA, which is down slightly from the 3.8x that we ended the end of last year and where we ended the first quarter. And we expect that we will end 2014 at about 3.7x, which is consistent with our budget. Debt in the quarter increased $178 million. For the full year or for the year-to-date, it's increased $1.17 billion, so almost $1.2 billion. Let me reconcile those numbers for you. The $178 million in the quarter, we spent a little over $800 million, about $814 million between acquisitions, expansion CapEx and contributions to equity investments, with almost all of that being expansion CapEx and contributions to equity investments. We raised about $592 million in equity and then we had about $44 million in working capital and other items, largely associated with working capital source on accrued interest. Year-to-date, the $1.2 billion increase in debt or $1.17 billion are acquisitions and expansion CapEx. We spent almost $2.6 billion; that was $2.572 billion of spending. We had about $993 million year-to-date in acquisitions, with the balance of the $2.57 billion being expansion CapEx and contributions to equity investments. We raised just under $1.4 billion. So simple numbers, we spent $2.6 billion, we raised $1.4 billion. The actual number is $1.395 billion was raised in equity, and then we had a very small amount of working capital and other items to get you to the $1.17 billion change in debt year-to-date. Turning to EPB and the first page of the EPB numbers, the board today approved a cash distribution per unit of $0.65. That's up 3% from the second quarter of 2013. Year-to-date, that translates into $1.30 of distribution per unit versus $1.25 in the first 6 months of 2013 or a 4% increase. On the second page of EPB's numbers, where we go through our distributable cash flow, EPB generated distributable cash flow per unit of $0.62 in the quarter. You compare that to the $0.65 distribution, so it had negative coverage of about $6 million. It's similar to KMP. And what we tell you every quarter, we expect that EPB will have negative coverage in the second quarter and the third quarter, positive coverage in the first and the fourth and positive coverage for the full year. For the year-to-date, the DCF per unit is $1.37 per unit compared to the declared distribution of $1.30. So year-to-date, EPB has positive coverage of about $15 million. Total DCF in the quarter was $141 million. That's up $12 million or 9% versus the second quarter of 2013. For the 6 months, DCF was $304 million, up $6 million or 2%. And so now I'm going to reconcile for you the $12 million increase in the quarter and the $6 million increase year-to-date. If you look up on the top line, earnings before DD&A increased $1 million. But as Steve mentioned earlier, that doesn't tell the whole story because for our investments, we add back, down below in our calculation of DCF, JV DD&A, we subtract out JV sustaining CapEx. The reason we do this is to more closely reflect in our DCF calculation what we receive in cash distributions. So when you add back the JV DD&A down below, that's $21 million, then there's a $4 million adjustment that is negative for some deferred revenues, basically to get our DCF closer to cash. So there's about an $18 million increase coming from the assets. Likewise, on a year-to-date basis, earnings before DD&A of $605 million, that's up $3 million. That doesn't tell the whole story. If you add back the JV DD&A and subtract the other adjustments to DCF of $6 million, that also gets you to an $18 million increase year-to-date. And that's largely driven, as Steve mentioned, by the drops that we did in May, somewhat offset by the rate case impacts on WIC and SNG and the lower contractual renewals on WIC. G&A for the quarter was a $19 million expense. That is actually down from the first quarter -- or the second quarter of 2013. Year-to-date, it's an expense of $39 million, which is also down from last year about $2 million. Interest is flat in the quarter versus last year, and it's down about $2 million. And that's a result of maturities being replaced with lower rate debt, somewhat offset by the issuance that we did for the drop-downs in May. And then sustaining CapEx is flat in the quarter versus last year. It's about a $1 million increase in sustaining CapEx year-to-date. So $18 million plus the $2 million benefit on G&A or lower G&A gets you to $20 million in the quarter. The GP interest increased by $8 million as a result of the higher distribution to get you to $12 million increase at EPB. Likewise, on the year-to-date, $18 million coming from the assets, benefit of $4 million between G&A and interest, deduct $1 million on the increased sustaining CapEx gets you to $21 million, less $15 million for the increased GP incentive to get you to the $6 million. As we said in the earnings release, we expect EPB to meet its distribution per unit for the year of $2.65. Right now, EPB in terms of DCF per unit, is running slightly ahead of its budget. On EPB's balance sheet, there's one unusual thing that I would point out here, which is total assets increased by $1.6 billion. And you think about the drop-downs and the spending that I'll go through, that's only about $1 billion. And so the reason, you can see in the investment lines increase by $1.7 billion, those assets went on the books at KMI's carrying value and then the difference between what EPB paid and where we're putting them on the books, i.e. KMI's carrying value, is considered an equity contribution by the GP which you can see occurring in other partners' capital. We ended the quarter with $4.7 billion of debt; that's 4.2x debt-to-EBITDA. That's higher than where we ended last year and higher than where we ended the first quarter. But that's because you only have 2 months of the drop earnings, but you have all the debt on your balance sheet. We still expect to end the year at about 4x, maybe slightly better. And that would be consistent with our budget. We -- the debt increased in the quarter $629 million, it increased year-to-date $563 million. Looking at the uses of capital, we spent about $989 million in the quarter between acquisitions, expansions and contributions to equity investments, with the largest component of that being the $972 million drop. We raised $387 million in equity, and then we had a use of working capital and other items of about $27 million, largely associated with accrued interest and a use of capital associated with AP and AR. Year-to-date, $563 million increase in debt. We spent a little over $1 billion, again with the largest component of that being the drop at $972 million. We raised about $422 million in equity, and then we had a source of working capital and other items of about $20 million. The primary driver of that was accrued taxes. Now turning to KMI. At KMI, we are declaring a dividend today of $0.43. That results year-to-date in a declared dividend of $0.85. Cash available per share in the quarter was $0.32. That translates into negative coverage in the quarter of $113 million. The same thing here, as I say on KMP and EPB, we have negative coverage at KMI in the second and the third quarter, positive in the first and the fourth and we expect to end the year at about 1x. We generated cash available to pay dividends, $332 million in the quarter. That's up $38 million or 13%. And just looking at the drivers of that 13%, the cash generated by the MLPs was up $65 million, and then that's offset a little bit by the cash generated from the other assets, because we've dropped down these assets we no longer have, that cash flow coming from those assets, although there are some offset coming back from the MLPs. So that's about $47 million net of the cash generated from the other assets. We got about a $4 million reduction in between G&A and interest expense. And then you tax effect that to get to the $38 million. Year-to-date, the increase in this cash available to pay dividends is $98 million or 12%. And very similar circumstances here, you've got $134 million or 11% increase coming from the cash generated by the MLPs, offset by a reduction in cash from the other assets of about $29 million. You have a benefit in interest and G&A. You have primarily lower G&A expense. You tax effect that, and that gets you to the $98 million. Right now on cash available for paid dividends, we're running slightly ahead of our budget, and therefore our guidance that we expect to declare at least $1.72. At KMI, on its balance sheet, we ended the quarter at $9.28 billion in debt. That's about 4.9x debt to EBITDA. That's down from the 5x where we ended the year. 4.9x is consistent with where we expect to end 2014 and also consistent where our budget expected us to end 2014. Debt in the quarter, down $728 million; year-to-date, down $547 million, with the primary driver of the reduction in debt being the drop-down proceeds, but I'll take you through a little bit more of the detail. Drop-down proceeds were $875 million. That's the $972 million that EPB paid. KMI took back 10% equity, and so that's how you get $875 million of cash proceeds. We repurchased warrants of about $43 million. We had negative coverage of $113 million, and then we had a whole host of other items that were about $9 million. Year-to-date, $547 million reduction in debt; $875 million in drop-down proceeds; $98 million in warrant repurchase; $94 million in share repurchase; $50 million in a pension contribution; $25 million positive coverage year-to-date; and then use of capital of $111 million on a whole host of items, which include the fact that KMR is not -- we chose not to monetize the KMR shares that we received as a distribution. The cash taxes that we pay actually are lower than what we reflect in the metrics, so that's a benefit. We had some onetime items associated with marketing payments from the legacy -- marketing environmental payments associated with the legacy El Paso assets, and then we had some timing on the distributions that we received versus what's reflected in the metric of about $59 million and then some other smaller items. So that's KMI.

Okay. And before we open it to questions, let me just clarify one thing. When Kim talked about KMCC, Kinder Morgan Crude & Condensate, obviously the volumes there dramatically improved from the second quarter of '13, but she said we were below plan. And the reason for that is we have one shipper that has a take-or-pay contract that is not meeting those take-or-pay minimums. We're getting the cash but because of the period that, that shipper has for makeup rights, we can't book all of that at this time. So that's the difference or the main part of the difference in KMCC not being on its plans. And for those of you anticipating the question on the warrants, Kim usually mentions that. Kim, our final warrant count is?

We have about 298 million warrants outstanding.

Okay. And with that, Anna, we will open the floor to questions.

[Operator Instructions] And it looks like we have the first question from Darren Horowitz from Raymond James.

Got 2 quick questions. The first, and I'm sure you've gotten this question a lot, with regard to comment -- condensate and the Commerce Department's commentary on stabilized condensate exports, I'd just like your view on how you think that changes the balance between supply and demand for Eagle Ford condensate, obviously production trends and its impact on price. But more importantly, infrastructure development, whether you think we need incremental splitting capacity beyond what's been announced either for the export of light naphtha or gas oil, or if you think there could be a bigger infrastructure opportunity for you to add fuel-level stabilizer capacity and possibly leverage your ability either dock access on the ship channel or at Galena Park or even to move product on Double Eagle down to Corpus?

Yes, it's a very good question, Darren, and it cuts a lot of ways. There's a big disagreement in the industry or, I think, on how big this condensate move really is and whether people are going to have to apply for permits or just ride on the decision of the department on those 2 requests. We think they probably will only get comfort if they actually file for their own permits. With regard -- let me start with the easy question on the splitters. Clearly, we have a 100,000-barrel per day splitter that we are building on the Houston Ship Channel. That's fully contracted with BP for a long period of time. So it really doesn't impact that. I think as far as future splitters are concerned, it's going to make the potential people who utilize those splitters probably think carefully about whether they want to proceed. The benefit to us, though, is that our KMCC line is a batch line, and we can move that kind of condensate through the line with the Houston Ship Channel. And we have a lot of dock capacity at the ship channel, and we're building considerably more. So we could take that condensate and then ship it out at our facilities at Pasadena and Galena Park. The other thing that's very interesting to us is that the stabilizers that are apparently necessary to qualify the condensate for export, that's right down our sweet spot in our Kinder Morgan treating. And in fact, one of the 2 that got their permit is using one of our stabilizers. So we know our stabilizers fit the bill as far as qualifying condensate for export, so we see that as an upside for our stabilizer business. I think overall with regard to the Eagle Ford, there's clearly a lot of condensates you hear of, all kinds of numbers being bandied about. 800,000 barrels a day was one number I saw. But clearly, I think the condensate will move. This will be a positive for it in that sense, and we hope to handle as much as we can through our pipelines and across our dock. And we will continue to complete the splitter and obviously, we'd not have built anymore anyway unless we have customers who are willing and want to stand behind taking -- utilizing the capacity of those splitters. Steve, anything else?

I just think, as you said at the beginning, there's a lot of development to be played out here yet, I think. It's generally positive for us and positive for our infrastructure and positive for the Eagle Ford overall. Just how quickly it materializes is, I think, the big question, but we've got several ways to play it.

Yes, and, Steve, if I could, just one follow-up question to that. When you think about what you can move, and Cochin's a great example of this, but what you can move up to Canada as [indiscernible] oil sands production, you think about what's going to be going to the Gulf Coast to be split, and then you try and balance that with the aggregate amount of Eagle Ford light sweet condensate production growth over the next few years, how much incremental demand for stabilization capacity do you think KM Treating could benefit from? Do you have a rough sense of either the scale or the associated CapEx?

I don't have a rough sense of it. Tom, do you have any...

Yes, it's a little early to know.

It's early to know. I mean, there's a lot of stabilization that's already taking place. I mean, people have facilities in place already. We're receiving stabilized condensate already at our facility. So some of that is already in place and we're in the early days of exploring this. But I think Rich mentioned this; the one opportunity for us is to take available space in KMCC. We've got plenty of truck offloading facilities that are attached to that system, which is now kind of a network going to multiple markets and moving it up to the ship channel and utilizing some tanks in the Terminals groups and some dock and a dock line and getting it offshore. How much more incremental stabilization we'll need to be done? As that production grows, it's just hard to get a handle on, I think.

Our next question comes from Brad Olsen from Tudor, Pickering.

My first question is actually for Rich. And as you might imagine, if you read our note this morning, it's kind of a follow-up on that. You guys are now sitting at a point where you've done billions of dollars of accretive deals over the last few years, and yet KMI remains at a discount to peers that I would imagine is pretty frustrating from your perspective. So as you sit and kind of look at where you're trading versus some of your peer companies right now, do you have any thoughts on that current discount, and whether or not you'd be willing to consider a transaction to reduce Kinder Morgan's cost of capital?

Let me just say that we're always exploring operational and strategic opportunities to enhance the value for our investors, including myself. And that includes, among other things, evaluating potential combinations of Kinder Morgan companies. But as I've stated in the past, any such transaction or combination would have to be on terms negotiated between the companies and mutually agreed upon.

And that would involve just kind of the standard conflict committee process that these arm-length transactions go through?

That's correct.

Got it. Are there any deals within the companies that are categorically kind of unworkable due to tax liabilities or just the overall corporate structure from your opinion?

Again, we are looking at any possible alternatives, and some certainly would seem more doable than others.

Got it. All right. Great. I have a follow-up on the UMTP project out of the Northeast. It seems as though NGL oversupply is kind of just around the corner, and production from processing plants in the Marcellus and the Utica is increasing rapidly. And yet it seems difficult for not just your project but also for some of the other projects that have been proposed. We're yet to see a contracted committed project go forward to take NGLs out of the Northeast. What has been kind of the remaining sticking point on that project? It seems like a no-brainer from a strategic perspective for your producer customers out there. What is it then that has made it so easy for you guys -- or not easy, but it's been a lot easier to fill up gas pipelines and maybe a little bit more challenging to fill up NGL pipelines out of the Northeast?

Steve?

Sure. Well, let's start with the last part of that. Remember, this is an existing TGP line that we're talking about converting to a new service and reversing. And if, for some reason, we're not able to get contractual commitments on UMTP, we would look for projects to use that capacity for gas service. So we're in a good position in that regard. But to your real question about what is it with producers and not getting things signed up, I mean, I think there are important differences in the market structure between natural gas and natural gas liquids. And natural gas, if you can get the transport capacity on one of Tom's pipelines to one of several dozen market hubs in the United States, you're all done. And that's a easy thing to get your head around commercially. It's a little harder on the NGL side. You have to look further downstream and think about what it's going to do when it get -- where is it going to get fractionated? Where is the product going to go? Are you going to sell it -- or are you going to sell it up in the field? Are you going to sell it down in Mont Belvieu. The contractual or commercial commitments are just a little bit more difficult. I don't think anybody doubts that the production is there. And I think that what we're beginning to see in the market is that people are also realizing that the sort of incrementalist solutions that people have been using for the last couple of years are going to run out, and people can see the wall that you're talking about. But there's still been some gap between that realization and commercial commitments that are required for us to underwrite and make this investment. Now we have that one important development that's mentioned in the release, that we have a potential shipper who is interested in a substantial amount of capacity on the system, and is so interested that they're helping us with the development costs here through the end of August. So we've kind of been out there in the market commercially talking to our other shippers or potential shippers, as well as this shipper about we've got to make a decision go or no-go kind of by the end of the summer. And so we're hopeful that will help catalyze some of the plans into signatures and some of the realizations that other outlets are needed, again, into contractual commitments to this project. But again, there's no guarantee to that. We don't have it in the backlog. But we've had a positive development, and we continue to work it. Ron, anything else?

I think that that's very accurate, and still adjusting, talking to shippers and hope to have a successful open season at some point.

And just one last one, it's a quick one. As far as the Jones Act tankers that you guys are acquiring, there's 10 boats in all. It sounds like you have a pretty good understanding of the type of product that the condensate treating plants are going to be spitting out. Are those Jones Act tankers generally capable of moving that type of lightly refined condensate around in their shipment?

Yes, they are. And again, as we've said so many times, all of these boats are under long-term contracts. So it will really be up to our lessees to determine what they want to move in. But they would certainly be capable of doing that as obviously as well as all their crude oil and refined products can all be moved in that.

And our next question comes from Ted Durbin from Goldman Sachs.

I want to kick off here with the, I think -- what I guess we're calling the Northeast Energy Direct pipeline now into Boston. CapEx number looks like it went up a lot, $6 billion. I'm wondering if you can just give us a little more detail there. I think at the Analyst Day you're talking about more like kind of low 2s. Is the -- the [indiscernible] to the route change, what's the story there?

Well, I think -- and I'll let Tom Martin jump in here, but what's really changed is this is really now 2 projects. One is from the Marcellus to Wright, New York, and that's mostly a supply push project. And then the second project is from Wright across a little bit of New York and Massachusetts to Dracut. And again, the cost of that depends obviously on what the shipment actually is, and the $5 billion to $6 billion would be at the fully utilized percentages. Tom, you want to comment on that?

Yes, no, I think that's exactly right. It's a scalable project. What we're seeing on the customer side could potentially be up to 2.2 Bcf a day, we think, more likely. And the 800 to 1.2 Bcf a day range, the supply side of the -- I guess, the supply project that's included in that $6 billion number would be more than 800 to 1 Bcf level. Potentially bigger, but that's kind of how we're seeing it right now. And a good mix of customer interest on the market side, a healthy mix of LDC customers, also some Canadian customer interest, some LNG export customers. And ultimately, we believe there'll be power generation customers that [indiscernible] project as well.

Got it. And is it fair to say then that the market side of the project's probably the bigger push of the CapEx and the capacity and whatnot?

Yes, that's exactly right.

Yes, okay. And then maybe just elaborate a little bit more on the Trans Mountain decision here to push this back. I guess the fear, of course, is that this is a precursor to maybe some longer delays. Do you feel like you've sort of nailed everything down beyond the last 5 kilometers there? Or what else should we be looking for there? And then can you talk about if your customers themselves have any off-ramps if there are further delays from a contracting standpoint?

I think the issue that specifically is getting addressed here is that build that's through the really urban part of the route, and there had been fairly substantial public opposition to building on that route. And we were basically going to follow, at least in part, our existing right-of-way. We had multiple alternatives routes getting to Burnaby Mountain. But basically, once we came down the hill to the dock, we were going to go along the same existing routes. And so we have now kind of backed up and decided to look at some different alternatives, and I think the board wants to give that a full vetting. And I think there's a -- there's sort of a good side to this, in that I think this is a reasonable way to try to get this issue resolved and fully and finally resolved. And it is probably the most contentious piece of the route to us. So from that perspective, I think it's a sign that the NEB just wants to get to the right answer on the route, and we do, too. So yes, look, we're disappointed with the timing and all of that. But I think in general, if you look at what change or impact does it have on the long-term prospects of the project, getting the permit that we desire to get, I think there's a case to be made that it's actually slightly improved it. And so I think from that perspective, it's a -- well, if you can choose to take it as a -- or I'll choose to take it as a positive. In terms of the overall desire and demand for the project, that is still very strong. Customers want this project done, have been very supportive through this whole process. I'm not aware of any off-ramps certainly that would have any -- that this decision would have any bearing on. So I think it's a delay, but it's still all systems go.

Our next question comes from Scott Graham [ph] from Teilinger Capital [ph].

It's actually John Kiani [ph]. Given the favorable procedural changes around non-FTA approval for LNG exports, can you talk a little bit about the progress and efforts to get contracts for the Gulf LNG facility, please?

Sure. Tom, you want to do that?

Yes, absolutely. We've been talking to quite a few customers on the LNG project there at Pascagoula, and I think the discussions are gaining momentum. We have one MoU signed with a customer for 2 million tonnes a year. Again, not a whole lot of stock in that right now because it's really nonbinding at this point. But I think kind of where we are shaking out at this particular point is for -- from now through the end of the year or maybe early next year, we're really shaking through the binding agreement discussions with these potential shippers. And I think we'll know by the end of the year, maybe into early next year, as to whether this project will go or not. But I think as far as the regulatory change, I think probably overall neutral to favorable to us. I think the fact that we're -- a great balance sheet, a brownfield project, have good connectivity in the area, a favorable local and state regulatory environment which we're working on the project, and I think a very good relationship with FERC. I think that's where ultimately the project is going to be a go or no-go, obviously, as we get customer firm commitments. And ultimately, our opinion, I think, is the DOE process will follow what the FERC does.

Okay. So I don't want to put words in your mouth, but is it -- if I summarize what you were saying, if I understand you correctly, do you feel as though -- do you feel pretty confident that you should eventually be able to commercialize Gulf LNG? And obviously, you guys aren't going to build something like that without long-term stable contracts. Or is it just too early in the process to...

I think we're more favorable than we've been so far. But I think the next 3 to 6 months are going to be critical. There's been a lot of favorable discussions with customers. But I mean it really boils down to getting terms -- committed terms that are favorable to both parties and turning these into firm commitments. And we would like to see a mix of both tooling and FOB service ultimately crystallize here into 2 trains. And so we'll know more here over the next 3 to 6 months.

Okay. And then on a -- that's helpful. And then on a separate topic, if M&A has -- seems to have picked up in the MLP sector, and it's been a successful part of the company's strategy in the past. Is it tough right now for you all to be involved in that with KMP's current cost of capital where it is? Or do you think it's possible for the economics of the math to work? How are you thinking about that part of the strategy in general right now, please?

Well, I think certainly, cost of capital plays a role in any M&A activity, and we aim to be as competitive as possible in that and certainly are looking at all ways of lowering our cost of capital. But I agree with you that I think M&A is going to be active over the next months and next couple of years, and we certainly want to be a player in that and more to come.

Our next question comes from Brian Zarahn from Barclays.

On condensate, appreciate the color on the Eagle Ford opportunity. How do you view potential opportunities to transport Permian condensate?

I think it's -- oh, I'm sorry, Permian condensate. Yes, I'm sorry. We have -- we don't have anything really in the works on that right now. I mean, it's something that we can continue to look at, but it's not something that we've got like either in the backlog or really on the horizon right at the moment.

What about other crude infrastructure in the Permian? Any opportunities there?

From time to time, we do revisit the Freedom pipeline project, but that is not anything that is anywhere near imminent. It's just a function of if prices and pad well flow patterns on oil settle in to a position where a lot of the West Coast refiners want to use Permian crude as part of the refining slate, then maybe discussions emerge again there. But the uses for -- the other side of that story is the uses for the El Paso Natural Gas system have just continued to escalate, which makes the thinking about conversion a bit more challenging, not impossible, just it would be additional costs to make sure that we can continue to serve our gas customers at the level that we are serving them and expect to serve them going forward. Again, it's not something that's particular on the horizon.

Now the other thing is that we obviously, over in our CO2 segment, our Wink pipeline moves over 130,000 barrels a day of crude to a refiner in El Paso. And we are looking at ways of modifying that, in conjunction with our customer, to enable us to move crude and I suppose potentially condensate in the opposite direction there. And if we get the right contracts there, that will be an opportunity for us. And in fact, we just discussed that at some length at our most recent review with the CO2 group. So that's a potential that we're working on. It could come fairly soon. Now it's not a huge project, but would get us into that game somewhat.

And then shifting gears to the UMTP NGL pipe, did you say that you would expect a go, no-go decision by the end of the summer?

Yes, that's what we have set out is we need to see commitments by the end of this summer.

Okay. And then you mentioned potential anchor shipper. Would that contracted capacity be enough to move the project forward, or you would probably need some others to sign up?

That would be enough to move the project forward.

So stay tuned on that. Last one for me on the buy -- the warrant buyback. Are you expecting a new authorization?

The board did not authorize any incremental today. There's around $2 million remaining on the prior authorization.

Our next question comes from Jeffrey Campbell from the Tuohy Brothers Investment Research.

I'm calling for Craig Shere who couldn't be on the call today. A lot of my questions have been answered. But let me ask, do we have any updates on the NGL flooding potential?

I'll throw it over to Jim Wuerth, our CO2 segment head.

Yes, we're in the middle of testing that right now. The good and the bad of it, I guess the good part is, is that we're testing, trying to get a baseline off the shelf that we've found there. We're producing about 500 barrels a day out of the well, so it's kind of hard to get a baseline when you're producing that much. That makes us look at do we just go find additional shelves and open the purse up in those areas, put a plug in, open a purse there. And we've identified probably about 20 of those. So more to come whether we can drain that fast enough to even get a baseline to put the NGLs in. The plan is to try and put it in, in August, and we'll see what kind of a baseline we can get. But everything is positive right now. We haven't done a thing other than put a plug in and clean it out, put purse in up at the higher level and we're getting really good volumes out of there already.

Okay. And my other question is with regard to ROZ. Is -- will proving out the ROZ economics be a 2015 event? And if it works out as well as is hoped, what would be the main...

Yes, I think so -- yes, we're planning on the phase 1 that we've got going on right now. We should be injecting CO2 by November or December. This is on small acre spacing. It's on 10-acre spacing. The injectivity rates we've seen are upwards of 25%. So we should see real good production within just a few months after injection, and we would expect even peak production out of that 9 pattern [ph] area within 1 year, 1.5 years. So yes, we will know by '15 on a full go-forward plan.

Our next question comes from John Edwards from Crédit Suisse.

Just a couple quick questions -- actually I just have one quick question. At the Analyst Day, you talked about sort of the non-backlog backlog, if you will, and I'm just wondering where that stands now. And you've indicated the backlog's risen about $600 million this quarter. I'm just curious how the other products -- how that other -- the other total is looking.

Well, John, Martin, head of [indiscernible] today -- Martin, head of our Gas Pipelines group came into the full board meeting without any prompting on my or Steve's point and said that his non-backlog, as you call it, John, was now $18 billion, up from $15 billion the last time he met with the board. And when somebody comes in and volunteers something like that, you take it. So I think the short answer is we're seeing enormous opportunities in this natural gas province. We could go on and cite up all kinds of anecdotal evidence to it, but just a lot of potential now. The key is getting the horses in the Crown and getting the saddle on. Tom, anything you want to add to that?

No, I think that's exactly right. I think we continue to see more and more traction on opportunities than we've seen evidence of projects that weren't even on the potential backlog list that go all the way to the finish line and enter execution phase. So it's a very target-rich environment right now.

And I think overall in our Products Pipelines side, there's things like KMCC and I -- it depends on how you -- what you include in the basket or not. But correct me if I'm wrong, Ron, we basically have either spent or committed to spend, under long-term contracts, around $1 billion on that system now. We started out spending $220 million in the first go-round. We now have commitments that when we're fully built out, we'll be over 2/3 of the way there to fulfilling the 300,000 barrel a day capacity. Frankly, we have some additional capacity we could add on a relatively economic basis to that, which we will continue to look at. And when you add everything we're seeing down there to the -- this potential for additional condensate, that just looks like very good. So a lot of opportunities elsewhere in the company, too. But clearly, this natural gas -- the opportunity for natural gas long-line transportation is very strong right now.

Okay. So that -- and that's where you're seeing the majority of the increase in opportunities is natural gas?

That 15 to 18 -- the 15 billion going to 18 billion was just Tom Martin's Natural Gas Pipeline group.

Okay. And then are you seeing anything -- any significant increase on the terminal side?

Steve?

You mean increases in the non-backlog backlog as [indiscernible]...

Yes, kind of opportunity -- evaluation opportunity.

I think it's not a calculated number, John, so I don't have a calculated number for you there. But I think just generally, as I said before, the -- on the handling of liquids, crude and refined products and biofuels, and on crude-by-rail projects, the opportunities continue to increase. So I mean, I think it bodes well for that sector as well -- for that segment.

Our next question comes from Sonyam Sudaram [ph] from JH Securities [ph].

A couple of clarifications for me, the 2 Bcf per day of -- from transportation capacity contracts that you mentioned, in the process of negotiating, if you were to get those contracts finalized, would it necessitate additional project announcement from your side? Or they just kind of help you fill up the projects that have already been announced so far?

Yes, as we complete those projects, we will make announcements on them, as we complete the -- all the commercial arrangements for those projects, absolutely.

Okay. And then just one clarification on the previous comments with regard to the UMTP project. So the potential anchor ship that you have for that project that provides you enough capacity to go ahead with the project, that you are trying to layer on additional contracts so as to get a better scope of the project. Is that kind of a fair statement?

Yes, we're still pursuing third -- we're still pursuing other shippers as well beyond the sector [ph]. Or beyond the potential anchor shipper, we are pursuing other shippers.

Our next question comes from Rich Cheng from Deutsche Bank.

My question has already been answered actually.

Our next question comes from Pranab Kannadi [ph] from [indiscernible].

I think most of my questions have been answered; just one thing. On NGPL, you guys conducted an open season recently, and wanted to see if you had any updates on that?

Sure. Tom?

Yes, we -- I think we have some pretty good customer interest on our expansion, Gulf Coast expansion project down from the REX interconnect. We see potential project to be somewhere in the 0.5 Bcf to maybe 750,000 a day level, largely sponsored by producers, but also other potential export customers down the Gulf Coast. So we expect to move through the PA process here in the third quarter and see if we can get enough commitments.

Got it. What sort of rates do you get on those -- on that gas that you're flowing down there?

Yes, I mean, I don't -- we can't really get into specific rates. But I mean, I think we're -- by evidence of the interest in the project, I think we're very competitive with what other alternatives are in the market.

And I'm showing no further questions at this time.

Okay. Well, thank you, all, very much. Have a good evening, and we appreciate you spending this time with us. Goodbye.

Thank you for your participation. This concludes today's conference call. You may disconnect at this time.