Kinder Morgan, Inc. (KMI) Q1 2017 Earnings Report, Transcript and Summary

Thank you for standing by, and welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode until the question-and-answer session of today's conference. [Operator Instructions]. This call is being recorded. If you have any objections, you may disconnect at this time. And now, I'd like to hand the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Mr. Kinder, you may begin.

Okay. Thank you, Carrie, and welcome to our first quarter analyst call. As always, before we begin, I'd like to remind you that today’s earnings release and this call includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934, as well as certain non-GAAP financial measures. We encourage you to read our full disclosure on forward-looking statements, and use of non-GAAP financial measures set forth at the end of our earnings release, as well as review our latest filings with the SEC for a list of risk factors that may cause actual results to differ materially from those in such forward-looking statements. I will kick this off by making a few remarks, then I will turn it over to Steve Kean, our CEO, and Kim Dang, our CFO, to give the operational and financial update, and then we will take any questions that you have. I want to quickly make two points. First of all, this quarter's good results in terms of EBITDA and DCF which Steve and Kim will discuss in detail, demonstrates once more the strength of the asset portfolio at KMI. We are able to generate substantial amounts of cash flow even in a challenging environment in our business. Sometimes, good solid financial and operational success, which is made possible only by a lot of hard work by the whole team, gets overlooked by some investors. But I would argue that it's one of the critical elements to the long term economic health of any entity, and that includes Kinder Morgan. The second point I want to make is, that Steve will update you in detail on this quarter's developments on our Elba and Trans Mountain projects, but let me say, we continue to make good progress on them, and on our goal of strengthening our balance sheet and thereby allowing us to return substantial value to our shareholders, through some combination of dividend increases, share repurchases, additional attractive growth projects, our further debt reduction. Now, as I have said previously, we currently believe the best avenue for returning value, is by an increased and well covered dividend, and we expect to announce our revised dividend guidance for 2018 later this year. And with that, I will turn it over to Steve.

All right, thanks. I will give you a few updates on our performance and our key projects. First, we had a very good first quarter, with DCF per share at $0.54, and that's better than our beginning of the year guidance. Right now, we are seeing that and calling that as timing, so we are still forecasting to be on plan for the full year. But overall, strong performance for the quarter. On our Trans Mountain project, we have made progress on the project itself, and also on our effort to either joint venture the project with a partner or to include it in an IPO. On the project, we reached a really significant milestone. We increased our cost estimate, and that increase put us above the contractual cap. So cap was C$6.8 billion and our revised estimate is C$7.42 billion, and that, being above the cap, gave our shippers the right to turn capacity back to us. At the investor conference in January, we expressed our confidence that the market still had a very strong need for the project. And in fact, when all was said and done, all 708,000 barrels remained under long term contract. But now, have the increased tolls, and those increased tolls include our return on the additional capital that we will spend. We ended up with only 3% of the barrels turned back, and those were taken up in an open season over the course of a week or a week and a half. The contracts are 15, but primarily 20 year terms -- predominantly 20 year terms. Now this is a remarkable development, when you consider that these contracts were signed five years ago, and at $90 a barrel oil environment, and when the Canadian and the U.S. dollars were at parity. A lot has changed since then, including the circumstances of many of the producers in the oilsands, as well as the project costs itself. Our shippers and our commercial team worked very hard and fast to place the barrels with new customers, and existing customers who wanted more. As those who wanted less looked for places to assign our capacity. So message here is that even at the higher cost the demand for the project remained strong, and that's huge. We have essentially reconfirmed the value and need for the project, with a 2017 line-up of shipper needs, and based on 2017 market conditions. We also received during the quarter, our environmental approval from British Columbia, and we now have written agreements on the satisfaction of the B.C. five conditions, which were put forward for heavy oil pipelines crossing the province. So good regulatory development, and an extremely good commercial development as well. So that's on the project. On the JV, our IPO front, we have advanced on both tracks simultaneously, which is what we told you we would do in January. We believe this approach provides the best opportunity for us to secure acceptable financing terms for the project. Our key considerations here are value and control of project governance. Both of these processes are well advanced and we expect to update you by the end of the quarter on the resolution. Recall that for our plan, we assume the JV partner picking up 50% of the capital, but we did not include anything for our promote payment, which we would expect to get, and coming up with our target 5.4 debt-to-EBITDA metric. So in other words, we could do better on that target, to the extent we get to promote that we expect to get. I know everyone is interested in what the value is going to be, but we have avoided putting a marker out there for the sake of maintaining a strong negotiation position, but I will say this, this is an attractive return project, and is consistent with the 6.7X EBITDA multiple average that we have for the backlog as a whole. As we announced earlier, we completed our Elba JV transaction in the first quarter, and it was at the value that we put in the plan for 2017, and that included value in excess of our capital spend, recognizing the value that we created in originating the project. On the backlog, I will be brief, this quarter it stands at $11.7 billion, $300 million lower than last quarter. As usual, there are multiple moving parts, small project additions and removables and some cost changes, but the main development is that we placed into service our Kinder Morgan export terminal, a liquids terminal dock and cross channel line project for one of our refinery customers on the ship channel, the Houston ship channel. We expect to update the backlog for the Trans Mountain outcome next quarter, so the project cost will now be approximately $5.7 billion, and the ownership level is of course, expected to change. One more project update before moving to a few commercial highlights. On our Utopia pipeline project, our project team has done an excellent job of acquiring right of way, and finding routing alternatives where necessary in the wake of an adverse court decision last year on eminent domain in one of the Ohio circuit courts. We are pleased with our progress, and we -- again we began the tree felling process in the first quarter. This joint venture project is under a long term contract and is expected to be in service in January of next year. Now a few commercial market updates, starting with the gas segment. Experienced slightly increased transmission volumes year-over-year, but gathering volumes were down. I will start with gathering; we are generally seeing a leveling off of volumes in our key basins during the first quarter, but the comparison to first quarter last year reflects the declines that took place throughout 2016. Generally, our volumes are in line with what is observed in the basins in which we operate, although we are running a little bit ahead in our Bakken's gas assets, with one exception, and that's the Haynesville, where we are down on our KinderHawk asset, where the basin is flat to slightly higher. That's a function of the fact that our primary customer was not active in 2016. That's beginning to change, and we have added a new customer, that's actively developing its acreage, so we expect some improvement there. Recall, that our gas segment is 55% of our segment. Earnings before DD&A and gathering, processing is only 18% of that number. On the transmission volumes, we are up 1% year-over-year. The winter was weak, it was weak last year too, but we had a cold March in 2016. Power demand was down year-over-year. What I have read predicts that gas will still exceed coal's share of the power market again this year, but some gas to coal switching did occur on our assets in the first quarter. Also we saw higher renewable, including California hydropower contributing to the year-over-year decline. Overcoming this though, were exports to Mexico, which were up 16% year-over-year on our systems and now averaging 2.8 BCF a day -- averaging 2.8 BCF a day for the first quarter. Recall, that the vast majority of our margin here is secured by reservation fees, which are not affected by usage, but the volume information helps give a view on long term value for the capacity. I failed to mention also that LNG exports were up on our system year-over-year by half a BCF a day. We signed up an additional 400 a day of long term firm transportation commitments in the quarter. A 100 of that was existing but previously unsold capacity that brings our total in the last three and a quarter years to 8.4 BCF of new sign up of which 2.2 BCF is existing previously unsold capacity. We recently announced two developments related to the Permian. First, we announced a non-binding open season for a 1.7 BCF newbuild pipeline from the WAHA hub in West Texas to Agua Dulce in South Texas, our Gulf Coast express project. Last week, DCP announced its potential participation in that project as a partner and a shipper, and we are working with them over the next 90 days or so, to try to finalize that arrangement. DCP's assets in the Permian would provide good upstream connectivity and our Texas intrastate network would provide excellent downstream connectivity to Mexico, LNG at Corpus Christi and utility in industrial markets along the Texas Gulf Coast. Gas production is growing in the Permian and increasingly, East Texas is becoming a premium market. We think the project makes a good deal of sense, but we are in the early days and we have not put it in the backlog. The second development related to the Permian is, we have a binding open season on our EPNG system for capacity to the WAHA. The open season package includes 150 a day of existing capacity, but it also reflects our ability to expand the system, by as much as 900 days more, to meet incremental demand. The expansions would be relatively inexpensive, and would again, demonstrate the value of having existing infrastructure that we can build off of at attractive returns. This project with a fee takeaway capacity at WAHA, including the potential Gulf Coast express pipeline in our Midstream business, and we continue to work both of those opportunities over the coming weeks. The overall summary on gas is that we continue to expect long term benefit in the sector from increased LNG, Mexico exports, power and industrial demand, which should drive the demand from transportation storage infrastructure for the long term. Shifting to our products segment, refined products volumes are up 1% year-over-year, even though we experienced some weakness in Southeast U.S. markets. Crude and condensate transportation volumes are also up 1% year-over-year, notwithstanding declines year-over-year in the Bakken and Eagle Ford basins. KMCC in particular continues to show the benefit of its superior connectivity, both on the supply end and the Eagle Ford, as well as on the [indiscernible] in the Greater Houston area, and holding up very well in the face of declines experienced in the Eagle Ford as a whole on a year-over-year basis. In our terminals business, our liquids terminals utilization climbed to over 95%, as we continue to benefit from the strong positions we have built in several liquid hub locations. And this team has been gradually been migrating it's business increasingly to the liquids part of the business. We are now at 80% of our segment earnings before DD&A coming from the liquids part of the business, and increasingly, our development activity is in the hub positions that we have built in Houston, Edmonton, New York and Chicago over the years. We have kept our Jones Act vessels under charter on renewals that we have experienced, on [indiscernible] renewals. We had the discount to do that, but we expect to be slightly ahead of our plan on this business, and we currently have all of our vessels under charter. We continue to make good progress in our base line terminal expansion at our Edmonton hub, and as I mentioned, we put our Kinder Morgan export terminal project in service on the Houston ship channel. In the CO2 business, we came in slightly ahead of plan for the quarter, with pricing offsetting lower crude production volumes. Also of notice, that we achieved record CO2 volumes during the first quarter. Our demand was up, but so were our third parties'. They had a good strong demand for CO2 off of our system. So again, overall, a strong quarter, with strong financial performance, continued progress on our project execution and on our joint venture plans for our key projects. And with that, I will turn it over to Kim.

Good. Thanks Steve. Today, we are declaring a dividend of $0.125 per share, which is consistent with our budget. On the performance, let me hit the high points first, and then I will take you through the details. I will start with the GAAP numbers, and then move to DCF. DCF is the way we look at and think about our numbers and performance. Earnings per share attributable to common stockholders is up 50% in the quarter. Now, it would be nice to take credit for a 50% increase, but I don't think that gives us an accurate -- that's not an accurate view of the way we perceive our performance. Adjusted earnings per share, which we have added for you on the GAAP income statement and adjusted for certain items, is about $0.01 a share. DCF per share, which is the primary way we judge our performance, is down 1% or $18 million versus the first quarter of 2016, all of which is attributable to the sale of a 50% interest in SNG. So after the sale, DCF per share would be flat. For the first quarter, the DCF per share of $0.54 is slightly better than our budget, and for the full year we remain on target to generate $1.99 of DCF per share. On the balance sheet, we ended the quarter at 5.3 times debt-to-EBITDA consistent to where we ended 2016, but a significant improvement versus the 5.6 times in the first quarter of 2016. Now for the details, looking at the preliminary GAAP income statement, let me point out a couple of things to you there. You will see that revenues are up about 7% in the quarter, but cost of sales is up by more, resulting in about $121 million reduction in gross margin. Adjusting for certain items, gross margin would actually be down slightly more, would be down $146 million. The largest contributor to this decrease is the 50% sale of SNG. As a result of that sale, we no longer consolidate SNG's revenue and cost of sales, but report our 50% in net income further down the income statement as equity earnings. Now keep in mind also, that SNG did not have significant cost of sale. The impact of deconsolidating SNG was approximately $145 million reduction in gross margin for the quarter. Therefore, excluding the sale, gross margin would essentially be flat, which is consistent with how we would view our results. Net income available for the common shareholders is $401 million or $0.18 a share versus $276 million of income or $0.12 per share in the first quarter of 2016, resulting in $125 million or $0.06 per share increase or 45% and 50% respectively. Net income available to common shareholders before certain items for adjusted earnings was $371 million or $0.17 a share versus the adjusted number in 2016 of $402 million or $0.18 a share. Certain items in the first quarter of this year are income of $30 million, the largest of which is associated with proceeds we received from the sale of a bankruptcy claim on one of our natural gas pipeline. Certain items in the first quarter of 2016 were net expense of $132, driven primarily by project write-off and impairments. Now let's turn to the second page of financials, which shows our DCF for the quarter and the year and is reconciled to our GAAP numbers in the earnings release. As I said earlier, DCF is the primary financial measure, on which we judge our performance. We generated total DCF for the quarter of $1.215 billion versus $1.233 billion for the comparable period in 2016, down $18 million or 1%. There are lots of moving parts, but the simple explanation I gave you earlier is true, which is after the sales of 50% interest in SNG that occurred in the third quarter of 2016, we would be flat. Segment EBITDA before certain items is down $90 million, when you look up at the segment. That's primarily due to $113 million reduction in our natural gas segment. Of the $113 million reduction, $83 million is attributable to the SNG sale, and the natural gas decline is partially offset by $26 million increase in our terminal segment, which is associated with expansion projects coming online in the marine division and in the Gulf Coast. G&A and interest are a benefit of $44 million in the quarter versus the first quarter of 2016, both largely as a result of the SNG transaction. In our adjustments to convert net income to DCF, we add back JV DD&A and subtract sustaining CapEx to more closely reflect the cash we expect to receive from our JV; because SNG is a JV in the first quarter of 2017 versus the fully consolidated asset in the first quarter of 2016, there is approximately a $17 million benefit between the two periods in our adjustment from net income to DCF to reflect the economic impact of the SNG JV. So a $90 million of reduction in the segment. You add back the $17 million benefit to reflect the economic impact of the SNG transaction. The $44 million reduction between interest and G&A expense, and that gives you a net reduction of DCF of $29 million, which largely reconciles the change of $18 million in DCF. DCF per share was $0.54 versus $0.55 in the first quarter of the prior year or down a penny, almost all of which is associated with the DCF [indiscernible] I just walked you through. This $0.54 in DCF results in $935 million of excess distributable cash flow above our $0.125 dividend for the quarter. As I said earlier, for the quarter, we are ahead of budget, but for the full year, we expect to be on budget, largely as a result of some timing associated with sustaining CapEx, interest and cash taxes that occur in the second, third and fourth quarter. And with that, I will move to the balance sheet. On the balance sheet, as I said, we ended the quarter at 5.3 times net debt-to-EBITDA consistent with where we ended 2016. Our budget for 2017 is that we would expect to end 2017 at 5.4 times debt-to-EBITDA. After the first quarter performance, we are still on track to achieve that. Remember, as Steve said, the budget nor the current forecast, include any proceeds from a Trans Mountain promote, which we would expect to receive, and therefore, we would expect that our actual result will improve on the 5.4 times budget and forecast. Now reconciled before you, we ended the quarter at $37.8 billion of net debt, that's a $317 million decrease from the end of 2016. We generated DCF of $1.215 billion. We had expansion CapEx and contributions to equity investments of $773 million. We have asset sales and JV proceeds of $462 million, the largest of which was $391 million that we received from the Elba JV. We paid dividends of $280 million, and then we have working capital and other items, at a little bit over $300 million. So working capital is what we would expect in the first quarter. In the first quarter, we typically see working capital associated with interest payments, because we have a large portion of interest payments which occur in the first quarter, and so interest was a use of cash of $165 million in the quarter. We pay a significant amount or property tax in the first quarter, that was a use of cash of $77 million and then bonuses get paid in the first quarter and that was a use of cash about $75 million. So those were the three primary uses of cash in the $300 million of working capital. So with that, Steve, Rich?

Okay. Carrie, we will now open the line for questions.

Thank you. We will now begin the question-and-answer session. [Operator Instructions]. Our first question is from Kristina Kazarian of Deutsche Bank. Your line is now open.

Hi Kristina, how are you?

Good afternoon guys. How are you doing?

Good.

All right. So can you guys tell me a little more about how you are thinking about the new Permian project particularly the gas takeaway pipe? You know, how the DCP deal came about? And if you are also willing, maybe project cost and any updates on the open season?

Yeah. So I will start with the open season. It's closing shortly again, it's non-binding. The DCP discussion started early, even before our announcement of the deal that continued up until -- well that will be continuing on. But widened enough that we did a joint announcement of their participation. And again, the rationale there is, we get upstream connectivity with their processing assets and pipes in the Permian. And then we have downstream connectivity from all the market that we connect to, on what we think is the best intrastate system in Texas, connected to LNG, Mexico, et cetera. You know we are -- I think there is enthusiasm for it, but again it's non-binding. Producers I think are increasingly turning their attention to finding additional routes out of the Permian. Sometimes that takes some time to ripen. But certainly, there is interest in it, and will also cultivate interest on the demand side as well. And on the demand side, one of the things that we can do and have talked to people about is, we are a buyer of gas in Texas, because we have a lot of sales gas customers in the state of Texas, and so one of the things we could do, is buy the inlet to this piece of pipe, and that may serve as a bit of a bridge for some of the producer markets out there. So any parts of your question I have missed?

Project cost?

Cost. Yeah, we haven't come out with cost yet. But I mean, it is a 1.7 BCF newbuild project. So you are looking at north of $1 billion.

Perfect. And then my next question is, we have seen a good bump in Eagle Ford rig count recently; can you maybe talk about how this is trending, versus your original expectations and any chance for a positive revision related to this?

Yeah I mean -- it's going I think as we expect with the price recovery that we have seen. So I think, generally, what we are seeing in the basin, is a bottoming out of volume, both crude and gas, really this quarter, trending flat to slightly up, starting next quarter, and then probably finishing the year higher than it is today. And that's kind of where we set our plan coming into the year, and I think generally, that's how we are seeing it play out. Maybe slightly more activity than we were anticipating to this point. But I think how all that materializes, as far as actually bringing volume online versus just drilling, you know, that still needs to be played out over the year.

Yeah. I think we build as we started. We ended the year kind of where we started with some declines early and then picking up. I think, some developments that have been encouraging, is the rig count has been up a good bit. The other thing is, and these are related, is that acreage has been changing hands down there. So it's going from people who were not actively developing to people who are actively developing, and that's a positive indication for the basin too.

And Steve, last real quick one for me, as I know you said end of Q2 for timing and then, still waiting on FID and arranging project financing, but any other color you want to give, maybe for what we should be waiting for?

No. Those are the key things really. I mean, we are running both of these processes simultaneously. And the reason for doing that of course, is to get to a value point that reflects a fully negotiated deal or a fully marketed process and it's not fully marketed or fully negotiated until it's done. And so, we are not there yet and so we haven't [indiscernible] yet.

Got it. Nice job on the quarter guys. Thank you.

Thank you.

Thank you. Our next question is from Brandon Blossman of Tudor, Pickering, Holt and Company. Your line is now open.

Hi Brandon, how are you?

I am good. How are you Rich?

Good.

Let's see, probably just a couple follow-ups on Kristina's questions. One, on Gulf Coast express; Steve, you talked quickly about some projects on El Paso, I think, on the inlet side of that pipe. So I was wondering one, if you could describe in a little bit more detail, what those projects would look like? Are we talking about reversing compressor stations or adding compression or both? And then, more detail on the downstream side of that pipe; clearly, there is a way to get volumes up and down the Texas Gulf Coast, but any comments on -- is there anything that needs to be done to that intrastate system, or is there just plenty of unutilized capacity there?

Okay. Yeah so, the open season on El Paso has 150 a day of capacity that's existing, that comes in a bit over time, as the contract rolls off. But that's 150 without moving a muscle. We have got that capacity available and we can do it today. We can get another 900 of expansion, and the first, if you want to think of it this way, the first half of that roughly is relatively small CapEx. It's back pressure valves and things like that, that we probably do on a -- and a few pipe modifications. I mean, the interstation modifications, and we can probably do that under our blanket certificate, could do that relatively quickly, and that's a nice pickup. And again, underscores the value of having piped an inactive basin that we can make some adjustments to. The second half of that expansion, to get up to that 900 a day of incremental, would require compression. So that's a little bit pricier, but again, not much. There is not significant, little bit of pipeline built on maybe, but it's not a significant investment, but that would require a 7c. In terms of getting -- once you get to Texas, gas will be flowing south and east primarily, east to Corpus and south to Mexico. We are expanding that network with a crossover expansion that we have got in service, and we put in service in September of last year. So we have got -- and it is a network. So you have got options there, and it doesn't cost as much to expand that as needed for takeaway. But my guess is, and Tom you can opine, there may be some expansions -- if people who want to take significant volumes to Houston, we may need some expansion.

Yes. [They go 1.7] [ph] on the Houston.

That will be a problem. We will be happy to have that problem, but --

Short of that, I mean, there is a lot of -- really just changing the direction of the flow. I mean, we [indiscernible] today and a fair amount of that going to serve Mexico, some of that market today. So just letting that volume stay, and then actually we can pump some of that -- I mean, originally, these facilities were constructed to move gas from South Texas to Houston. So we have that capability today.

And the other takeaway -- there is other takeaway. When you get to WAHA, that's a significant hub and there is significant capacity coming online from WAHA to Mexico. So that's the other value adding component of the EPNG projects.

I think once again, we have said over the years, how valuable it is to have the huge footprint that we have, particularly on the natural gas side, and this is just one more indicator of how valuable that is. The project is not done yet. The open season has concluded. But the fact of having all that pipe in the ground is of enormous advantage, when you start talking about expansions and extensions of your system.

Great color. And then I will probably just follow-on on that topic. Competitive environment, we have three pipes essentially, very similar [indiscernible] announced in the same time period. So one, just what the competitive landscape looks like that, vis-à-vis producer interest? And then related, is there any chance of moving around the project, if there is demand and interest, say earlier 2019 or even late in 2018, is there something that can be done more quickly, in order to satisfy some residue gas takeaway issues?

Well, it's an intrastate project, so it's not a federal process. So if the demand is there, and it's there in a hurry, we can move more quickly. Yeah, it is a competitive environment, but I feel like, we have got the best downstream connectivity here, and we touch all the major markets, including all the big growing markets, and I think that's a real advantage. I mean, Agua Dulce -- getting to Agua Dulce didn't use to be a very big deal, you were just in South Texas. If you are in Agua Dulce and connected to our system, and you can go to Mexico or you can go to Corpus Christi or you can go to Houston, then you have really got something. Now, we need to -- we are working to sell for the upstream piece, and that's where DCP, I think, is a very nice fit. But there are others out there too, who we could coordinate with, to make sure that we can get the gas to WAHA and of course, EPNG expansion fits very nicely with that. So we think we have got a very good offering. I am sure that the other competitors would say the same thing, but I think that you look at the upstream and the downstream and we have got a very nice offering.

And one thing I would add Steve is, we are reducing interest from some of our customers in the intrastate network, actually wanting to reach back potentially all the way to WAHA. So again, I think that's something we offer in our project that our competitors don't.

Plus, we'd like to buy some of the gas.

All right. Perfect. Thank you very much guys.

Thank you, Brandon.

Our next question is from Shneur Gershuni of UBS. Your line is now open.

Hi Shneur. Good afternoon.

Good afternoon guys. Maybe just to start off following up to some of the questions with respect to the Permian Gulf Coast express; with respect to that project, with DCP potentially being on the project, how far away are you from getting to a commitment level that you would feel comfortable moving forward with the project, as it gets you 'fairly close?' And then secondly, when we think about project returns, I know that the board has sort of been enforcing a mid-teens type of return hurdle, is that something that you would need for this project to proceed to just given the contracted nature, it looks like with this -- you would be willing to accept the lower return hurdle to move forward with the project?

It's early to be talking about that. We have got a non-binding open season that's closing, and I think while the shipper interest, certainly producer interests, this is a maturing situation, as they are looking at takeaway capacity out of the Permian in their own production. And so I think, frankly, we are ways off there, in terms of maturing or ripening the project. I think we have got a good offering. I think DCP can bring volumes to themselves. We can bring purchase requirements to it. I think there are a lot of things that are compelling about it. But I think we are ways off. Now on returns, we have been using as a starting point, 15% unlevered after-tax returns and in projects where we are building off of our network, we have been pretty effective at getting those kinds of returns. And this has some of those characteristics, when you look at the downstream network and you look at upstream potentially on EPNG. On the other hand, where we have secure cash flows under long term contracts with good credits, we certainly talked with our business unit presidents about don't say no to those, if they are just -- because they are just a point or two off, bring them to us, let's have a look at them and see if on a risk adjusted basis, we are comfortable with them. So it's not a hard and fast, it's a totality of the circumstances kind of a valuation.

Okay. And just pivoting to TMX for a second here; you have the federal B.C. approvals in hand, but there is a lot of job owning in the upcoming B.C. elections about TMX's well too. I guess kind of two questions, one, what avenues would new government have in British Columbia to interfere with a project? And then again secondly, does the discussion with any JV partners or -- is it potentially suspended until after the election result is in, or the discussions continuing and ongoing, and it doesn't really influence the start?

I will go with the last question first. So no, there is no suspension of any process. We are going full speed ahead on both processes here. On the B.C. election, as you pointed out, we do have our federal and also, our provincial approval, and that includes the EA and then also the environmental approval. And it also includes, reaching agreement with British Columbia on benefits of their five conditions, which are primarily, benefits to BC, as well as risk reduction associated with marine and land response. There are also many other benefits of this project to British Columbia, that we think are recognized, and think and hope would be taking into account, for creating a lot of B.C. jobs here. There is economic development. There is benefits to the First Nations and the communities along the route that we have entered into a mutual benefits agreements with. And we have got a lot of detailed plans and protections that we put in place, and that the British Columbia and federal governments have put in place, to mitigate any perceived risk from the project. Now we are -- also, this is a federally sanctioned project. Now we are watching, we are certainly following developments very closely, and the B.C. -- the government in B.C. can certainly have an impact on the project, but it's probably a little premature for us to pine [ph] on those exact impacts at this point. We have a lot of momentum on both the federal and the provincial level from all the work that we have done and that those governments have done to address the concerns that have been raised, and to make sure that there are benefits that are shared with the broader public. So we think we have got good strong support behind us, both at the federal and the provincial level.

Okay. And one final question; last quarter, you talked about green shoots potentially emerging. Q1 seem to have some momentum in it as well too. But you sort of didn't change your yearend leverage target, and so forth. Are you seeing these green shoots develop? Could we see -- exceed your leverage targets by the end of the year or rather EBITDA targets? I was wondering if you can sort of comment on what you are seeing in terms of flows in green shoot?

Yeah, again, we are not changing our outlook and notwithstanding the strong first quarter performance, we are not changing our outlook for the full year. In terms of the debt-to-EBITDA metric changing, I think the main mover there is probably getting the financial arrangements in place for the Trans Mountain project. We are just a few weeks into the second quarter here, and I think there are some promising developments there. The rig count is one thing we have mentioned. Our Haynesville producer becoming more active on the gathering part of it. We are happy to be up 1% year-over-year on crude and condensate and refined products volumes. But it's just a little early for us to calling anything different on our EBITDA at this point.

Great. Thank you very much guys. Appreciate the color.

Thank you. Our next question is from Ted Durbin of Goldman Sachs. Your line is now open.

Afternoon Ted.

Hey Rich. How are you doing?

Good.

So I guess, just thinking about the JV and the promote on TMX and what you just announced on Elba a little while back, is there -- are those terms that you sort of came to on Elba? Breathe through for us, in terms of [indiscernible] about Trans Mountain. But from your perspective and in the way a potential partner might think about the investment in Trans Mountain?

Yeah. I don't think so. They are very different projects. As I said, the Trans Mountain return is consistent with the average return -- the overall return in our back -- the overall multiple of EBITDA in our backlog, which is about 6.7 times. So they are not -- they are really very -- they are very different projects, and so, I don't think you can analogize much, except to say, that we got compensated for the work that we did in originating and developing the project at Elba, and we expect -- as we did on Utopia, and we'd expect the same to be true on Trans Mountain.

The construction, when you look at how those projects are built, the construction is different. You know, you are going to take longer to construct Trans Mountain, than it takes to construct Elba. Elba is a self-contained site, with a signed EPC contract. In Trans Mountain we have multiple trucks over many miles. So the projects just have different returns and different risk profiles, and so I would expect that investors -- potential JV partners would take all those things into account. So I don't think you can take an Elba and apply it to Trans Mountain.

That's right. I would add, that of course what we have on both projects is very strong long term contracts with creditworthy entities, and I think, we just can't overemphasize on Trans Mountain, the fact that we have all these shippers who were signed up for 708,000 barrels a day, almost all of them for 20 years, and that is a very important factor, just [indiscernible] signed up on Elba, for that period.

Great. And then, I know this came up a lot at Analyst Day, but just a thought that -- you know, if you can't come to terms that you think are attractive for a JV partner and to promoting the things that you'd like to see. Let's say if the election goes south on you next month. I mean, you are still willing to walk away from the process or an IPO and are you willing to self-build the entire project, or would you then move to just the IPO process? Just where you are headed on all that?

Yeah. I think that's not a decision we are confronting yet. We fully expect that the two track process is going to produce successful results for us, so that's what we are basing our decision making on right now.

Okay. Fair enough. And then if I can do one more smaller one; the two section 5 rate cases that you got hit with currently in the year. Just how much of an annual revenue impact would you see from those, if -- well let's say, the pipelines will return, we will call it a reasonable ROE, as the FERC see that, what would be the revenue impact there?

Well first I will say, we feel very strongly that it was not appropriate to initiate those proceedings, because not all of the facts around those assets were fully taken into account in the section five process. We are also in discussions with our customers right now, and we did not expect that the -- anything other than -- at most, a de minimis impact on the margin for those assets.

Okay, perfect. I will leave it at that. Thank you.

Thank you. Our next question is from Jean Ann Salisbury of Bernstein. Your line is now open.

Good afternoon Jean Ann.

Hi, good afternoon. If you look at adding to your backlog. Should we think of the DCP JV as an indicator of broader interest than getting into the Permian in a bigger way? Or is it just opportunistic, since you already had existing gas assets? You had sort of continued to focus on building out existing basin [indiscernible]?

No, we would like to -- we have existing assets that serve the Permian. EPNG of course, we have the line on the Texas intrastate, so that line is fully utilized and constrained and difficult to expand. So we are already there, and we are absolutely looking to expand our presence there. I should have mentioned too, NGPL serves the Permian and brings the gas northbound to Chicago, and their opportunities on that system as well, to take advantage of the developments there.

Great. And then, I don't think that this is victory, but can you just give a sense of how much of your backlog is waiting for quorum to move forward?

I think, Tom correct me on this. We got orders on the projects that were time critical already, before the quorum disappeared early in the year. And so now, I think where we are is, we are not going to find the time critical issue, so long as they get quorum by midyear, thereabouts or even late 2017. So it's not constraining us right now, Jean Ann.

Okay. Great. That's all for me. Thanks.

Thank you. Our next question is from Danilo Juvane of BMO Capital Markets. Your line is now open.

Thanks. Most of my questions have been asked, but I had a couple of follow-up questions on TMX. Within the B.C. agreement that you signed earlier this month, I think you stipulated the June end decision timeline followed by a July 2nd announcement. Is that the absolute latest we will hear something, or can you announce something prior to that?

Yeah. That was really to set a date that was out there, kind of at the end of the timing thinking. So it was just a negotiated date, and it was put out there to be kind of at the end of the timing.

Okay. So we could hear something earlier than that?

Possible.

Okay. Secondly, within that agreement, is there any protection that you have from this potential change in political regime in the province?

Something in the agreement?

Right. Meaning, if there is a change, politically, [indiscernible]. Does the agreement change in any way, shape or form?

No, the agreement doesn't change. No, the agreement does not change.

Okay. Got you. Last but not least, just a clean-up [ph] question for me; what was the CO2 CapEx for the quarter?

$112 million.

Got it. Thank you. That's it for me.

Thank you. Next question is from John Edwards of Credit Suisse. Your line is now open.

Hey John. How are you doing?

Good Rich. Thanks. Just a couple of quick ones here; just on the real strong export volumes on Mexico this quarter, and what kind of growth rate is expected for the rest of the year, in terms of export volumes to Mexico?

Tom, do you have a feel for that?

That's a tough one. I mean, I think, it really just depends on the timing of additional capacity coming online. I am not sure I could give you a number. I mean, we should be trending up from here, but not out of [indiscernible]. There is a very steep climb. I think it will just continue to fully grow.

Okay. And then, just on the dividend. I know -- any more thoughts on, kind of step it up high with a slower growth or step it up not as much and grow it fast? Any kind of preliminary thoughts on dividend policy?

Oh, we are going to step it up high and grow it fast. Just kidding John. Look, we are going to have more say on that later in the year. But as we emphasize consistently, we are going to have the firepower, we believe, to significantly raise the dividend. And when we do, we are going to make sure that we -- that dividend is strongly covered. And one way of looking at it is, we'd like to be able, in an ordinary year, to be able to fund the equity portion of our expansion CapEx out of the cash flow, which would lead to good coverage of whatever dividend we are paying. But we haven't made any detailed decisions on it. And again, as we promised, we are going to do that later this year and get back to you with our outlook for 2018.

Okay, great. And then just one other question on Trans Mountain, you may not be able to comment on this, but in terms of the timing of the payment -- I know at Analyst Day, if I recall correctly, there was a discussion about having a good chunk of the amount be paid upfront versus -- over the construction process. Any other datapoints or color you can provide on that?

That's still consistent with our expectation?

Which one, Steve?

The upfront, giving a significant portion of the proceeds upfront.

Paid upfront. All right. That's helpful. Thank you. That's it for me.

Thank you, John.

Our next question is from Darren Horowitz of Raymond James. Your line is now open.

Good evening Darren.

Good afternoon Rich. Hope you and everybody is doing well. Steve, just a quick question for you on Gulf Coast Express; when we put all the pieces of the puzzle together, of the 1.7 that's being marketed, inclusive of the reside gas that DCP could commit, and we can all see what that is, and the options both upstream and downstream at the pipe that you talked about. Based on what you are marketing, how much total capacity do you think is necessary to commercialize the project? And then, as you mentioned, it makes a world of sense to be a buyer of that gas, especially if they can come back and capitalize on some regional [indiscernible], so how much capacity would you want to just leave open for that opportunity?

Yeah, very early to tell. Again, Darren, it would be -- if the demand is there at a high enough rate, you wouldn't have to fill the whole pipe. Tom, our purchase business is over 1 BCF a day, that's the whole portfolio, right?

Probably 2.5.

2.5 BCF a day and Eagle Ford is declining. So it would be a nice -- at an attractive price, a nice way to fill in for that, and the purchase part of portfolio, the Texas intrastate. Too early to tell what that mix will be.

Okay. Do you have a sense -- and this is my follow-up, and I will leave it here. Do you have a sense when you look at what's being marketed out of the basin, relative to residue gas, with high growth expectations? Either yours or from third parties. Do you have a sense of how much takeaway capacity is actually going to be necessary?

I mean, I think at least [indiscernible] in some analysis we'd see [ph] two additional pipes. So definitely enough to build this project.

Okay. Thank you.

Thank you. Next question is from Jeremy Tonet of JPMorgan. Your line is now open.

Hi Jeremy. How are you?

Good. Good afternoon. Thanks. Going back to TMX for a second here, I was just wondering if you could remind us, if you guys had kind of finalized, whether or not the JV and IPO process, whether that would include existing assets, or is it just the project itself? Could you just walk us through your way of thinking there?

Yeah. So it's very difficult to -- really, it's effectively impossible to break the expansion from the existing Trans Mountain system. It's effectively a twinning of that system, with some blind reactivations in it, and common facilities at the terminals and at the dock. So really the way we would be selling this, either at JV or an IPO is with the existing system as well. And in the IPO, potentially with a broader offering of our Canadian assets as well.

Got you. Thanks. And just one more, as far as Gulf Express there, and congratulations on that project, where the open season there. Was just curious as far as the interplay between kind of new projects and kind of returning a dividend to a higher level in the interplay, because I assume, 2018 CapEx steps down somewhat from 2017 and that kind of helps you in the process of being able to lift the dividend. And so it's a great thing to win new projects, but then, you know, you see the interplay there, as far as the leverage is concerned. So just wondering if you could walk us through your thoughts there?

I think it goes back to what Rich said earlier. We would look to have enough coverage over our dividend to be able to continue to fund the equity portion of a growth capital plan. So we are looking at -- we are going to be looking at all of that, as we come up with our guidance to the latter part of this year -- in the latter part of this year.

Got you. Great. Thank you.

Thank you. Next question is from Michael Blum of Wells Fargo. Your line is now open.

Michael, how are you?

Good, thanks. Just two quick follow-ups on Trans Mountain, on the JV IPO. Just what is the latest in terms of timing? In terms of when you think you will have an announcement? And then second question, would FID come sort of concurrent with that, or is that running on some sort of separate track? Thanks.

The timing is this quarter, and we haven't been more specific than that Michael. We are running both processes simultaneously, and again, the point there is, that we want to get ourselves to a fully negotiated JV side or fully marketed on the IPO side to kind of see what our value is. We would expect that the FID would come close in time, with the conclusion of those processes.

Got it. Thank you.

Thank you. We show no further questions at this time, speakers.

Okay. Thank you very much, Carrie. Thanks for all of you participating in our call and we will talk later.