Thank you for standing by and welcome to the Quarterly Earnings Conference Call. All lines have been placed in listen-only mode until the question-and-answer session. Today’s call is being recorded. [Operator Instructions] I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.

Thank you, Kim. Before we begin, as usual, I’d like to remind you that today’s earnings releases by KMI and KML and this call include forward-looking and financial outlook statements within the meaning of the Private Securities Exchange Litigation Reform Act of 1995, Securities and Exchange Act of 1934 and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measures set forth at the end of KMI’s and KML’s earnings releases, and to review our latest filings with the SEC and Canadian provincial and territorial securities commissions for a list of important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking and financial outlook statements. As I usually do before turning the call over to Steve Kean and the team, let me make a few comments regarding our long-term strategy and financial philosophy. I have talked repeatedly about our ability to generate large amounts of cash and to use that cash to benefit our shareholders in a number of ways, through reinvesting it in expansion projects to grow our future cash flow; paying dividends; delevering our balance sheet and buying back shares. We are utilizing our cash in all these ways, and this past quarter demonstrates that. In many respects, because a fine job done by Steve Kean and the whole KMI team, the third quarter was in my view, a pivotal one for the Company. Beyond good operational and financial performance, we have substantially improved our balance sheet extricated ourselves on favorable financial terms from the Trans Mountain expansion that was problematic in view unrelenting opposition from the government of British Columbia, and we have developed additional significant expansion projects which should allow us to continue to grow our cash flow in the future. Regarding our growth prospects, I believe we can develop good higher return infrastructure projects in the range of $2 billion to $3 billion per year. In short, we are demonstrating that we can generate strong and growing cash flow and employ that cash and benefit our shareholders. That is the essence of our long-term financial strategy at Kinder Morgan. And like many of you on this call, I’m puzzled and frustrated that our stock price does not reflect our progress and future outlook, but I do believe that in the long term, markets are rational and that the true value of our strong cash generating assets will be appropriately valued. And with that I will turn it over to Steve.

Okay. Thank you. As usual, we will be covering both KMI and KML on this afternoon’s call. I’m going to start with a high level update and outlook on KMI, then turn it over to our President, Kim Dang, to give you the update on segment performance. David Michels, KMI CFO will take you through the numbers. Then, I will give you a high level update on KML and will take you through the numbers and a couple of other topics there. Then, we will answer your questions on both companies. We had a pivotal quarter on KMI and KML, highlighted by the closing early in our schedule of our transaction to sell the Trans Mountain pipeline with government of Canada, which removed considerable uncertainty, while providing significant value to KML and KMI shareholders. With respect to KMI, we are having a very strong year. We are well above plan for the first three quarters and now project that we will exceed our financial targets for full-year 2018. And I think that includes our EBITDA, DCF, and our leverage metric targets. We expect to achieve this outperformance, notwithstanding the absence of earnings contribution from Trans Mountain, the delay in the completion of Elba, and the termination of a contract in our Gulf LNG joint venture, none of which was assumed when we put the budget together. What that tells you is that our underlying business is very strong. We also made our final investment decision along with our partner EagleClaw on the Permian Highway natural gas pipeline project in the third quarter. We have now sold out all of the available capacity to Bcf a day under long-term contracts, as we projected when we FID project. We have also already secured our pipe supply, which is a big mitigation of…

Thanks, Steve. Overall, our segments had a good third quarter, up 5%. Natural gas had an outstanding quarter, it was up 9%. And so, I think it’s worth spending a moment on the overall market. Current estimates show that the overall U.S. natural gas market is going to approach 90 Bcf for 2018, which is over 10% growth versus 2017. This is driving nice results on our large diameter pipes where transfer volumes are up 4 Bcf a day, that’s 14%. If you look at power demand on our system, it was up in the quarter up 1 Bcf or 16%; in the overall power market, natural gas now comprises approximately 38% of total generation, up from 36% in the third quarter of 2017. Exports to Mexico were up 375 million cubic feet a day on our pipes or 13% versus the third quarter of 2017 with total exports to Mexico on our system of just under 3.3 Bcf a day. Overall, the higher utilization of our systems, a lot of which came without the need to spend significant capital, resulted in nice bottom-line growth in the quarter and longer term will drive expansion opportunities as our pipes reach capacity. On the supply side, we’re also seeing nice volume growth. Our gas and crude gathering volumes were up 15% -- were up 20%, sorry, and 15%, respectively, driven by higher production in the Bakken and the Haynesville and the Eagle Fort. In the Haynesville, our gathering volumes doubled in the quarter versus 2017. On the project side in natural gas, we had a few noteworthy developments. Steve gave you the update on PHP. On Gulf Coast Express, we’ve secured approximately 80% of the right away. Construction is starting this month and we remain on target for October 2019 in service.…

All right. Thanks, Kim. Today, we’re declaring a dividend of $0.20 per share, which is consistent with our 2018 budget and with the plan that we laid out for investors in July 2017. Net annualized $0.80 per share is what we expect to declare for the full-year of 2018 and would represent a 60% increase, $0.50 per share that we declared in 2017. Once again, despite that very robust dividend increase, we expect to generate distributable cash flow of more than 2.5 times our dividend level. As you’ve already heard Kim, I had another great quarter. Our performance was above budget and above last year’s third quarter. As Steve mentioned, we expect to beat our budget on a full year basis, with all DCF, EBITDA and leverage. Now, I’ll walk through the GAAP financials, distributable cash flow and the balance sheet. Earnings, on the earnings page, revenues are up $236 million or 7% from the third quarter of 2017. Operating costs are down $453 million or 18%. However, that does include the gain recorded on the Trans Mountain sale. Excluding certain items, which Trans Mountain is the largest, operating cost would actually be up $162 million or 7%, which is consistent with the growth in revenues. Net income for the quarter is $693 million or $0.31 per share, which is an increase; $359 million, $0.16 per share versus the third quarter of 2017. Much of that increase is also attributable to the gain from the Trans Mountain sale. Looking at earnings on an adjusted basis, looking at adjusted earnings, take out certain items. The $693 million would be $469 million, which is $141 million, a 43% higher in adjusted earnings in the third quarter of 2017. Adjusted earnings per share is $0.21 or $0.06 higher than the prior period. Moving…

Okay. Thanks. So, we close the transaction on -- talking about KML, turning to KML now. We closed the Trans Mountain transaction. As we said at the time of close, the sales price amounts to about $11.40 Canadian per KML share. And on top of that, KML’s shareholders have a strong set of remaining midstream assets in an entity with little or no debt and with opportunity for investment expansion, as well as the potential for a strategic combination. We have a shareholder vote coming up on November 29th on a couple of matters that Dax will take you through, and expect the distribution of proceeds to occur in January, as David mentioned. And with that, I’ll turn it over to our CSO, Dax Sanders.

Thanks, Steve. Before I get into the results, I do want to update you on a couple of general items. First, as both Steve in the press release mentioned, we anticipate distributing the net proceeds associated with the sale on January 3, 2019, following shareholder vote on November 29th. More on the amount to be distributed in a second. Specifically, the shareholder vote is to approve two things. First, a reduction in stated capital, which is in Alberta corporate law concept. And with the reduction in stated capital, we will ensure that our distribution is copacetic with Alberta corporate law. The overall concept of the stated capital reduction is more fully described in the proxy. Second approval is to affect the three-for-one reverse split, post payment of special demand. As a reminder, the vote is subject to a two thirds majority of the outstanding shareholders in KMI, which owns approximately 70% has agreed about in favor. Moving to the business front. We now have all 12 Base Line tanks in service as we place 5 of the 6 remaining tanks in service during Q3 and the last tank in service just after the quarter-end. Overall, 10 of the 12 tanks were placed into service on-time or early. As of the end of Q3, we have spent approximately $342 million of our share with approximately $31 million remaining on the total spend of approximately $373 million. The $373 million compares with original estimate of $398 million. And as I mentioned last quarter, is a result of cost savings on the project. Now, going towards results. Today, the KML board declared a dividend for the third quarter of $0.1625 per restricted voting share of $0.65 annualized, which is consistent with previous guidance. Earnings per restricted voting share for the third quarter of…

Okay. We’re going to go to Q&A. We’re going to do something slightly different this time. We got some feedback that some of you would prefer that as a courtesy to others with questions, we limit the questions per person to one with one follow-up, and that’s what we’ll do. However, if you have more than one question and a follow-up, we invite you to get back in the queue, and we will come back around to you. Okay. With that, we’ll turn it over -- operator, please come back on and start the questions.

Thank you. [Operator Instructions] Thank you. And our first question comes from Jean Ann Salisbury with Bernstein.

Hi. How should we book in [ph] the potential downside for KMI of the 501-G outcomes? Do you have any internal productions that you can share of what EBITDA lose could be in the worst case?

Yes. It’s very hard to project, because the outcome is highly uncertain, but I’ll try to give you some parameters. We’ve said in the past that looking at the tax effect alone, it’s about $100 million across our interstate assets. Beyond that it’s very difficult to predict. And you understand -- you know what the mitigating factors are. We have rate moratorium in place on many of our systems. We have negotiated rates for many of our transactions in the interstate business. We have discounted rates in effect. Not all of our gas segment is interstate. Some of it is our intrastate a business in Texas, which we’re obviously growing. And not all of our regulated interstate assets earn their cost of service. Okay. So, if you put that all together and you roll off several years forward, and you’re really just talking about the max rate revenues on our interest business that are subject to some adjustment. If the max tariff rate comes down, which is what rate actions do, they would be subject to adjustment. And that amounts to about 30%, which by the way, to us anyway underscores the lack of foundation for what the commission is doing here. If you look at the action that they’re taking, they’re treating interstate natural gas pipelines as if they were regulated franchise monopoly utilities. That hasn’t been the case since the 1970s. Over the last 30 years, the commission has carefully crafted a competitive market through various administrations, one pro competitive rulemaking after another in order to create competition between pipelines. We operate in a competitive market, not in the franchise service territory. We expect to bring that and other rate-making arguments to bear as we go through the 501-G process. So, thanks for giving me a chance to stay on the result.

And one thing -- one follow-up there. The 30% that you mentioned is just of the interstate revenues, not of the whole gas segment, it is of the interstate.

Yes. That makes sense. And if we start to think about it, maybe as a multiple of the 100 million going away and a worst case or...

Yes. Again, very hard to project, because I think there are quite a few hands to play here as we work through this process and we work with our customers and we work with our regulator and we actively mitigate it. And I think we will be able to actively mitigate it, spread it over time. And the numbers I gave you are what gives us some confidence in that statement. We’ll be able to mitigate this and spread it over time.

And then, as a follow-up, you mentioned on the last call the potential of re-contracting at higher negotiated rates on EPNG, NGPL, and I believe your intrastate pipe. Could we get an update on that and would you be willing to share roughly what share of your volumes out of the Permian come up for negotiated rate re-contracting over the next couple years?

Yes. It’s not we have a quantification of that.

Yes. It’s hard to put a number on all of that. I mean, I think we’re talking about $25 million, somewhere in that range kind of year-over-year upside.

And our next question comes from Shneur Gershuni with UBS.

Maybe just to follow up on that 501 question. I was just wondering if you can clarify a couple of things. I mean, at this stage right now, can you confirm that that request is effectively informational at this point right now and it’s not actionable? And then, as part of the discussion on it, can you speculate on the purpose of the FERC making this request in the first place? Is it more to find the market price for the ROE, given that the last rate case was so long ago? Especially, given the context that there’s like another filing out there for a pipeline that’s asking for mid-teens ROE. I was just wondering if you can sort of opine on that.

On the first, we view it as an informational filing. And we view it as frankly, a bad informational filing. There are a number of things that it overlooks, including the negotiated rates and other things that I mentioned. It uses a very old litigated ROE, uses the cap structure that we don’t think is appropriate. And it kind of forces -- it forces information into a particular template that we don’t think is consistent with the way commission -- the commission has done rate making in the past. And so, in the course of all this, we’ll get an opportunity I’m sure to point that out. But, what I would submit that you all ought to be thinking about is, you’re going to get as many of you have written, these numbers are going to be uninformative. So, as these 501-Gs roll out, you need to take that into account as you’re looking at them, because they have flaws in our view, particularly in light of past commission policy and precedent. So, we think they’re informational and not very much information. On FERC’s purpose, I won’t speak for them. But, I think it was fairly clear from the process leading up to this that it was based on a desire to make sure that the benefits of the income that the Tax Cuts passed late last year found their way to customers. And in a competitive market, they do find their way, one way or another, to customers. But, we are not again, a franchise -- a protected franchise, regulated monopoly utility in the same way that some electric utilities or gas local distribution companies are. And so, I think that using a similar approach, if you will, with us given our circumstances isn’t appropriate. And we’ll continue to make that point to the commission.

Great. And as a follow-up question. I believe Rich mentioned in his prepared remarks an ability to invest $2 billion to $3 billion a year on an ongoing basis. Where do you envision those dollars being spent? Are we looking at some more large scale projects, like Permian Express Highway, or do you see it more of a series of $100 million to $200 million type projects? And if so, kind of where do you see the capital being spent?

I think, it’ll be primarily directed to natural gas. We put -- we grew the backlog quarter-to-quarter $200 million after putting several projects in service and that was largely due to a net addition of backlog of $600 million on the natural gas segment. And if you look at the fundamentals that Kim took you through, we would expect to see not only the increased utilization of the existing system but the opportunity to put more capital to work. And we’re looking at what those projects would be. It’s a little hard to say how many big ones will it be versus a collection of smaller multi-hundred million ones. But, we think we’ll have good opportunities there.

Thank you. Your next question comes from Jeremy Tonet with JPMorgan.

Hi. Good afternoon. Just want to turn to the business a little bit here. And it seems like you have some things kind of moving in your favor as far as growth is concerned, natural gas segment. You noted kind of the Bakken, Haynesville and Eagle Ford, and crude activity there. And just want to touch a bit more on those areas. It seems like the Bakken, there is quite wide basis differentials that cropped up recently there and wondering what that could mean for you guys as far as possibly expanding Double H or other infrastructures you might have. The Haynesville, seems like resurgence of activity there. BP might be looking to do more. Have you been in conversations with guys like that that are putting more capital to work? And then, the Eagle Ford as well seems like kind of coming off the trough nicely. Just wondering if you could comment on those three areas as far as where you see the growth opportunities.

Jeremy, that feels like a lot more than one question. So, I’m going to -- I think in all three areas that you touched on, I think there is going to be opportunities. I think, we are looking at some -- I don’t want to speak too much on the crude side, but there is -- there are some projects that we’re looking at to take additional volumes south to Cushing. Potentially on the crude side, there is clearly a need for additional residue solution out of the Bakken. So, I think that’s an area that we’re exploring as well. Clearly, there is going to be more expansion capital deployed in the Haynesville as we -- our existing capacity I think will be a point, certainly in pockets of the Haynesville, we’ll need to expand the system to take additional volumes there. And then, the Eagle Ford I think largely will be building our existing capacity, but there may be pockets of opportunity to expand there, particularly on the NGL side, which we’ll take a look at as well. So, I think clearly the value of our capacity, existing capacity is going up to the extent it’s not already sold in long-term contracts. As those deals come up for renewal, we should do better in those areas. So, I think prospects look good.

Got you. Great. Thanks for that. I was going to ask about Permian brownfield debottlenecking opportunities. But in the interest of not getting in trouble, I’ll hope back in the queue.

And your next question comes from Colton Bean with Tudor, Pickering, Holt & Company.

Good afternoon. As you evaluate next steps on KML, is there any consideration of potential asset inclusion from the KMI level, specifically maybe the U.S. portion of Cochin? And I guess, to touch on that, how does that fit into the Kinder network if KML were to exit the portfolio?

Yes. So, Cochin does not commercially or otherwise really divided the quarter. So, it makes sense for it to end one side or the other. And we’re evaluating how best to handle that. And some of that as a function of who the prospective or possible purchaser candidate might be. So, that’s still to be worked out, but you have put your finger on something that we have to resolve as part of it. It is an attractive asset. It runs full. It’s under contract, nearly full, it runs -- it’s under long-term contract. And it is providing a valuable service to our customers. So, I think it’s valuable, whichever side it gets up on.

Got it. That’s helpful. And I guess, just as a follow-up. So, you mentioned on UMTP, moving away from that project, I think you had filed for a abandonment on the TGP portion there in 2015. Given the abandonment filing, is there anything incremental, you would need to do on permitting, if you were to pursue a project there? And just any thoughts on kind of commercial appetite for more and more Northeast to Gulf Coast capacity given where spreads move to?

Yes. We’re not pursuing that project any further. And we reflected that in our accounting for the quarter et cetera. And part of the reason for that is, we haven’t gotten the customer sign up on UMTP. But just as importantly, we have a lot of interest in that pipe, which is currently in gas service, remaining in gas service and the potential for another long series of reversal projects that we’ve done on TGP in order to take the Marcellus and Utica gas south to where the market is now growing. And so, it’s a function of a lack of opportunity on the one hand, but thankfully the emergence of a very good opportunity on the other.

Okay. And so, no real, no real downtick in appetite for Southbound capacity even with basis being a bit tighter?

Yes. For this capacity, which is -- I don’t know if it’s the last one, but it’s among the few remaining opportunities to take existing Northbound capacity and turn it around. So, it’s not brand new Greenfield long haul pipe. So it’s one of the last, if not the last pipeline reversal projects. So, we think if we can -- that it is attractive in this market price. Clearly, it’s attractive compared to Greenfield costs and that it’s a nice pocket of capacity, it doesn’t require Bcf, 2 Bcf of commitment, it’s [indiscernible] range, I think, pretty actionable. So good trade.

Our next question comes from Spiro Dounis with Credit Suisse.

I just wanted to go back something you said earlier, Steve, just around your ability to meet and actually beat guidance here, as we get to the end of the year, despite some of the headwinds and unforeseen, all the issue that you had. Curious if you can just give a little more detail around what exactly is driving your ability to do it? And ultimately, what I’m getting at is, how much of that is really sustainable into 2019 versus maybe just commodity shrink based?

Yes. It’s really -- I mean, as Kim said, it’s the uptick that we’ve had in natural gas volumes and utilization. And one important point of note there is that the volumes on both the supply and the demand side are growing faster even in Texas. So, we’re seeing that 14% number that were up is 20% -- that’s 20% on sales and that’s 25% on transport in the Texas intrastate market, which is a good thing. That’s not a FERC regulated position for us. So, really, there is good tailwinds there, and they’re expected to continue. And we’ve had growth like we’ve never seen, at least in a very, very long time in the gas markets year-over-year, and we’re going to have another -- it looks like another good year of growth next year on the supply and the demand side. So, that looks like a good, beneficial trend for us, carrying on.

Again, I would just add that what we’re looking at Kinder Morgan is the largest network of pipes moving natural gas, about 40% of all the natural gas moved on our system. And when you have the kind of dynamics as Steve and Kim are referring to, it’s a huge tailwind for the whole Company. And that’s in essence the guts of what we’re trying to do at Kinder Morgan. And I think, in this year and particularly in this quarter, you’re seeing that tailwind really come to fruition, and it’s really driving tremendously good performance.

I appreciate that. And then, not sure if this is where Jeremy was going, but I’ll pick up that Permian question. In terms of the potential need for a third gas pipe out of there, I think Steve talked about it on the last call, maybe being kind of a tossup between the need to just expand the current pipe or do you add a third one. I think you said it was unclear last time. Just wondering, as you’ve gone through the rest of the Permian Highway process, is that more clear to you now? Do you feel like it’s clear one way or the other that third pipe is needed or do you see yourself getting maybe 2.7 Bcf a day on Permian?

Yes. So, the 2.7 -- I’ll start with that, 2.7 Bcf on the Permian Highway was if we had gone 48 inch. We went to 42 inch, because the supply chain for the pipe for 42 inch was much more secure, and as Kim said, we locked in our pipe there. And so, we took care of that risk. I think, our view and Tom you elaborate, but I think our view is, you’re going to continue to need additional types out of the Permian over time. We may be at a point where as people are waiting for the takeaway to come on and they’re doing more docks and they’re doing more diversion of rigs at other places, et cetera. They’re taking a brief break in the breakneck growth they were having. But we think there’s a third pipeline, maybe it’s two or three years out as opposed to right now, but we think there’ll be a third pipeline, if not more after that.

Thank you. And our next comes from Tristan Richardson with SunTrust.

Just curious on opportunities for new infrastructure downstream sort of in anticipation of the 4 Bcf a day of incremental supply from your two large projects as we look into 2020?

Yes. Well, a very good point. So, if you look at our Texas system today, it’s about a 5 Bcf a day system. And with these two projects that Tom’s team has put together here really in a very short period of time, we’re bringing another 4 Bcf to that system. Now, those projects come with certain downstream lease arrangements or pipeline capacity arrangements on our existing Texas intrastate system. But it will create, we believe, follow-on opportunities for us to do debottlenecking expansions on the Texas system to accommodate all of that additional gas, which comes with a lot of additional demand as LNG comes on and as we continue to see exports to Mexico rise, et cetera. So, the Texas market -- the whole Texas market and our position in it is in very good shape right now and has a very fine outlook.

And then, just a follow-up. Just curious sort of what areas in terms of the additions to backlog outside of PHP, sort of where you’re seeing growth project additions?

Okay. Well, we touched on one with the Tennessee pipeline reversal. We have additional projects serving LNG coming up that we are looking at on NGPL as well as our Kinder Morgan Louisiana pipeline. We’ll look at those also on the Texas Gulf Coast as time goes on. In the West, we’ll continue to find I think some debottlenecking opportunities, which may not necessarily have a full bunch of capital, but all that capacity is very valuable, certainly in the near term. And so, we can monetize that. And then, so the earlier question, the G&P part of our business, the Bakken is moving again and it is bottlenecked on our system. And so, we are investing capital to debottleneck that system and get our customers’ product to market. But, as Tom alluded to, in the Haynesville and in the Eagle Ford, we’ve got room on our existing systems to take additional volume with potentially small debottlenecking, not capital intensive expansion. So, we’ll get some volume, not for free, but for nearly free, as it grows in the Haynesville. And so, more in the Bakken than in the other two basins.

Our next question comes from Keith Stanley with Wolfe Research.

On the KML strategic review process, is there any reason you’d want to wait until the Trans Mountain special payment in early January or the shareholder vote in November before you make a decision on KML, or are those two items not connected at all?

We don’t necessarily have to wait on that for a decision, and we can work our process even starting now.

Okay. And one follow-up just on the backlog. You added $800 million in the quarter. How much of that is Permian Highway and what ownership interest are you assuming there?

Yes. So, we were conservative, I believe, on the ownership interest. So, we took it assuming a full exercise of the options that the large shippers on the system have to take equity. So, isn’t that, Tom, 600, something like that? So, it was most of the addition to the backlog and gas.

Thank you. Our next question comes from Tom Abrams with Morgan Stanley.

Thanks. Intrigued with this Bakken residual gas idea, began just coming out of the ground, has to go somewhere, but where? Where does it go? Try to get to the West Coast, we need LNG development there, or you get to the Gulf Coast and fight past all that Permian associated gas, just how you’re thinking about that?

Yes. I mean, I think we’re considering both options and I think more likely down to the Rockies area, but considering both.

And then, on the New York terminaling, you still have some headwinds there on Staten Island. But as you look across in the New Jersey, are you seeing anything over there that would suggest things are tightening up where the wind is kind of getting less in your face and maybe starting to bottom out and improve?

400% utilized in two New Jersey facilities at Carteret and at Perth Amboy. And actually, we saw an improvement on a quarter-to-quarter basis at Staten Island. We had 948,000 barrels last quarter and we’re up to 1.7 billion now. So, we’ve got a good short-term plan to keep our head above water over there. Spill tax is still a huge issue though. And so, we’re looking at strategic options for the facility kind of long-term, which could include looking at alternatives for the side.

Our next question comes from Michael Lapides with Goldman Sachs.

Real quick, and it’s a little bit of a two for one. How are you thinking about project returns on Elba Island now versus kind of original expectations? And for Gulf LNG to move forward outside of the FERC EIS process, how should we think about the sequence of steps necessary for that to become something that’s kind of a real project for you guys?

Okay. First on Elba. So, you have to go way back in time. But, when we originally sanctioned the project, we didn’t have a joint venture partner and we didn’t have certain other things in place. The return has actually improved since that time, and we’re still looking at a double-digit after-tax, unlevered return. Now, part of what brought about that change is we brought in a partner and our investment and it was promoted, our development of it was promoted. The other thing that’s protected us there, Michael, is we have in our contractual arrangements, there is three important parties here. There’s us as the project developer and manager et cetera. There is Shell, who is the provider of the units that are being provided to do the liquefaction. So, that’s not, if you will, on us. That’s something that Shell is providing. And then, we’ve entered into an EPC contract with our EPC contractor. So, the bottom line on all that is it insulates us from some of what you would normally think of as the cost of pain that’s associated with delay. So, our returns have surprisingly eroded, not that much notwithstanding a fairly significant and really not acceptable from our standpoint delay. The second question was on Gulf LNG? Okay.

Yes. How do you think about next steps for Gulf LNG outside of the obvious with the FERC EIS process?

Yes. So, as you have just said, I mean, we did get some information on Gulf LNG, the commission actually gave a timeframe on the EIS and on the expected order date for the 7c, which is in mid-July of next year. Gulf LNG is the last brownfield liquefaction opportunity. There’s been a lot of talk about the next wave of LNG. We need to get our current situation resolved with our re-gas shippers who are there and we need to explore our options in the market. And that includes not just marketing the facility; we’re potentially looking at a JV opportunity or other things.

Our next question comes from Robert Catellier with CIBC Capital Markets.

I was just hoping to make sure I understand the Trans Mountain recall rates on some of the tanks at KML if TMX is completed. I understand they have the right to recall tanks. And I think the original expectation was they could recall -- they were likely recall too. So, my question is, is that still the expectation? And what is the impact on EBITDA to KML as a going concern, if that in fact happens?

Yes. That’s still the expectation. The few tanks are still the expectation at the time that the project actually comes into play. And so, that’s obviously at the time project comes into play. They’ve also got the ability to give two years of additional notice -- two years of notice and recall additional tanks to the extent that they can’t meet their regulated requirements, existing regulated requirements, after they give notice. And so, we don’t anticipate to have that.

And the quantification, give us some color on the impact?

Yes. Go ahead.

It depends upon what we actually have in terms of third-party business out there. And so, it would depend on the specific situation.

Okay. Similar question then on the expiration contracts at the Edmonton rail terminal. I think, there’s an important contract that expires in 2020 with favorable renewal rates for the customer. What sort of color can you provide us on the impact that might have?

It switches to a cost plus contract. So, we will have a management fee in place at that time. So, we looked at this that it would be paid off in its initial term. And in April of 2020 that contract switches over to just a management contract.

So, that’s a material impact then?

Right now, it looks like it’s about $45 million.

Your next question comes from Robert Kwan with RBC Capital Markets.

Hi. Just wanted to confirm, with the numbers Dax gave, both the $4 billion on the dividend and then just over $300 million on the tax, just to make sure there is no other major inflows are outflows that pretty much means you’ve got -- you’re going to be no debt, no cash. Is that fair?

Yes. That’s about right. Pro forma for the cash taxes were just over 300 the dividend of about or -- that’s right.

Okay. And then just on the $50 million to $55 million in the fourth quarter, so that pretty much includes all of the second phase of baseline, yet that sweeps up the full quarter of the tank lease, at least the rail contract highlighted as part of this quarter. Does it also incorporate what you think the ongoing G&A run rate is, and are there any kind of future factors?

No. I think that’s a pretty clean sort of going forward run rate. The last baseline tank came in -- I said, the last one came in the fourth quarter, just after the beginning of the fourth quarter. So, it’s got a pretty, pretty good run rate going forward.

Our next comes from Shneur Gershuni with UBS.

Hello, again.

Hey. Following the rules, I had seven questions. I just wanted to clarify something that Kim has said earlier about total interstate revenues and 30% of that with respect to an adverse situation. Just wondering if you can sort of walk us through that again.

Yes. So, if you think of it this way, if FERC were to make ultimately a rate adjustment, what they would be adjusting down would be our max rate tariff. And so, by definition, it’s primarily the shippers who are paying max rates that if the revenue associated with that that could potentially be affected, could have some reduction in it, not elimination but some reduction in it. And negotiated rates, discounted rates would not be affected, they’re largely not affected. There is always a possibility that max rates come down enough that they get some of the discounts and they pull the rate, the max rate goes below the discounted rate. But, that’s very small. And so, it’s really the potential for an adjustment is a potential for an adjustment to that 30% subset of the interstate regulated revenues, which in turn are a subset of our natural gas segment. That’s what we’re trying to convey.

Okay. So just to clarify. So, basically what you’re saying is 30% of your revenues -- sorry, 30% is subjective max rate and that’s where you would then see an adjustment. So, if not a 30% hit to the revenues, it would be far less than that?

Correct. Very important. Yes. And it’s 30% of the regulated interstate revenues that we’re talking about. And yes, so, if you had -- and we’ve had rate settlements where we’ve taken a 5% reduction, for example, or a rate reduction that goes from 1%, then 3%, then 4, something like that. That’s what we’ve been able to achieve in other settlements. So, it’s not the whole 30%. Thank you for that clarification. Not the whole 30%.

Okay. Thank you. Much appreciated. And as a second follow-up question. You sort of gave in your opening remarks an update on if you ended up selling Canada where the proceeds would go and so forth. I was just wondering if you can talk about whether it’s a buyer or sellers market in Canada. And then, in terms of thoughts around asset sales, are there any other assets that you’re thinking about selling, for example, the Oklahoma assets where you had an impairment earlier this year. And is it fair to assume a similar playbook in terms of buybacks, if you were to get proceeds on some asset sales elsewhere?

Yes. First of all, what we were talking about with respect to use of proceeds would apply kind of wherever the proceeds came from. We’d make sure that we maintain that same leverage ratio, but then we would use them. If there were available projects, we’d use them for projects, but otherwise they would go to share buybacks. So, that’s our current thinking. On the KML assets, we think they’re great assets. They are -- it’s a fairly new development. We’ve built the largest merchant terminal position in Edmonton. John and his team did that over a 10 or 12-year period. And the Vancouver Wharves asset is a very good asset, the Cochin Pipeline is a very good asset. And we think that asset packages like this are rare anywhere, but they are rare to come to market and they are rare to come to market in Western Canada. And so, we do think that it tends to be a bit of a seller’s market for these assets.

The Oklahoma assets or any other assets?

Yes. So, Oklahoma, as we said, we have good G&P assets. We have some assets that might be more valuable in someone else’s hands and where we find those instances, and Oklahoma may be one of those, we could look to monetize them. But beyond that, not commenting on specific processes or specific assets. Everything here at a price, right, at the right price that -- the whole driver is what’s going to create the most shareholder value. That’s it. And so, if we find those opportunities on pieces of our asset base as we have in the past, some facilities, we’ll certainly evaluate those.

Thank you. Our next question comes from Jeremy Tonet with JPMorgan.

Hi. So, about that Permian natural gas debottlenecking. I think, in the past, you guys have talked about 2 Bcf a day gross capacity that could be added between kind of Texas intrastate, EPNG and NGPL. And just wanted to drill down if that was more -- you talked about the downstream connectivity that would be employed, I guess with -- based on these new pipes that you are building. 2 Bcf number, is that specific to that or just trying to drill down into really Waha takeaway? Is there any more that you guys can squeeze out on your assets there, given how Waha touched the buck recently and seems like egress is ever more challenged?

I mean, I think all of the low-hanging fruit has been harvested as far as low cost expansion. And certainly, we’re monetizing all the existing capacity that we have. There is anywhere from a Bcf to 2 Bcf of potential projects to be done at a much higher costs, which really are markets -- are supported by the market today. And if they were deployed, it would be kind of post PHP time horizon. But, we’re certainly looking at those smaller components of those projects that may still make economic sense. And really, the downstream side of it is really what Steve talked about earlier, and that is clearly a lot of the demand for this 4 Bcf is driven by Mexico exports, LNG exports, as well as growth along the Texas Gulf Coast in the petrochemical market. And we will look for opportunities to expand and extend our Texas intrastate network to support those growth activities.

So, just to be clear, the 1 to 2 Bs that you talk about, that’s really kind of like downstream of a PHP, and kind of that last mile getting to market, that’s not more getting out of Waha. Is that the right way to think about it?

That’s more Permian.

But, it is getting out of Waha?

Yes.

Okay. But that’s more…

Permian to Waha or places in North potentially up on the North mainline of El Paso or up into the Rockies via Trans Colorado. But again, I’ve -- those are, again, not for the bigger quantities anyway, probably not supported by market prices today. But, we’re certainly looking at smaller pieces of that, subsets of that as we get those done.

And the market may support them in the future as Permian continues to grow and the pipe -- even the pipe capacity that’s getting built, gets filled out.

And then, just a follow-up real quick, and we were talking about Double H before. If you can expand that, how long would that take to do? Is that kind of a pumping thing that could be done within a year or is this kind of longer term projects in nature?

On Double H?

Yes.

Yes. There is a small remaining expansion to be done, that’s pump station.

That’s right.

So, I think a couple of quarters, you could do that if you got commitment?

Yes. You could do that within 6 to 8 months.

Thank you. And I show no further questions.

Okay. Well, thank you all very much. Hope you’ll tune into the baseball game in a couple of hours. Good night.

Thank you. This concludes today’s conference. You may disconnect at this time.