Kinder Morgan Inc - Class P (KMI) — Q3 2018 Earnings Call Transcript

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 of the 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, which was problematic in view of 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 to 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 early closing of our transaction to sell the Trans Mountain pipeline with the 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 finalized the project. We have also already secured our pipe supply, which is a significant mitigation of risk in the current trade environment. We revised our debt to EBITDA target down from 5.0 to approximately 4.5 times with the KML announcement regarding use of proceeds and KMI’s announcement that we will apply KMI’s share of approximately $2 billion U.S. to debt reduction. We are achieving our leverage target. We’re having a very good year, strong financial performance, tremendous progress in the balance sheet, and we’re finding good opportunities to deploy capital on attractive projects in our great network of assets. This has been a pivotal quarter for KMI. Looking ahead, here are our priorities: Complete the distribution of the Trans Mountain proceeds and continue our discussions with positive indications that we now have from all three rating agencies into positive ratings actions; continue executing on our project backlog, particularly the completion of Elba and the advancement of our Gulf Coast Express and PHP; continue maximizing the benefit of our unparalleled gas network and seek to add attractive return projects to our backlog as we did this quarter; continue returning value to our shareholders with a growing and well-covered dividend. And with respect to questions on KML and possible transactions there, as we’ve said previously, following the sale of Trans Mountain, KML is evaluating all options to maximize value to its shareholders. The original purpose of KML was to hold a strong set of midstream assets and to use the cash flows from those assets and the balance sheet to provide a self-funding mechanism for the Trans Mountain expansion. Clearly that purpose no longer exists. The good news for KML shareholders is that there are good options available, which include continuing to operate a strong set of remaining midstream assets as a standalone enterprise. Simply put, we like the assets and we don’t have to sell them. But, among the other potential outcomes is a strategic combination with another company, including possibly KMI. We will be exploring and evaluating all of the available options with the KML board in the coming months. Because strategic transactions are difficult to predict, we will likely not have further updates on this until we have something more definitive to say. But as we’ve consistently demonstrated, our focus will be on maximizing KML shareholder value. The possibility, though not a certainty, that KML may enter into a strategic transaction, including an outright sale, means that KMI can have another use of proceeds decision.

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 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 on our system of just under 3.3 Bcf a day. Overall, the higher utilization of our systems, without the need to spend significant capital, resulted in nice bottom-line growth in the quarter and will drive expansion opportunities as our pipes reach capacity. On the supply side, we’re seeing nice volume growth. Our gas and crude gathering volumes increased by 15% and 20%, respectively, driven by higher production in the Bakken, Haynesville, and Eagle Ford. 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-of-way. Construction is starting this month, and we remain on target for October 2019 in service. Our Elba Liquefaction Project, we now anticipate that it will be in service in the first quarter of 2019. Although the delay is impacting our DCF versus budget, the natural gas segment is still expected to exceed its budget for the year. We do not expect the delay to have a material impact on our construction costs, given the way our construction and commercial contracts are structured. Our CO2 segment benefited from higher crude and NGL volumes and also higher NGL and CO2 prices. Net crude oil production was up 2% versus the second quarter of 2017. SACROC volumes were up 4% versus last year and they’re 6% above our plan year-to-date, as we continue to find ways to extend the life of this deal. Currently, we’re evaluating transition zone opportunities as well as off-unit opportunities that are adjacent to SACROC. Tall Cotton volumes were up versus last year but below our budget. Our net realized crude price is relatively flat for the quarter, despite a higher WTI price. The WTI hedges we have in place, as well as the increase in the Mid-Cush differential, offset the increase in WTI. For the balance of this year and for 2019, we’ve substantially hedged the Mid-Cush differential. Our terminals business benefited from liquids expansions in Houston Ship Channel, Edmonton, and the new Jones Act tankers that came on in 2017, which we’re now getting a full-year benefit from in 2018. These benefits were largely offset by weakness in the Northeast, particularly at our Staten Island facility, which is now subject to New York spill tax, making facilities in New Jersey more economic options for our customers, and a number of other factors which include non-core asset divestitures, contract expirations at our Edmonton rail facility, and higher fuel and labor costs in our steel business. Bulk tonnage in the quarter was actually up 5%, primarily driven by coal and pet coke. Although you don’t see much benefit from this result given the way our contracts are structured, the GAAP revenue recognition rules, and to a lesser extent, some pricing changes. Liquids utilization was down 2%, primarily due tanks out of service for API inspections and the Staten Island facility I mentioned. In the products segment, we benefited from increased contributions from Cochin and Double H, but that was offset by lower contributions from Pacific due to higher operating costs. Crude and condensate volumes were up 13%, due to increased volumes on our pipelines in the Bakken which drove higher contributions from Double H, and in the Eagle Ford, the impact at those volumes though is largely offset by lower pricing. And with that, I’ll turn it over to David Michels, our CFO, to go through the numbers.

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 from the $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 financial targets which encompass our DCF, EBITDA, and leverage for a full year. 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 costs 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 up from $359 million or $0.16 per share versus the third quarter of 2017. Much of that increase is attributed to the gain from the Trans Mountain sale. Looking at adjusted earnings, taking out certain items, the $693 million would be $469 million, which is $141 million, or 43% higher in adjusted earnings than in the third quarter of 2017. Adjusted earnings per share is $0.21, or $0.06 higher than the prior period. Moving on to distributable cash flow (DCF), DCF per share is $0.49, which is $0.02 up from the third quarter of 2017, a 4% increase. That is yet another strong quarterly performance for 2018 and reflects growth in our natural gas segment. Natural gas was up $81 million or 9% benefiting from various factors. You’ve already heard about the Bakken, Eagle Ford, and Haynesville shale volumes being up, benefitting KinderHawk, South Texas and Hiland gathering and processing assets. Our EPNG and NGPL pipelines had greater contributions driven by Permian supply growth. Our Tennessee Gas Pipeline was up due to expansion projects placed in service, and our CIG pipeline experienced strong growth due to greater DJ basin production. Partially offsetting those items was lower contributions from our Gulf LNG due to a contract termination. The CO2 segment was up $16 million from last year, driven by NGL prices and greater volumes. The Kinder Morgan Canada segment was down $18 million or 36% due to the sales of Trans Mountain and a loss of one month of contracts during the quarter. G&A is lower by $16 million due to greater capitalized overhead as well as lower G&A from the Trans Mountain sale. Interest expense is $10 million higher, driven by higher interest rates, which offsets the benefit from a lower debt balance as well as some interest income earned on the sale proceeds. Sustaining capital was $36 million higher versus 2017. We have budgeted sustaining CapEx in 2018, to be higher than in 2017 and actually expect it to be favorable to our budget. So, to summarize, the segments were up $59 million; G&A costs were down $16 million; interest was up $8 to $10 million; cash taxes were up $5 million; other items driven by increased pension contributions led to a reduction to DCF of $9 million and sustaining CapEx was higher by $38 million, which explains the main variances in the $38 million period-over-period change in DCF. 2018 remains on track to be a very good year for Kinder Morgan. We expect to exceed our budgeted financial targets for the year, driven by natural gas and CO2 segments, lower G&A, cash taxes, and sustaining capital expenditures, partially offset by reduced contributions from Kinder Morgan Canada as a result of the Trans Mountain sale, as well as lower contributions from our terminal segment due to lower lease capacity in the Northeast and lower than expected Gulf throughput. One more note here. While natural gas is nicely ahead of plan year-to-date, as expected to finish the year ahead of plan, the segment does expect to be impacted relative to budget in the fourth quarter due to delays in service of our Elba and LNG project, as Steve Kean mentioned. Moving on to the balance sheet, we ended the quarter at 4.6 times net debt to EBITDA. Just to repeat that, we ended the quarter at 4.6 times net debt to EBITDA. This is an important milestone and a nice improvement from 4.9 times last quarter and 5.1 times at year-end 2017. We expect this to remain at 4.6 times for this year. The Trans Mountain sale was the largest driver of that improvement. The proceeds from that sale will reside at KML. We expect the distribution of those proceeds to occur on January 3, 2019. We expect to use our share to pay down debt. In the meantime, KMI consolidates all of those cash proceeds including the amount that the public KML shareholders will receive. Therefore, as you can see on the balance sheet page, we subtract out from KMI’s net debt approximately $919 million of cash that will go to the KML public shareholders. We believe that’s a more accurate reflection of KMI’s leverage. Including that adjustment, net debt ended the quarter at $34.5 billion, a decrease of $2.1 billion from year-end and from last quarter. To reconcile the $2.1 billion for the quarter, we generated $1.093 billion of distributable cash flow. We had growth capital expenditures and contributions to JVs of $715 million. We paid dividends of $444 million. We received the Trans Mountain sale proceeds of $3.391 billion, which we took out the KML public shareholders portion of those proceeds which is $919 million. We had a working capital use of $337 million, primarily as a result of EPNG refund payments. This reconciles to our $2.069 million reduction in net debt for the quarter. For the full-year or year-to-date reconciliation, we generated $3.457 billion of distributable cash flow. We had growth CapEx and contributions to JVs of $1.981 billion. We paid dividends of $1.163 billion. We repurchased $250 million of shares. We received the Trans Mountain sale proceeds of $3.391 billion, excluding the KML public shareholders portion of that at $919 million. We had a working capital use of $455 million year-to-date, which includes the EPNG refunds, as well as interest payments, and reconciles to the $2.08 billion reduction in net debt year-to-date. With that, I will turn it back to Steve.

Okay. Thanks. So, we closed the transaction on KML. 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 opportunities 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. We 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 and the press release mentioned, we anticipate distributing the net proceeds associated with the sale on January 3, 2019, following the 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 an Alberta corporate law concept. With the reduction in stated capital, we will ensure that our distribution is compliant with Alberta corporate law. The overall concept of the stated capital reduction is more fully described in the proxy. The second approval is to affect the three-for-one reverse split, post payment of special demands. As a reminder, the vote is subject to a two-thirds majority of the outstanding shareholders in KMI, which owns approximately 70%, who have agreed about in favor. Moving to the business front, we now have all 12 Base Line tanks in service as we placed 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 an original estimate of $398 million, and as I mentioned last quarter, this is a result of cost savings on the project. Now, moving 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 2018 are $0.05 from continuing operations and $0.378 from discontinued operations, with both derived from approximately $1.35 billion of net income, which is up approximately $1.3 billion versus the same quarter in 2017. Obviously, the big driver of this was the large gain on the sale of the Trans Mountain pipeline. Let me focus for a minute on what’s driving the $12.4 million increase in income from continuing operations. Stronger revenue associated with the Base Line tank and terminal coming online, and interest income associated with the proceeds from the Trans Mountain sale are the big drivers. Adjusted earnings, which excludes certain items were approximately $44 million compared to approximately $42 million from the same quarter in 2017. Of course, the big certain item in the quarter was the gain on the sale of Trans Mountain. Total DCF for the quarter which is not adjusted for discontinued operations is $80.6 million, which is up $3.4 million for the comparable period in 2017 and within $1 million of our budget. This provides coverage of approximately $7 million, reflecting the DCF payout ratio of approximately 71%. Looking at the components of the DCF variance, segment EBITDA before certain items is up $8.4 million compared to Q3 2017, with the pipeline segment up approximately $8.2 million and the terminal segment essentially flat. The pipeline segment was lower primarily due to the Trans Mountain assets going away, approximately $15 million net, offset by the non-recurring underlying FX loss from some intercompany notes that were in place in 2017 and lower O&M in Cochin compared to 2017 as we had some non-routine integrity management activities in 2017 that were completed. The terminal segment was flat with the Base Line tank terminal project coming into service and higher contract rates and renewals at the North 40 Terminal and Edmonton South Terminals offset by the expiration of a contract on the Imperial JV. Same unrealized FX dynamic I mentioned on the pipeline segment and the lease payment on the Edmonton South facility to the government. G&A is favorable by $2.5 million, due primarily to the removal of the Trans Mountain G&A line item. Interest is favorable by approximately $11 million due to the interest on the Trans Mountain proceeds and lower interest expense. The cash tax line items are essentially flat. Preferred dividends were up $5.2 million, given Q3 2018 had both tranches outstanding for the fourth quarter. Sustaining capital was favorable approximately $3.8 million compared to 2017, with the exclusion of Trans Mountain being the main driver but augmented by timing of spending in the terminals segment. Looking forward, as we mentioned in the release, we expect to generate $50 million to $55 million of adjusted EBITDA for the fourth quarter and almost a full quarter of Base Line tanks in service during the fourth quarter. Consistent with past practice, as we prepare our 2019 budget for KML, we will communicate that which will provide more clarity on the earnings power of the residual assets going forward. With that, I’ll move to the balance sheet comparing year-end 2017 to 9/30. My comments will focus only on the line items related to the retained assets and not the assets or liabilities held for sale. Cash increased approximately $4.239 billion to $4.35 billion, with many moving pieces in the change associated with Trans Mountain stemming from the CapEx spend on behalf of government, the government credit facility, and other purchase price adjustments such that I’m not going to take you through that on this call. But if you want more detail, feel free to give us a call. Generally, the increase is the $4.426 billion of net proceeds received, plus DCF generated, less expansion CapEx, less distributions paid net of growth and less the payoff of the debt we have when we receive the sale proceeds. More importantly, let’s look forward to where that cash is going. The dividend we will pay in January will be approximately $11.40 per KML share, will be approximately $4 billion. We will then pay capital gains tax associated with the transaction of just over $300 million in Q1 2019. Other current assets increased approximately $19.5 million, primarily due to an increase in several items in accounts receivable with the largest component coming from a billing to Imperial related to the Imperial JV. Net PP&E decreased by $3 million as a result of depreciation in excess of net assets placed in service. Deferred charges and other assets decreased by approximately $64 million, which is a result of a write-off of the unamortized debt issuance costs associated with the TM facility that we canceled. On the right-hand side of the balance sheet, other current liabilities increased $321 million, primarily due to the taxes payable on the Trans Mountain sale. Other long-term liabilities decreased by $283 million, primarily as a result of a deferred tax liability release due to the gain on the sale of Trans Mountain. Also of note, we ended the quarter without any outstanding debt. With that I’ll turn it back to Steve.

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 to the operator, please come back on and start the questions.

Hi. How should we book in the potential downside for KMI of the 501-G outcomes? Do you have any internal projections that you can share on what EBITDA loss 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 difficult to predict. 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.

The 30% you mentioned applies only to the interstate revenues, not to the entire gas segment; it specifically pertains to 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. 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.

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 of years?

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.

Maybe just to follow up on that 501 question. I was just wondering if you can clarify a couple of things. At this stage right now, can you confirm that the request is effectively informational at this point right now and it’s not actionable? And then, can you speculate on the purpose of the FERC making this request in the first place?

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 factors that I mentioned. It uses a very old litigated ROE, uses the capital structure that we don’t think is appropriate. What I would submit that you ought to be thinking about is, these numbers are going to be uninformative. And so, as these 501-Gs roll out, you need to take that into account, as they have flaws particularly in light of past commission policy and precedent. So, we think they’re informational and not very helpful. On FERC’s purpose, I won’t speak for them. But, I think it was clear from the process leading up to this that it was based on a desire to ensure that the benefits of the income from the Tax Cuts found their way to customers.

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 as series of $100 million to $200 million type projects? And if so, where do you see the capital being spent?

I think it will mainly focus on natural gas. We increased our backlog by $200 million from one quarter to the next after launching several projects, which was mostly due to a net gain in the natural gas sector. The fundamentals indicate that we expect not only higher utilization of the existing system but also the chance to invest more capital. It's difficult to determine if we'll see more significant projects or a series of smaller ones in the multi-hundred million range. We are confident that there will be strong opportunities in that area.

Hi. Good afternoon. Just want to turn to the business a little bit here. We’ve seen some things moving in your favor as far as growth is concerned, in the natural gas segment. You noted Bakken, Haynesville and Eagle Ford activity there. Just want to touch a bit more on those areas. It seems like there are quite wide basis differentials cropping up recently in Bakken. What does this mean for you guys as far as possibly expanding Double H or other infrastructure? Have you been in conversations with players like BP that are putting more capital to work in Haynesville? And in Eagle Ford, it seems like coming off the trough nicely. Just wondering if you could comment on those three areas as far as where you see growth opportunities.

In all three areas that you touched on, I think there will be opportunities. I think we are looking at some projects that we’re exploring to take additional volumes south to Cushing. There are some projects that we’re looking at to take additional residue solution out of the Bakken. There will be increases in expansion capital deployed in Haynesville as our existing capacity will need expansion to take additional volumes there. For Eagle Ford, we may find expansion opportunities to build on existing capacity, but particularly on the NGL side. The value of our capacity is increasing as those deals come up for renewal; we should do better in those areas. Prospects look good.

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

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? How does that fit into the Kinder network if KML were to exit the portfolio?

Yes. Cochin does not commercially or otherwise really divide the quarter. So, it makes sense for it to end on one side or the other, and we’re evaluating how best to handle that. We think it’s an attractive asset. It runs full and it’s under contract, nearly full, and is providing a valuable service to our customers. 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. Given the abandonment filing, is there anything incremental you would need to do on permitting, if you were to pursue a project there? Any thoughts on commercial appetite for Northeast to Gulf Coast capacity given where spreads move to?

We’re not pursuing that project any further, and we reflected that in our accounting for the quarter, et cetera. We haven’t gotten the customer sign-up on UMTP. We’ve seen significant interest in that pipe remaining in gas service and the potential for a long series of reversal projects to take Marcellus and Utica gas south to where the market is now growing. It’s not an opportunity, but thankfully the emergence of a good opportunity on the other side.

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

For this capacity, which is among the few remaining opportunities to take existing Northbound capacity and turn it around. It’s not brand new Greenfield long-haul pipe. So, it’s one of the last, if not the last pipeline reversal projects. It’s attractive compared to Greenfield costs and it doesn’t require large commitments.

I just wanted to go back to something you said earlier, Steve, just around your ability to meet and actually beat guidance as we get to the end of the year despite unforeseen issues. Curious if you can just give a little more detail around what exactly is driving your ability to do it? How much of that is really sustainable into 2019 versus maybe just commodity shrink based?

It’s really the uptick that we’ve had in natural gas volumes and utilization. The volumes on both the supply and the demand side are growing. We’re seeing a growth of 14% on sales and that’s 20% on transport in the Texas intrastate market, which is a good thing. That’s not a FERC regulated position for us. There are good tailwinds here, and they’re expected to continue. We’ve had growth in gas markets year-over-year, and we expect another good year of growth next year. So, that looks like a very positive trend for us carrying on.

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. When you have the kind of dynamics as Steve and Kim are referring to, it’s a huge tailwind for the whole Company. What we’re seeing in this quarter demonstrates that tailwind really come to fruition, driving tremendously good performance.

I appreciate that. In terms of the potential need for a third gas pipe out of Permian, I think Steve talked about it on the last call, maybe being a toss-up between the need to just expand the current pipe or do you add a third one. Is that more clear now? Do you feel like a third pipe is needed or do you see yourself getting maybe 2.7 Bcf a day on Permian?

The 2.7 Bcf on the Permian Highway was if we had gone 48 inch. We went to 42 inch because that was much more secure in terms of the supply chain. I think our view is you’re going to continue to need additional pipes out of the Permian over time. We have to see how things develop in the near future, but we believe a third pipeline may be two or three years out.

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

Yes. The Texas system today, it’s about a 5 Bcf a day system, and we’re bringing in another 4 Bcf to that system. Those projects come with certain downstream lease capacity arrangements on our existing Texas intrastate system. This will create follow-on opportunities for us to do debottlenecking expansions on the Texas system to accommodate all that additional gas, which comes with a lot of additional demand as LNG and exports to Mexico rise, and so forth. The Texas market, our position in it, is in very good shape right now.

And then, just a follow-up. Just curious about what areas you’re seeing growth project additions outside of PHP?

We touched on one with the Tennessee pipeline reversal. We’re looking at additional projects serving LNG on NGPL as well as our Kinder Morgan Louisiana pipeline. We’ll look at those on the Texas Gulf Coast as time goes on. In the West, we’ll continue to find some debottlenecking opportunities. The Bakken is moving again and it is bottlenecked on our system, and we are investing capital to debottleneck that system to get our customers’ product to market. 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.

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 making a decision on KML, or are those two items not connected?

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

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

Yes. We were conservative, I believe, on the ownership interest. We took it assuming a full exercise of the options that the large shippers on the system have to take equity. So, it was most of the addition to the backlog and gas.

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

We’re considering both options, but more likely down to the Rockies area.

On New York terminaling, you still have some headwinds on Staten Island. Are you seeing anything in New Jersey that would suggest things are tightening up where the wind is maybe starting to bottom out and improve?

We are 400% utilized in two New Jersey facilities at Carteret and Perth Amboy. We’ve seen 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. We’ve got a good short-term plan to keep our head above water over there. The spill tax is still a huge issue and we’re looking at strategic options for the facility long-term, including potential alternatives for the site.

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 a real project?

When we originally sanctioned the Elba project, we didn’t have a joint venture partner in place. The return has actually improved since that time, and we’re looking at a double-digit after-tax, unlevered return now. Our contractual arrangements insulate us from some of the cost pain associated with delays. On Gulf LNG, the commission gave a timeframe on the EIS and on the expected order date for the 7c, which is in mid-July next year. Gulf LNG remains the last brownfield liquefaction opportunity. We need to get our current situation resolved and explore our options, which includes not just marketing the facility but potentially looking at a JV opportunity.

I was hoping to clarify the Trans Mountain recall rates on KML if TMX is completed. Is it still expected that they could recall tanks? If so, what is the impact on EBITDA to KML as a going concern if that happens?

Yes. That’s still the expectation. They’ve got the ability to give two years of notice and recall additional tanks, should they not meet their regulated requirements. We don’t anticipate that affecting KML significantly.

And the quantification, what’s the impact?

It depends on what we actually have in terms of third-party business out there.

On the expiration of contracts at the Edmonton rail terminal, what color can you provide us on the impact that might have?

It switches to a cost-plus contract. We will have a management fee in place at that time, which looks like it’ll be about $45 million.

Hi. Just wanted to confirm the numbers Dax gave, both the $4 billion on the dividend and just over $300 million on the tax, and that means you’ll have no debt, no cash. Is that fair?

Yes. That’s about right, pro forma for the cash taxes where just over $300 million and the dividend of about $4 billion.

On the $50 million to $55 million in the fourth quarter, does it incorporate what you think the ongoing G&A run rate is, and are there any future factors?

That’s a clean run rate going forward. The last baseline tank came in just after the beginning of the fourth quarter, so it’ll have a good run rate.

Hello, again.

Just wanted to clarify something Kim mentioned earlier about total interstate revenues and 30% of that with respect to an adverse situation. Can you kind of walk us through that again?

Yes. If FERC makes a rate adjustment, they would adjust our max rate tariff. The potential for an adjustment is a subset of our natural gas segment which includes up to 30% of the regulated interstate revenues. 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.

Okay. So basically, what you’re saying is that 30% of your revenues are subjective max rate and that’s where you would then see an adjustment; it would be less than that?

Correct. Very important. Not the whole 30%.

Thank you. And as a second follow-up question, can you talk about whether it’s a buyer or sellers market in Canada? Are there any other assets you’re thinking about selling, for example, the Oklahoma assets where you had an impairment earlier this year?

We think those assets are great. They are rare to come to market, especially in Western Canada, so it tends to be a bit of a seller’s market for these assets. In Oklahoma, we have good G&P assets. Some of our assets might be more valuable in someone else’s hands, and if we find those instances we could look to monetize them. But beyond that, we’re not commenting on specific processes or assets.

Hi. So, about that Permian natural gas debottlenecking. You guys have talked about 2 Bcf a day gross capacity that could be added between kind of Texas intrastate, EPNG and NGPL. So, if you can expand that, how long would that take? Is it kind of a pumping thing that could be done within a year?

Yes, with Double H there is a small remaining expansion to be done, which is a pump station. So, I think within 6 to 8 months you could see that if you got commitment.

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