金德摩根 (KMI) 2018 Q3 法說會逐字稿

Thank you for standing by, and welcome to the quarterly earnings conference call. (Operator Instructions) Today's call is being recorded. If anyone has any objections, you may disconnect at this time.

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 of the fine job done by Steve, Kim 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 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.

Now like many of you on this call, I am 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'll turn it over to Steve.

Okay, thank you. As usual, we'll 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, and then turn it over to our president, Kim Dang, to give you the update on segment performance. David Michels, KMI's CFO, will take you through the numbers. Then I'll give you a high level update on KML, and we'll take you through the numbers and a couple of other topics there. Then we'll 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 to 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 3 quarters and now project that we will exceed our financial targets for full year 2018. That includes our EBITDA, DCF and our leverage metric targets. We expect to achieve this out performance 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, 2 Bcf a day, under long-term contracts as we projected when we FID the project. We have also already secured our pipe supply, which is a big mitigation of risk in the current trade environment. We revised our debt-to-EBITDA target down from 5.0 to approximately 4.5x, with the KML announcement regarding the use of proceeds and KMI's announcement that we will apply KMI's share, approximately USD 2 billion, 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. We're finding good opportunities to deploy capital in attractive projects on 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 on turning the positive indications that we now have from all 3 rating agencies into positive ratings actions; continue executing on our project backlog, particularly the completion of Elba and the advancement of Gulf Coast Express and PHP; continue maximizing the benefit of our unparalleled gas network; seek to add attractive return projects to our backlog as we did this quarter with the addition of PHP; continue returning value to our shareholders with a growing and well-covered dividend.

And with respect to questions on KML and possible transaction 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 that strong set of remaining midstream assets as a stand-alone 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 forecast, 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 could have another use of proceeds decision.

A few points on that. We have consistently said at KMI that we would evaluate the use of available cash to fund attractive projects, return value to KMI shareholders in the form of buybacks or increasing dividend. We have also updated our leverage target to around 4.5x, and we're there now with the Trans Mountain transaction. With our leverage target achieved, we would expect to use the additional available cash to fund the equity portion of attractive growth projects that we may add in the backlog or for share repurchases. And I'll say again that we continue to believe that our current share price is an attractive value for share repurchases.

And with that, I'll turn it over to Kim.

Okay. Thanks, Steve. Overall, our segment 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 Bcfs for 2018, which is over 10% growth versus 2017. This is driving nice results on our large diameter pipes, where transport volumes are up 4 Bcf a day. That's 14%.

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% -- or were up 20%, sorry, and 15%, respectively, driven by higher production in the Bakken and the Haynesville and the Eagle Ford. In the Haynesville, our gathering volumes doubled in the quarter versus 2017.

On the project side of 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 delays impacting our DCF versus budget, the natural gas segment is still expected to exceed its budget for the year, and we do not expect the delays to have a material impact on our construction cost 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 field. 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 they're below our budget.

Our net realized crude price was 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, we benefited from liquids expansions in Houston Ship Channel, in Edmonton and the new Jones Act tankers that came on in 2017 that we got a full -- that we're getting a full year benefit in 2018. These benefits were largely offset by weakness in the Northeast, particularly at our Staten Island facility that is now subject to a New York spill tax, making facilities in New Jersey a more economic option for our customers. And a number of other factors, which include non-core asset divestitures, contract explorations at our Edmonton Rail facility and higher fuel and labor cost 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 in those results 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 to tanks out of service for API inspection and the Staten Island facility I mentioned a moment ago.

In the product segment, we benefited from increased contributions from Cochin and Double H, but that was offset by somewhat lower contribution from Pacific due to higher operating costs.

Crude and condensate volumes were up 13%, and that was due to increased volumes on our pipelines in the Bakken, which drove higher contributions from Double H and in the Eagle Ford. The impact of 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. That annualized $0.80 per share is what we expect to declare for the full year 2018 and would represent a 60% increase [from the] $0.50 per share, that was declared in 2017. Once again, despite that very robust dividend increase, we expect to generate distributable cash flow of more than 2.5x our dividend level.

As you have already heard, KMI had a great -- 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 for 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 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 an increase of $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 at 43% higher than adjusted earnings in the third quarter of 2017. Adjusting -- adjusted earnings per share is $0.21 or $0.06 higher than the prior period.

Moving on to distributable cash flow. DCF per share is $0.49, which is $0.02 up from the third quarter of 2017, a 4% increase. That is yet another very nice quarterly performance for 2018 and was

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by strong growth in our natural gas segment. Natural gas is up $81 million or 9%. Net debt that it -- that segment benefited from -- on multiple fronts. As you already heard, Haynesville, Eagle Ford and Bakken shale volumes were up, and that benefited KinderHawk, South Texas and Hiland gathering and processing assets. Our EPNG and NGPL pipelines had greater contributions driven from -- by Permian supply growth. Our Tennessee Gas Pipeline was up due to expansion projects which were placed in service. And our CIG pipeline experienced strong growth due to greater DJ Basin production. Partially offsetting those items was lower contribution from our Gulf LNG due to a contract termination.

CO2 segment was up $16 million from last year driven by NGL prices and greater volume. And Kinder Morgan Canada segment was down $18 million or 36% due to the sale of Trans Mountain and the loss of 1 month of contribution during the quarter. DD&A is lower by $16 million and that's 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 more than offset the benefit from a lower debt balance as well as some interest in income that we earned on the Trans Mountain sale proceeds. Spending capital was $36 million higher versus 2017. We had budgeted sustaining CapEx in 2018 to be higher than 2017 and are actually -- actually expect to end the year favorable to our budget.

So to summarize, the segments were up $89 million, G&A costs were down $16 million, interest expense was up $10 million, cash taxes were up $5 million, other items driven by an increased pension contribution were a reduction to DCF of $9 million and sustaining CapEx was higher by $38 million. That adds up to $43 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 low leased capacity in the Northeast and lower than expected Gulf liquids throughput.

One more note here. While natural gas is nicely ahead of plan year-to-date, is expected to finish the year ahead of plan, the segment does expect to be impacted relative to budget in the fourth quarter by the delayed in-service of our Elba Island LNG project as Steve and Kim mentioned.

Moving on to the balance sheet. We expect -- we ended the quarter at 4.6x net debt-to-EBITDA. Just to repeat that, we expect -- we ended the quarter at 4.6x net debt-to-EBITDA. So a very important milestone, a nice improvement from the 4.9x last quarter and 5.1x at year-end 2017. The current forecast also has us ending the year at 4.6x. The Trans Mountain sale was the largest driver of that improvement. The proceeds of that sale still reside at KML. We expect that the distribution of those proceeds will occur in January 2019. January 3 of 2019. And 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 subtracted out from KMI's net debt approximately $919 million of cash that will go to the KML public shareholders. And 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. So to reconcile that $2.1 billion for the quarter, we generated $1,093,000,000 of distributable cash flow. We had growth capital and contributions to JVs of $715 million. We paid dividends of $444 million. We received the Trans Mountain sale proceeds of $3.391 billion. We took out the KML public shareholder's portion of those proceeds of $919 million, and we had a working capital use of $337 million, primarily as a result of EPNG refund payments. And that reconciles to our $2.069 million reduction in net debt for the quarter. For the full year, or for the year-to-date, reconcile -- reconciliations, 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 and we received the Trans Mountain sale proceeds of $3.391 billion. We excluded the KML public shareholders' portion of that of $919 million, and we had a working capital use of $455 million year-to-date. That also includes the EPNG refunds as well as interest payments. And that reconciles to the $2080 million, $2.08 billion reduction in net debt year-to-date.

With that, I'll turn it back to Steve.

Okay, thanks. So we closed the transaction on -- I'm talking about KML, turning to KML now. We closed the Trans Mountain transaction. As we said at the time of the close, the sales price amounts to about CDN 11.40 per KML share, and top of that, KML 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 29 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 CFO, 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 shareholder vote on November 29. More on the amounts to be distributed in a second.

Specifically, the shareholder vote is to approve 2 things: First, a reduction in stated capital, which is an 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. The second approval is to effect the 3-for-1 reverse split, post payment of the special dividend. As a reminder, the vote is subject to a 2/3 majority of the outstanding shareholders, and KMI, which owns approximately 70%, has agreed to vote 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 had spent approximately $342 million of our share, with approximately $31 million remaining of the total spend of approximately $373 million. The $373 million compares to an original estimate of $398 million and, as I mentioned last quarter, is a result of cost savings on the project.

Now moving towards the results. Today, the KML board declared a board -- declared a dividend for the third quarter of $0.1625 for restricted voting share or $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 $3.78 from discontinued ops, and both are 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 there was a large gain on the sale of the Trans Mountain Pipeline. So 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 Trans Mountain sale are the big drivers. Adjusted earnings, which exclude 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. Double DCF for quarter, which is not adjusted for discontinued ops, is $80.6 million, which is up $3.4 million for the comparable period in 2017 and within $1 million of our budget. That provides coverage of approximately $7 million which reflects a DCF payout ratio of approximately 71%.

Looking at the components of the DCF variance, segment EBITDA before certain items is off $8.4 million compared to Q3 2017, with the pipeline segment off approximately $8.2 million and the terminal segment essentially flat. The pipeline segment was lower primarily due to the Trans Mountain assets going away, and that was approximately $15 million negative. It was offset by the non-recurrence of an unrealized FX loss from some intercompany notes that were [on place] in 2017 and lower O&M in Cochin compared to 2017 as we had some nonroutine integrity management activities in 2017 that were completed.

The Terminal segment was essentially flat with the Base Line Tank and Terminal Project coming into service and higher contract rates and renewals at the North 40 terminal and Edmonton South terminals offset by the exploration 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 [term line]. Interest is favorable by approximately $11 million due to the interest on the Trans Mountain proceeds and lower interest expense. The cash tax line item is essentially flat. Preferred dividends are up $5.2 million given Q3 2018 had both tranches outstanding for the full quarter. Sustaining capital is favorable approximately $3.8 million compared to 2017 with the exclusion of Trans Mountain being the main driver, but augmented by timing on spending in the Terminal 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 the Base Line Tanks in service during the fourth quarter. And also, and consistent with past practice as we prepare our 2019 budget for KML, we will communicate that which will provide more color 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 and 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, and there are a lot of moving pieces in the change associated with the Trans Mountain -- with Trans Mountain that stem from the CapEx spend on behalf of the 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 the [DRIP], and less the payoff of the debt we have when we received the sale proceeds.

More importantly, let's look forward where that cash is going. The dividend we will pay in January -- and that's the approximate $11.40 per KML share, will be approximately $4 billion and then we'll pay a 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 and accounts receivable, with the largest component of that 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 released as a result of the gain on the Trans -- gain on the sale of Trans Mountain. Also of note, we ended the quarter without any outstanding debt.

And 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've gotten 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? And with that, we'll turn it over.

Operator, if you could come back on and start the questions.

(Operator Instructions) Our first question comes from Jean Ann Salisbury with Bernstein.

How should we bookend the potential downside for KMI of the 501-G outcomes? Do you have any internal projections that you can share of 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 very difficult to predict. And you understand, you know what the mitigating factors are. We have rate moratoria 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 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 interstate 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 rule making after another, in order to create competition between pipelines. We operate in a competitive market, not in a franchise service territory. We expect to bring that and other ratemaking arguments to bear as we go through the 501-G process. So thanks for giving me a chance to stand on a soapbox.

And one thing, one follow up there, the 30% that he mentioned is just of the interstate revenues.

Yes.

Not of the whole gas segment. This is of the interstate.

Yes, that makes sense. Would it be fair to think about it maybe as a multiple of the $100 million going away in a worst case, or...

Yes, very -- 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.

Okay, that makes sense. And then as follow up, you had mentioned in the last call the potential of recontracting at higher negotiated rates on EPNG, NGPL and I believe your intrastate pipe. Can 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 contracting over the next couple of years?

Yes. It's [not be able to] quantification on that.

Yes, I mean, 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.

Our next question comes from Shneur Gershuni from UBS.

Maybe just a 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 a mid-teens ROEs. I'm just wondering if you could sort of opine on that.

Okay. 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 a 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 will 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, and 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 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 is inappropriate, and we'll continue to make that point to the commission.

Great. 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 the 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 will 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 to the backlog of $600 million in 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 dollars ones, but we think we'll have good opportunities there.

Our next question come from Jeremy Tonet with JPMorgan.

I just wanted 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 in the Natural Gas segment. You noted, kind of the Bakken, Haynesville, the Eagle Ford and crude activity there, and I just want to touch a bit more on those areas. It seems like the Bakken is quite wide, based on the differentials that cropped up recently there. I'm wondering what that could mean for you guys as far as possibly expanding Double H or other infrastructure you might have. The Haynesville, it seems like resurgence of activity there. BP might be looking to do more. Have you been in conversations with guys like that, that are -- to put 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 3 areas, as far as what you see the growth opportunity is.

Jeremy, that feels like a lot more than one question. But Tom, you want to?

So I mean, I think in all 3 areas that you touched on, I think there's 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's, there are some projects that we are looking at, to take additional volumes, south to Cushing potentially on the crude side, there's clearly a need for additional residue solutions out of the Bakken, so I think that's an area that we're exploring as well. Clearly, there's going to be more expansion capital deployed in the Haynesville as we fill up our existing capacity, I think there will be a point, certainly in pockets of the Haynesville where we'll need to expand the system to take additional volumes there. And then the Eagle Ford, I think largely will be filling 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 our 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. 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.

And our next question comes from Colton Bean with Tudor, Pickering, Holt & Co.

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. Cochin does not commercially or otherwise really divide at the border, so it makes sense for it to end up on one side or the other. And we're evaluating how best to handle that, and some of that is 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 this. It is an attractive asset. It runs full. It's under contract, nearly full, it runs, it's under long-term contract and it's providing a valuable service to our customers. So I think it's valuable whichever side it ends up on.

Got it. That's helpful. And I guess, just as a follow up, so you mentioned on UMTP, kind of moving away from the project, I think you'd filed for 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 Northeast to Gulf Coast capacity given a little more spread to move to.

Yes, we're not pursuing the 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 in a 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 down tick in appetite for southbound capacity, even with bases 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 that we can -- that it is attractive in this market price.

Clearly, it's attractive compared to greenfield cost, and it's a nice pocket of capacity. It doesn't require Bcf or 2 Bcf of commitment. It's one that's out in a day range. So I think pretty actionable. Yes, so good rate.

Our next question comes from Spiro Dounis with Credit Suisse.

I just wanted to go back to something you said earlier, Steve, just around your ability to meet and naturally beat guidance here as we get to the end of the year, despite some of the headwinds unforeseen and all the issues that you had. Curious, Steve, could you 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 strength-based?

Oh, yes. No, 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 demand side are growing faster even in Texas. So we're seeing that 14% number that we're up is 20% on the -- that's 20% on sales, it takes 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's 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 is 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 this on the last call, maybe being kind of a tossup between do you need to just expand the current pipe or do you add a third one? I think he 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 a third pipe's 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 pipes 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 doing more DUCs and they're doing more diversion of rigs to 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 2 or 3 years out as opposed to right now. But we think there'll be a third pipeline, if not more after that.

That's right.

And our next question 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 2 large projects as we look into 2020.

Yes, well, very good point. So if you look at our Texas system today, it's about a 5 Bcf a day system. And with these 2 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.

Helpful. And then just a follow up. I'm 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 [pop] a whole 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 booming 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 2 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 came in, in early January or the shareholder vote in November before you make a decision on KML? Or are those 2 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 million, something like that? So it was most of the addition to the backlog in gas.

Our next question comes from Tom Abrams with Morgan Stanley.

Intrigued with this Bakken residual gas idea. The gas is coming out of the ground, it has to go somewhere, but where? Where does it go? Try to get to the West Coast, we need LNG development there. Try to get to the Gulf Coast and fight past all that Permian-associated gas?

Considering both options...

How are you 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're still -- have some headwinds there on Staten Island. But as you look across into 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?

We're 100% utilized in the 2 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 in the last quarter and we're up to 1.7 million now. So we've got a good short-term plan to keep our head above water over there. 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 site.

Our next question comes from Michael Lapides with Goldman Sachs.

Real quick, and it's a little bit of a 2-for-1. 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 in 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's 3 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 something that Shell is providing. And then we entered into an EPC contract with the EPC contractor. So the bottom line on all that is that insulates us from some of what you would normally think of as the cost 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 just said, we did get some information on Gulf LNG that 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 regas shippers who are there. And we need to explore our options in the market, and that includes not just marketing the facility, but 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 rights 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 to recall 2. 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 2 tanks are still the expectation at the time that the project actually comes into play. And so that's obviously -- at the time that the project comes into play. They've also got the ability to give 2 years of additional notice, 2 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 that -- we don't anticipate that happening.

And the quantification? Can you give us some color on the impact?

Yes, it depends on 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 of contracts at the Edmonton Rail Terminal. I think there's an important contract that expires in 2020 with favorable renewal rights 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.

That's a material impact, then?

The -- it, right now, it looks like it's about $45 million.

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

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's no other major inflows or outflows that pretty much means you got -- you're going to be no debt, no cash. Is that fair?

Yes, that's about right. Pro forma for the cash taxes, they're just over $300 million, the dividend is about $4 billion. 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 Base Line, 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 feature factors?

No, it don't -- I think that's a pretty clean, sort of going forward run rate. The last Base Line tank came in, I said the last one came in, in the fourth quarter, it was just after the beginning of the fourth quarter. So it's got a pretty good run rate going forward for [CapEx] going forward.

Our next question comes from Shneur Gershuni with UBS.

Hello again.

Hey, I -- following the rules. I had 7 questions that I (inaudible). I just wanted to clarify something that Kim had said earlier about total interstate revenues and 30% of that with respect to an adverse situation [that's worked out]. Was just wondering if you can sort of walk us through that again?

Yes. So the -- 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 the revenue associated with that, that could potentially be affected, could have some reduction in it. Not elimination, but some reduction in it, okay? And negotiated rates, discounted rates, would not be affected. They're largely not affected. There's always a possibility that max rates come down enough that they hit 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 subject to max rate, and that's where you would then see an adjustment. So it's not a 30% hit to the revenues, it would be far less than that.

Correct, 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, that's 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 seller's 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 maintained 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. 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're rare to come to market and they're rare to come to market in Western Canada. And so we do think that it tends to be a bit of a sellers' market for these assets.

And the Oklahoma assets? Or any other assets?

Yes, 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 with the revolving facilities, we'll certainly evaluate those.

Our next question comes from Jeremy Tonet with JPMorgan.

So about that Permian natural gas debottlenecking. I think in the past, you guys had talked about 2 Bcf a day gross capacity that could be added on 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're building. Is that 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 it 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 are -- there's anywhere from 1 Bcf to 2 Bcf of potential projects to be done at much higher cost and which really are market -- 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 to those projects that may -- they 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 Bcf to 2 Bcf you talked about that's really kind of like downstream of 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 asset.

That is getting out of Waha?

Yes. Permian to Waha or in -- places in the north, potentially up on the north mainline of El Paso or up into the Rockies, via Trans, Colorado. But again, I -- 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 can get those done.

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

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

On HH?

Yes.

Yes, there's a small remaining expansion to be done. That's a pump station.

That's right. That's pump work.

It looks like a couple of quarters you could do that, if you got commitment?

Yes, you can do that within 6, 8 months.

And I'm showing no further questions.

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

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