Thank you for standing by, and welcome to the Quarterly Earnings Conference Call. All lines have been placed in listen only mode due to the question and answer session. 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 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 Cain 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.
We're 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 Q3 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 high return infrastructure projects in the range of $2,000,000,000 to $3,000,000,000 per year. In short, we 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'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'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 Michaels, 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. And 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 removes 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 plans for the first three 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 outperformance, notwithstanding the absence of earnings contribution from Trans Mountain, the delay in the completion of EBITDA and the termination of the 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 3rd 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 share approximately $2,000,000,000 to debt reduction. We are achieving our leverage target.
We're having a very good year, strong financial performance, tremendous progress on the balance sheet, and we're finding good opportunities to deploy capital and 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 three rating agencies into positive ratings actions. We continue executing on our project backlogs, 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 BHP DHP. Continue returning value to our shareholders with a growing and well covered dividend.
And with respect Trans Mountain, KML is evaluating all options. 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 mid stream assets and to use 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 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 forecast, we will likely not have further updates on this until we have something more definitive to say. 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 dividends. We have also updated our leverage target to around 4.5 times and we're there now with the Trans Mountain transaction. With our leverage target achieved, we would expect to use the additional available cash that's on the equity portion of the expected growth projects that we had 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.
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 pipe where transport 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 PCF or 16%.
In the overall power market, natural gas now comprises approximately 38% of total generation, up from 36% in the Q3 of 2017. Exports to Mexico were up 375,000,000 cubic feet a day on our pipes or 13% versus the Q3 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 and longer term will drive expansion opportunities as our pipes reach capacity. On the supply side, we're also seeing high volume growth. Our gas and crude gathering volumes were up 15% were up 20% starting and 15%, respectively, driven by higher production in the Bakken and the Haynesville and the Eagle First.
In the Haynesville, our gathering volumes doubled in the quarter versus 2017. On the project side in Equigas, 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.
On our Oval Liquefaction project, we now anticipate that it will be in service in the Q1 of 2019. With the delays impacting our DCF purchase budget, the half and half 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 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 Q2 of 2017. Sactron 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 Sacrock. Tall cotton volumes were up versus last year, but they are below our budget. Our net realized crude price was relatively flat for the quarter despite a higher WTI price. WTI hedges we have in place as well as the increase in the mid-twoshed differential. In our terminals business, we benefited from liquids expansions in Houston Ship Channel, 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 New York spill pack, making facilities in New Jersey more economic option 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 petcoats. Although you don't see much benefit in this result given the way our contracts are structured, GAAP revenue recognition rules and to a lesser extent some pricing changes.
Liquid utilization was 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 HH, but that was offset by somewhat lower contributions from Pacific due to higher operating costs. Crude and condensate volumes were up 13 percent and that was due to increased volumes on our pipelines in the Bakken, which drove higher contributions from HH 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 Michaels, our CFO, to go through the numbers.
All right.
Thanks, Tim. 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 represent a 60% increase to $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 2.5x our dividend level. As you've already heard, Cam, I had a great another great quarter.
Our performance was above budget and above last year's Q3. As Steve mentioned, we expect to beat our budget on a full year basis for all DCF, EBITDA and leverage. And I'll walk through the GAAP financials, distributable cash flow and the balance sheet. On the earnings page, revenues are up $236,000,000 or 7% from the Q3 2017. Operating costs are down $453,000,000 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 $162,000,000 or 7%, which is consistent with the growth in revenue. Net income for the quarter is $693,000,000 or $0.31 per share, which is an increase of 3.59 $1,000,000 $0.16 per share versus the Q3 of 2017. Also that increase is also attributable to the gain from the Trans Mountain sale. Looking at earnings on an adjusted basis, we're looking at adjusted earnings and account certain items, the $693,000,000 would be $469,000,000 which is $141,000,000 or 43% higher than adjusted earnings in the Q3 of 2017.
Adjusted earnings per share is 0 point dollars higher than the prior periods. Moving on to distributable cash flow. DCF per share is $0.49 which is 0 point 0 $2 up from the Q3 of 2017, a 4% increase. And that is yet another very nice quarterly performance for 2018 and strong growth in our natural gas segment. Natural gas was up $81,000,000 or 9%.
That segment benefited on multiple fronts. As you've already heard, Haynesville, Eagle Ford and Bakken shale volumes were up and that benefited Kinderhawk, South Texas and Highland Gathering and Processing assets. Our EPMG and NGPL pipelines had greater Our EPNG and NGPL
pipelines had greater contributions driven from
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 TJ Basin production. Actually offsetting those items was lower contribution from our Gulf LNG, excluding due to a contract termination. The 2 segment was up $16,000,000 from last year, driven by NGL prices and greater volumes.
Kinder Morgan Canada segment was down $18,000,000 or 36% due to the sale of Transmeln and the loss of 1 month of contract during the quarter. G and A is lower by $16,000,000 and that's due to greater capitalized overhead as well as lower G and A from the Trans Mountain sale. Interest expense is $10,000,000 higher, driven by higher interest rates, which offset the benefit from a lower debt balance as well as some interest income that we earned on the Trans Mountain sales proceeds. Cleaning capital was $36,000,000 higher versus 2017. We had budgeted in sustaining CapEx in 2018 to be higher than 2017 and are actually expected to end the year favorable to our budget.
So to summarize, the segments were up $89,000,000 G and A costs were down $16,000,000 Interest expense was up $10,000,000 Cash taxes were up $5,000,000 Other items driven by an increased pension contribution were a reduction to DCF of $9,000,000 and sustaining CapEx was higher by 38,000,000 dollars That adds up to $43,000,000 which explains the main variances in the $38,000,000 period over period change in EPS. 2018 remains on track to be a very good year for Kinder Morgan. We expect to exceed our 4 digit financial targets for the year, driven by natural gas and CO2 segments, lower G and A, cash taxes and sustained capital expenditures, partially offset by reduced contribution from Kindermarten Canada as a result of the Trans Mountain sale as well as lower contributions from our Terminals segment due to lower leased capacity in the Northeast and lower than expected goldflip throughput throughput. One more note here, while natural gas is nicely ahead of plan year to date and is expected to finish the year ahead of plan, The segment does expect to be impacted relative to budget in the 4th quarter by the delayed in service of our Elvira and LNG project, as Steve and Ken mentioned.
Moving on to the balance sheet. We expect we ended the quarter at 4 point 6 times net debt to EBITDA. And just to repeat that, we expect we ended the quarter at 4.6 times net debt to EBITDA. So very important milestone and nice improvement from the 4.9 times last quarter and 5.1 times at year end 2017. Our 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, 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 $919,000,000 of cash that will bring 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 $34,500,000,000 a decrease of $2,100,000,000 from year end and from last quarter. So to reconcile that $2,100,000,000 for the quarter, we generated $1,093,000,000 cash flow. We had growth capital and contributions to JVs of $715,000,000 We paid dividends of $444,000,000 We received the TransMil sale proceeds of $3,391,000,000 We took out the KML Public Shareholders portion of those proceeds of $9.19 and we had a working capital use of $337,000,000 primarily as a result of the UTMB refund payments. And that reconciled to our $2,069,000,000 reduction in net debt for the quarter.
For the full year, our year to date reconcile our reconciliation, We generated $3,457,000,000 of distributable cash flow. We had growth CapEx and contributions to JVs of 1 point $981,000,000,000 We paid dividends of $1,163,000,000 We repurchased $250,000,000 of shares and we received a transaction on sale proceeds of $3,391,000 We exclude the PNNL public shareholders portion of that of $9.19 And we had a working capital use of $455,000,000 year to date. That also includes the EP and G refunds as well as interest payment. And that reconciled to the $280,000,000,000 $2,080,000,000 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 close.
The sales price amounts to about C11.40 dollars per KML share. And on top of that, KML shareholders have a strong set of remaining midstream assets and 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 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 in 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 amount to be distributed
in the second. Typically, the
shareholder vote is to approve 2 things. 1st, the 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 2nd approval is to affect a 3 for 1 reverse split post payment of the special dividend.
As a reminder, the vote is subject to a 2 thirds majority of the outstanding shareholders and KMI, which owns approximately 70% as agreed to voted favorably. Moving to the business front, we now have all 12 baseline banks in service as we placed 5 of the 6 remaining banks in service during Q3 and the last tank in service just after 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 342,000,000 of our share with approximately 31,000,000 remaining of the total spend of approximately $373,000,000 The $373,000,000 compares to an original estimate of $398,000,000 and as I mentioned last quarter, is a result of cost savings on the project. Now moving towards the results.
A and K and Onboard declared a Board declared a dividend for the 3rd quarter of 0.16 $25 per restricted voting share or $0.65 annualized, which
is consistent with previous guidance.
Earnings per restricted voting share for the Q3 of 2018 are 0 point 0 $5 from continuing operations and $3.78 from discontinued ops and both are derived from approximately $1,350,000,000 of net income, which is approximately $1,300,000,000 versus the same quarter in 2017. Obviously, the big driver there was
a large gain in the
sale of the Trans Mountain pipeline. So let me focus for a minute on what's driving the $12,400,000 increase in income from continuing operations. Stronger revenue associated with the baseline tanker 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 $44,000,000 compared to approximately $42,000,000 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 ETF for the quarter, which is not adjusted for discontinued ops is $80,600,000 which is up $3,400,000 for the comparable period in 2017 and within $1,000,000 of our budget. That provides coverage of $7,000,000 reflects a DCF payout ratio of approximately 71%. Looking at the components of the DCF variance, segment EBITDA before certain items is off $8,400,000 compared to Q3 2017, the pipeline segment off approximately $8,200,000 and the terminal segment is completely flat. The Pipeline segment was lower primarily due to the Trans Mountain assets going away and that was approximately 15 $1,000,000 negative. It was offset by the non recurrence of an unrealized FX loss from some intercompany notes that were in place in 2017 and lower O and M and Cogent compared to 2017 as we had some non routine integrity management activities in 2017 that were completed.
The terminal segment was essentially flat with the baseline Technical Terminal project coming into service, the higher contract rates and renewals at the North 40 Terminal and 77 South Terminal offset by the expiration of the contract on the Imperial JV. Same unrealized FX dynamic I mentioned on the pipeline segment and the lease payment on the Evans and Soft Facility to the government. G and A is favorable by $2,500,000 due primarily to the removal of the Trans Mountain G and A firm line. Interest is favorable by for a month. Interest is favorable by approximately $11,000,000 due to the interest on the Trans
Mountain proceeds and lower
interest expense. The cash back line item was essentially flat.
Preferred dividends were up 5 point $2,000,000 given Q3 2018 had both tranches outstanding for the full quarter. Sailing capital was favorable approximately $3,800,000 compared to 20 17 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 $50,000,000 to $55,000,000 of adjusted EBITDA for the 4th quarter, almost the full quarter of the baseline banks in service during the during the Q4. 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 ninethirty, and my comments will focus only on the line items related to the retained assets and not the assets and liabilities held for sale. Cash increased approximately 4.2 $39,000,000,000 to $4,350,000,000 There are a lot of moving pieces in the change associated with the Trans Mountain, with Trans Mountain that stemmed from the CapEx spend on behalf of government to 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 $4,426,000,000 of net proceeds received plus ECF generated, less expansion CapEx, less distributions paid net of the DRIP and less the payoff of the The dividend we will pay in January and that's the approximate $11.40 per KML share will be approximately 4,000,000,000 dollars and then we'll pay a capital gains tax associated with the transaction of just over $300,000,000 in Q1 twenty approximately $19,500,000 primarily due to an increase in several items in accounts receivable with the largest component of that coming from a billing material related to the Imperial JV.
Net PP and E decreased by $3,000,000 as a result of depreciation in excess of net assets placed in service. Deferred charges and other assets decreased by approximately $64,000,000 which is a result of a write off of the unamortized debt issuance costs associated with the TAM facility that we canceled. On the right hand side of the balance sheet, other current liabilities increased $321,000,000 primarily due to the taxes payable on the Trans Mountain sale. Other long term liabilities decreased by $283,000,000 primarily as a result of a deferred tax liability release as a result of the gain on the Trans Mountain gain on the sale of Trans Mountain. Also note, we ended the quarter without any outstanding debt.
And with that, I'll turn it back Steve.
Okay. We're going to go to Q and 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 of others with questions, we limit the questions per person to 1 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, you can come back on and start the questions.
Thank you. Thank you. Our first question comes from Jean Ann Seltzer with Bernstein. Hi. Team.
How should you go against the potential downside for KMI of the 501 GRP? And do you have any internal projections making
sure of what EBITDA loss
can be in a worst case?
Yes. It's very hard to predict 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 $100,000,000 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 intrastate assets earn their cost of service, okay? So you put that all together and you roll off several years forward and you're really just talking about the max rate revenues of our interest rate business that are subject to some adjustment. If the max tariff rate comes down, which is what trade 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 actions they're taking, they're treating interstate natural gas pipelines as if to a regulated franchise monopoly utility.
That hasn't been the case since the 70s. 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 point that in other rate making arguments to bear as we go through the five zero one gs process. So thanks for giving me a chance to stand
One thing, one thought there, the 30% that you mentioned is just of the inter state revenues, not of the whole gas segment, it is of the in per state.
Yes, that makes sense. Would it be fair to think about it maybe as a multiple of $100,000,000 going away in a worse 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 regulators 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.
That makes sense. And then as a follow-up, you mentioned on the last call the potential of recontracting at higher those categories on PTNG and DTL and I believe your introsate 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 Tom. Do you have a quantification of that? Yes. I mean, it's hard to put a number on all of that.
I mean, I think we're talking about $25,000,000 somewhere in that range kind of year over year upside.
Sounds great. That's all great. Thank you. And our next question comes from Samir Grasone with UBS.
Hi. Good afternoon, everyone. Maybe just to follow-up on that 501 question. Just wondering if you can clarify a couple of things. I mean, if you see right now, your comp debt request is effectively informational at this point right now and it's not actionable.
And then as part of your discussion
on it, can you speculate on the
purpose of the FERC making this request in the 1st 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 routine ROE. I was wondering if you can sort of outline on that.
Okay. On the first, we view it as an informational filing. And we view it as, frankly, a bad information filing. There are a number of things that it overlooks, including the negotiated rates and other things that I mentioned uses a very old, very old, mitigated ROE, uses a cap structure that we don't think is appropriate. And it kind of forces information into a particular template that we don't think is consistent with the way commission has done rate making in the past.
And so in the course of all this, we'll get an opportunity, I'm sure, to point that out. But what I would submit that you all ought to be thinking about is you're going to get as many of you have written, these numbers are going to be uninformative. So as these 501Gs roll out, you need to take that into account as you're looking at them because they have flaws in our view, particularly in light of past commission policy and precedence. So we think they're informational and not very much information. On first purpose, we won't speak for them, but I think it was fairly clear from the process leading up to this that it was based on a desire to make sure that the benefits of the income that the tax cuts pathway 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. And as a follow-up question, I believe Rich mentioned in his prepared remarks an ability to invest $2,000,000,000 to $3,000,000,000 a year on an ongoing basis. How do you envision those dollars being spent? Are we looking at some more large scale projects, something like Skyway? Or do you see it more of a series of $100,000,000 to $200,000,000 type projects?
And if so, where do you see capital finish that?
I think it will be primarily directed to natural gas. We put we grew the backlog quarter to quarter, dollars 200,000,000 after putting several projects in service, and that was largely due to a net addition to the backlog of $600,000,000 from the National Gas segment. If you look at the fundamentals that Tim took you through, we would expect to see not only increased utilization of the existing system, but the opportunity to put more capital to work. And we're looking at what those projects will be. It's a little hard to say how many big ones will it be versus a collection of smaller $300,000,000 ones.
But we think we'll have good opportunities there.
This shipping comes from Jeremy Tonnick with JPMorgan.
Hi. Good afternoon. Just wanted to
turn to business a little bit here. It seems like you have some things kind of moving in your favor as far as growth is concerned in natural gas. I mean, you know there's kind of a back end of the hands for the Eagle Ford and that came in there. And just wanted to touch a bit more on those areas. It seems like the Bakken is quite wide basis differential that's probably not based on there.
I'm wondering what that could mean to you guys as far as possibly expanding HH or other infrastructure you might have. The Hainesville, things like the surge in productivity there. GT might be looking to do more, having conversations with guys like that that are putting more capital to work. And then the Eagle Ford as well seems like kind of coming off the trough side. Just wondering if you could comment on those three areas as far as what you see the growth opportunities?
Jeremy, that feels like a lot more than one question. But I mean, I think in all three 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 are some projects that we're looking at 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 capacity. I think there'll 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 nothing prospects were good.
Got you. Thanks for that.
I was going ask about Permian Brownfield debottlenecking opportunities in the interest of not getting in trouble. I'll hop back in the queue.
Thank you. The next question comes from Colton King with Tudor, Pickering, Holt and Company.
Good afternoon. As you evaluate next steps on KML, is there any consideration of potential asset inclusion from the KMI level, specifically maybe the U. S. Portion of Coshin? And I guess to touch on that, how does that fit into the tender network if KML were to exit the portfolio?
Yes. So Coshin does not commercially or otherwise really divide its quarter. So it makes sense for it to hit 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 to put your finger on something that we have to resolve as part of it. It is an attractive asset. It runs full. It's under contract. It's 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 that project. I think you filed for abandonment on the PPP 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 where spreads have moved to?
Yes. We're not pursuing that project any further, and we reflect the current accounting for the quarter, etcetera. 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 put on PTV 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 pretty good opportunity on the other.
Okay. And so no real downside for southbound capacity even when base is being a bit tighter?
Yes. For this capacity, which is I don't know if this is the last one, but it's among the few remaining opportunities to take existing northbound capacity and turn it around. So it's not brand new greenfield long haul pipe. So it's one of the last, if not the last, pipeline reversal projects. So we think if we can that it is attractive in this market price.
Clearly, it's attractive compared to greenfield cost and it's it's in the pocket of capacity. It doesn't require a Bcf or 2 Bcf of contentment. It's more in the day range. So I think pretty actionable. So good and great.
Got it. Thank you very much.
You. And this question comes from Spiro Dounis with Credit Suisse.
Hey, good afternoon. Thanks for taking the question. I just want
to go back to something
you said earlier, Steve, around your ability to meet and actually beat guidance here as we get to the end of the year despite some of the headwinds we've seen
a little bit issues that
you had. Curious if you could give us a little more detail around what exactly is driving your ability to do this? And ultimately, what I'm looking at is how much of that is really sustainable to 2019 versus being just commodity shrink based?
So yes, it's really I mean, as Tim 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 that's 20% on sales and that's 25% of transport because it's a good interest rate market, which is a good thing. That's not a FERC regulated position for us. So really, there is good tailwinds there, and they're expected to continue.
And we've had growth, which we've ever 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 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 at Kinder Morgan is the largest network of pipes moving natural gas. About 40% of all the natural gas moved on our system. And when you have the kind of dynamics that 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. Appreciate that. And then I'm
not sure if this is where Jeremy was coming up, 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 on the last call, maybe seeing kind of a cost up between 8630 current pipe as you had a third one. I think you said some cleanup last time.
Just wondering if you've gone through
the rest of the process.
Is that more clear to you
to have you feel like it's clear one way or the other that it's quite needed or do you still get maybe 2.7 DCF a day on Permian?
Yes. So the 2.7 Bcf on the Permian Highway was it, we could go to 48 inches We went to 42 inches because the supply chain for the pipe for 42 inches was much more secure. And as Kim said, we locked in our pipe there. And so we took care of that risk. But I think our view, and Tom, you elaborated, 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're doing more docks and they're doing more diversion of rigs other places, etcetera. They're taking a brief break in the breakthrough 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. Okay. I think that's right.
Got it. Appreciate the color. Thanks, everyone.
Thank you. Our next question comes from Tristan Richardson with SunTrust.
Hey, good afternoon, guys. 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 with these 2 projects, 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 piece 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 then continue to see exports to Mexico rise, etcetera.
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. Curious what areas in terms of the additions to
that point outside of BHP, sort of
where you're seeing growth projects additions?
Okay. We touched on 1 with the Tennessee pipeline reversal. We have additional projects serving LNG coming up that we are looking at on as well as in Kinder Morgan, Louisiana pipeline. We'll look at those also on the Texas Gulf Coast as the trend goes on in the West. We'll continue to find, I think, some debottlenecking opportunities, which may not necessarily have 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 to the earlier question, the G and 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 existing systems to take additional volume with potentially small decodel, I think, not capital intensive expansion. So we'll get some volume, not for free, but for purely free as it grows in the Haynesville. And so more in the Bakken than in the other two basins.
Our next question comes from Keith Stanley with Wolfe Research.
Hi. Good afternoon. On on the KML strategic review process, is there any reason you'd want to wait until the current account special payment 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? So we don't necessarily have to wait on that for a decision. We can work our process even starting now. Okay.
And one follow-up just on the backlog, maybe $800,000,000
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 the full exercise as the options that the large shippers on the system have to take, like, pesos net, dollars 600,000 something like that. So it was most of the addition to the backlog in gas.
Next question comes from Tom Abrams with Morgan Stanley.
Thanks. I'm sure you could just talk some digital gas idea. That was somehow trying to have to go somewhere, but where? Where does it go? Try to get to the West Coast from East LNG development there, try to get to the Gulf Coast and fight past all that Permian associated gas?
How are
you thinking about that? Yes. I mean, I think we're considering both options and I think we're likely down to the Rockies area, but we're considering both.
And then on the New York terminalling, still got 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 pace and maybe starting
to climb them out and improve?
400% 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 last quarter and we're up to 1,700,000 now.
So we've got a good short term plan
to keep our head above water over there. The steel 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.
And this concludes from Michael Lapides with Goldman Sachs.
Hey, guys. Thanks for taking my question. 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
that vary 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 in place. The churn 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 are invested in it. It was promoted. Our development of it was promoted. The other thing that's protected us here, Michael, is we have in our contractual arrangements, there's 3 important parties here. There's us as a project developer and manager, etcetera.
There is Shell, who is the divider of the units that are being provided to do the liquid fraction. So that's not, if you will, on us. That's something Shell is providing. And then we entered into an EPC contract with our EPC contractor. So the bottom line on all that is it insulates us from some of what you would normally think of as the cost 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 self LNG.
Yes. Can you take that next step for self LNG outside of the obvious with the per TIF process?
Yes. So as you just said, I mean, we did get some information on Gulf LNG. The commission actually gave a time frame 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 to perfection opportunity. There's been a lot of talk about the next wave of LNG.
We need to get our current situation resolved with our recast shippers who are there, and we need to explore our options in the market. And that includes just marketing facility, potentially looking at a JV opportunity or other things.
Our next 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 JML if TMX was completed. I understand they have the right to recall tanks. And I think the original expectation was they could recall, so we're likely to recall too. So my question is, is that still the expectation? And what is the impact on EBITDA that came off as a going concern if that in fact happens?
Yes, that's still the expectation. It's still the expectation. The time that the project actually comes into play. And so that's obviously the time the project comes into play. They've also got the ability give 2 years of additional notice 2 years of notice to recall additional tanks to the extent that they can't meet their regulated requirements, existing regulated requirements after they give notice.
And so
that's we don't anticipate that anticipate that happening. And the quantification? And quantify give us some color on the impact.
Yes. It depends upon what we actually have in terms of third party business out there. And so it would depend on the specific situation.
Okay. Similar question then on the exploration of contracts with the Edmonton Reals 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 5 plus contract, so we will have a management fee in place at that time. So we looked at this debt that will be paid off in its initial term. And in April of 2020, that contract switches over to just a management contract.
So that's a material impact,
Right now, it looks like it's about $45,000,000 Thank you.
Next question comes from Robert Kwan with RBC Capital Markets.
Great. Thank you.
Hi. Just wanted to confirm what the numbers Zach gave, both the $4,000,000,000 on the dividend and then just over $300,000,000 on the cash. Just to make sure there's no other major inflows or outflows that's pretty much you're going to keep
in debt and cash, is that fair?
Yes, that's not right. Pro form a for the cash taxes are just over 300, the dividend of about 4, that's right. Okay.
And then just on the $50,000,000 to $55,000,000 in the 4th quarter. So that's pretty much increased all of the second phase of baseline. You get that piece out 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 and
A run rate is? And are there any kind of future factors?
Yes. No, it does. I think that's a pretty clean sort of going forward run rate. The last baseline tank came in, I said the last one came into
the 4th quarter, it was
just after the beginning of the 4th quarter. So it's got a pretty good run rate going forward for us going forward.
Okay. Thank you very much.
Next question comes from Samir Khomeini with UBS.
Following the rules, I had 7 questions.
I just wanted to clarify something that Kim had said earlier about total interstate revenues and 30% of that with respect to an AFFO situation. I 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 it's the revenue associated with that that could potentially be affected, could have some reduction in it, not double inflation, but some reduction in it, okay? And negotiating rates, discounted rates would not be affected or largely not affected.
There's always a possibility that tax rates come down enough that they hit some of the discounts and they pull the rate, the tax rate goes below the discounted rate. 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.
Just to clarify, so basically, what
you're saying is 30% of your revenues sorry, 30%
is subject
to the 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, it is 30% of the regulated interstate revenues that we're talking about.
And yes, so if you had we've had great settlements where we're taking a 5% reduction, for example, or 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. It's not the whole 30%.
Okay. Thank you. That's much appreciated. And as a second follow-up question,
you sort of see
in your opening remarks, what made on if you ended up selling Canada, where the proceeds could go and so forth. I was just wondering if you can talk about whether it's a higher similar market in Canada. And then in terms of thoughts around asset sales, are there any other assets that you're talking about selling? For example, the Oklahoma assets, we had an impairment earlier this year. And is it fair to assume similar political terms of buybacks if we were to
get both these comps from asset sales? Yes. So first of all, what we were talking about with respect to use of proceeds would apply kind of wherever the proceeds came from. We'd make sure that we maintain that same leverage ratio, but then we would use them. If there were available projects, we'd use them for projects, but otherwise, they would go to share buybacks.
That's our currency. 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 Ocean 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. So we do think it tends to be a bit of a seller's market for these assets.
And the Oklahoma assets or any other assets? Yes. So
Oklahoma, as we said, we have good G and C 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. Specific assets. But everything here at the price, right, at the right price, but the whole driver is what's going to create the most shareholder value. That's it.
So if we find those opportunities on pieces of our asset base as we have in the past with some of our home facilities, we'll certainly evaluate those.
Next question comes from Jeremy Tonet of JPMorgan.
Hi. So about that Permian natural gas bottlenecking. I think in the past you guys
have talked about 2 PGF a growth passes that can be added on between kind of Texas interstate, 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 any more that you guys can squeeze out on your assets there given how WAHA touched the buck recently and see if Nebraska 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 on the existing capacity that we have. There are anywhere from a Bcf to 2 Bcf of potential projects to be done at much higher costs, which really are markets aren't supported by the market today. And if we're deployed, it would be kind of post PHP time horizon. But we're certainly working at those smaller components of those projects that may still make economic sense. And really the downstream side of it is really what Steve talked about earlier and that is clearly a lot of the demand for the 4 Bcf is driven by Mexico exports, LNG exports as well as growth along the Texas Gulf Coast and the petrochemical
So just to be clear, the 1 to 2 Gs that you talked about, that's really kind of like downstream of the PHAP and kind of that last mile getting to market, not more getting out of Waha. Is that the right way to think
about it? It's more Permian.
It is getting out of Waha? Yes. Okay. So that's
more Permian to Waha, more important I would say to the north, potentially up on the North Main Line of El Paso or up in the Rockies via turn from Chandler, Colorado. But again, 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 people don't get filled out.
Got you. And then just to follow-up real quick, and we've spoken about WAs before. If you can expand that, how long would that take to do? Is that kind of a punching thing that could be done in a year? Or is this kind of longer term project
in nature? On Double H? Yes. Yes. There's a small remaining expansion to be done that's compensation.
Like a couple
of quarters, you could keep that commitment?
Yes. You could do that within 6,
Thank you. And I show 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.