Thank you for standing by, and welcome to the quarterly earnings conference call. All lines have been placed in listen-only mode until the question-and-answer session. Today's call is being recorded. If anyone has any objections, you may disconnect at this time. I would now like to turn the call over to 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 Litigation Reform Act of 1995, Securities 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. 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. To reinvest it in expansion projects, to grow our future cash flow, paying dividends, de-levering 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 high-return infrastructure projects in the range of $2 billion-$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. Like many of you on this call, I'm puzzled and frustrated that our stock price does not reflect our progress and future outlook.
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. 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, then turn it over to our President, Kim Dang, to give you the update on segment performance. David Michels, KMI CFO, will take you through the numbers. 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. 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 measure targets. We expect to achieve this outperformance notwithstanding the absence of earnings contribution from Trans Mountain, the delay in the completion of Elba, and the termination of 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 first quarter. We have now sold out all of the available capacity, two Bcf a day under long-term contracts, as we projected when we FID'd 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 four and a half times. With the KML announcement regarding the use of proceeds and KMI's announcement that we will apply KMI share, approximately $2 billion U.S., to debt reduction. We are achieving our leverage target. We're having a very good year. Strong financial performance, tremendous progress on the balance sheet, we're finding good opportunities to deploy capital on 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.
Continue executing our project backlog, particularly the completion of Elba and the advancement of Gulf Coast Express and PHC. 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 PHC. Continue returning value to our shareholders with a growing and well-covered dividend. 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 standalone enterprise. Simply put, we like the assets and we don't have to sell them. 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 4.5x, 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 have in the backlog or for share repurchases. I'll say again that we continue to believe that our current share price is an attractive value for share repurchases. 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%. I think it's worth spending a moment on the overall market. Current estimates show that the overall U.S. natural gas market is going to approach 90 BCF for 2018, which is over 10% growth versus 2017. This is driving nice results on our large diameter pipes, where transport volumes are up four BCF a day. That's 14%. If you look at power demand on our system, it was up in the quarter up one 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. 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 20% and 15% respectively, driven by higher production in the Bakken, in the Haynesville, and the Eagle Ford. In the Haynesville, our gathering volumes doubled in the quarter versus 2017. On the project side in natural gas, we had a few noteworthy developments. Steve gave you the update on PHP.
On Gulf Coast Express, we've secured approximately 80% of the right of way. Construction is starting this month, we remain on target for October 2019 in service. On our Elba with the Frack Sand project, we now anticipate that it will be in service in the first quarter of 2019. The delays impacting our DCF versus budget, the natural gas segment is still expected to exceed its budget for the year, 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 second quarter of 2017.
SACROC volumes were up 4% versus last year, 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, they're below our budget. The 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 Midland-Cushing differential, offset the increase in WTI. For the balance of this year and for 2019, we've substantially hedged the Midland-Cushing differential. Our terminals business, we benefited from liquids expansions in Houston Ship Channel, in Edmonton, the new Jones Act tanker that came on in 2017 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's spill tax, making facilities in New Jersey a more economic option for our customers. A number of other factors, which includes non-core asset divestitures, contract expirations in our Edmonton rail facility, higher fuel and labor costs in our steel business. Bulk tonnage in the quarter was actually up 5%, primarily driven by coal and petcoke. You don't see much benefit in this result, given the way our contracts are structured, GAAP revenue recognition rules, to a lesser extent, some pricing changes. Liquids utilization was down 2%, primarily due to tanks out of service for API inspections and the Staten Island facility I mentioned a moment ago.
In the products segment, we benefited from increased contributions from Cochin and Double H, but that was offset by somewhat lower contributions from Pacific Operations due to higher operating costs. Crude and condensate volumes were up 13%, 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. 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, would represent a 60% increase from $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 two and a half times our dividend level. As you've already heard, Kim, had another great quarter. Our performance was above budget and above last year's third quarter. As Steve mentioned, we expect to beat our budget on a full-year basis for all DCF, EBITDA, and leverage. I'll walk through the GAAP financials, distributable cash flow on the balance sheet.
On the earnings page, revenues are up $236 million or 7% from the third quarter 2017. Operating costs are down $453 million or 18%. 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 revenue. 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 2017. Much of 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, taking out certain items. The $693 million would be $469 million, which is $141 million, or 43% higher in adjusted earnings in the third quarter of 2017.
Adjusted earnings per share is $0.21 or $0.06 higher than the prior period. Moving 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 is a strong growth in our natural gas segment. Natural gas was up $81 million 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 Hiland Gathering and Processing assets. EPNG and NGPL pipelines had greater contributions driven by Permian supply growth. Our Tennessee Gas Pipeline was up due to expansion projects which were placed in service. Our CIG pipeline experienced strong growth due to greater DJ Basin production.
Partially offsetting those items was lower contribution from our Gulf LNG facility due to a contract termination. The CO2 segment was up $16 million from last year, driven by NGL prices and greater volumes. The Kinder Morgan Canada segment was down $18 million or 36% due to the sale of Trans Mountain and the loss of one month of contracts during the quarter. G&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. Sustaining capital was $36 million higher versus 2017.
We had budgeted sustaining CapEx in 2018 would be higher than 2017 and are actually expected to end the year favorable to our budget. 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. 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 lower 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 and 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 ended the quarter at 4.6 times net debt to EBITDA.
Just to repeat that, we ended the quarter at 4.6 times net debt to EBITDA. A very important milestone, a 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 4.6 times. 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 3rd 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.
We believe that's a more accurate reflection of KMI's leverage. Including that adjustment, net debt ended the quarter at $34.5 billion, a decrease of $2.1 billion from year-end and from last quarter. To reconcile that $2.1 billion for the quarter, we generated $1.093 billion of distributable cash flow. We had gross 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 set the KML public shareholders' 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. The net of that reconciles to our $2.069 billion reduction in net debt for the quarter. For the full year, our year-to-date reconcile, certain affiliates at the cash creations, we generated $3.457 billion of distributable cash flow.
We had gross CapEx and contributions to JVs of $1.981 billion. We paid dividends of $1.163 billion. We repurchased $250 million of shares. We received the Trans Mountain sale proceeds of $3.391 billion. 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. That reconciles to the $2.08 billion reduction in net debt year-to-date. With that, I'll turn it back to Steve.
Okay, thanks. We closed the transaction. 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 CAD 1,140 per KML share. On top of that, KML shareholders have a strong set of remaining upstream assets in an entity with little or no debt and with opportunity for investment expansion as well as the potential for a strategic combination. We have a shareholder vote coming up on November 29th on a couple of matters that Dax will take you through and expect the distribution of proceeds to occur in January, as David mentioned. 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 3rd, 2019, following shareholder vote on November 29th. More on the amount to be distributed in a second. Specifically, the shareholder vote is to approve two things. First, a reduction in stated capital, which is an Alberta corporate law concept. With the reduction in stated capital, we will ensure that our distribution is consistent 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 a 3-for-1 reverse split post-payment of the special dividend.
As a reminder, the vote is subject to a two-thirds majority of the outstanding shareholders, KMI, which owns approximately 70%, has agreed to vote in favor. Moving to the business front, we now have all 12 Baseline tanks in service as we placed five of the six remaining tanks in service here in Q3 and the last tank in service just after the quarter ends. 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. Moving towards results.
Today, the KML board declared a dividend for the third quarter of 0.1625 per restricted voting share, or $0.65 KMI, 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, 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 in the sale of the Trans Mountain pipeline. Let me focus for a minute on what's driving the $12.4 million increase in income from continuing operations. Stronger revenue associated with the Baseline Tank 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 third item in the quarter was the gain on the sale of Trans Mountain. Total EPS for the quarter, which is not adjusted for discontinued ops, is $80.6 million, which is up $3.4 million from the comparable period in 2017 and within $1 million of our budget. That provides coverage of approximately $7 million, reflective 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 not as an approximate $15 million negative.
It was offset by the non-recurrence of an unrealized FX loss on some intercompany notes that were in place in 2017, Lower O&M and Cogen 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 Tank and Terminal project coming into service and higher contract rates and renewals at the North Forty Terminal and Edmonton South Terminals offset the expiration of a contract on the Imperial JV. Same unrealized FX dynamic I mentioned on the pipeline segment The lease payment on the Edmonton South facility to recover. G&A is favorable by $2.5 million due primarily to the removal of the Trans Mountain G&A requirement. Interest is favorable by approximately $11 million due to the interest on the Trans Mountain proceeds and lower interest expense. The cash tagline item is essentially flat.
Preferred dividends are up $5.2 million, given Q3 2018 had both tranches outstanding for the full quarter. Maintaining capital was 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-$55 million of adjusted EBITDA for the fourth quarter from almost the full quarter of the Base Line Tank in service during the fourth quarter. Consistent with past practices, 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 compared 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 on the sale. Cash increased approximately $4.239 billion to $4.35 billion. There are a lot of moving pieces in the change associated with the Trans Mountain, which stems from the CapEx spent 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. 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 gross, and less the payoff from the debt we had 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 approximately $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 in accounts receivable, with the largest component of that coming from a billing to material 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 increased by approximately $64 million, which is a result of a write-off of the unamortized debt issuance costs associated with the TM facility that we canceled.
On the right-hand side of the balance sheet, other current liabilities increased $321 million, primarily due to the taxes payable on the Trans Mountain sale. Other long-term liabilities decreased by $283 million, primarily as a result of a deferred tax liability release as a result of the gain on the sale of Trans Mountain. It's also of note we end the quarter without any outstanding debt, and we'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? With that, we'll turn it over. Operator, you can come back on and start the questions.
Thank you. At this time, if you'd like to ask a question, please press star one and please record your name when prompted. If you'd like to withdraw the question, you may press star two. Again, to ask a question, please press star one. Thank you. Our first question comes from Jean Salisbury with Bernstein.
Hi. How much do you build in the potential downside for KMI of the Form 501-G? Do you have any internal projections when you compare of what the drag loss could be in a worst case?
Yeah, it's very hard to project because the outcome is highly uncertain. 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, 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 transit is interstate. Some of it is our intrastate business in Texas, which we're obviously growing. Not all of our regulated interstate assets earn their cost of service. Okay?
If you put that all together and you roll off several years forward, and you're really just talking about the max rate revenues for our interstate business that are subject to some adjustment. If the tax tariff rate comes down, which is what today's 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 that they're taking, they're treating interstate natural gas pipelines as if they were regulated franchise monopoly utilities. That hasn't been the case since the 1970s. Over the last 30 years, the Commission has carefully crafted a competitive market through various administrations, one pro-competitive rulemaking after another, in order to create competition between pipelines. We operate in a competitive market, not in a franchise service territory.
We expect to point that and other rate-making arguments to bear as we go through the 501G process. Thanks for giving me a chance to stand on a soapbox.
One thought there. The 30% that he mentioned is just of the interstate revenues.
That's right. Yeah.
Not of the whole gas segment. It is of the interstate.
Yeah, that makes sense. Would it be fair to think about it maybe as a multiple of the $100 million going away as sort of a worst case?
Yeah, Jean, 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. I think we will be able to actively mitigate it and spread it over time. The numbers I gave you are what gives us some confidence in that statement. We'll be able to mitigate this and spread it over time.
That makes sense. Then, as a follow-up, you had mentioned on the last call the potential of recontracting at higher negotiated rates on EPNG, NGPL, and I believe your interstate pipes. Can we get an update on that? Would you be willing to share roughly what share of your volumes out of the Permian come up for negotiated rate recontracting over the next couple years?
Yeah. It's an idea, but quantification of that.
Yeah. It's hard to put a number on all of that. I think we're talking about $25 million, somewhere in that range, year-over-year of size.
Okay.
At work.
Great. That's helpful. Thank you.
Okay, our next question comes from Shneur Gershuni with UBS.
Hi, good afternoon, everyone. Maybe just to follow up on that 501G question. I just wonder if you can clarify a couple things. It seems right now that request is effectively informational at this point right now, and it's not actionable. Then, as part of the discussion on it, can you speculate on the purpose of the FERC using 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 of another filing out there for a pipeline that's asking for routine ROEs. Just wondering if you can sort of help align on that.
On the first, we view it as an informational filing. We view it as, frankly, a bad informational filing. There are a number of things it overlooks, including negotiated rates and other things that I mentioned. It uses a very old mitigated ROE, uses a cap structure that we don't think is appropriate. It forces information into a particular template that we don't think is consistent with the way the commission has done ratemaking in the past. In the course of all this, we'll get an opportunity, I'm sure, to point that out. 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.
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, and particularly in light of past commission policy and precedence. We think they're informational and not very much information. On FERC's 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 tax cuts pathway last year found their way to customers. In a competitive market, they do find their way, one way or another, to customers. We are not, again, a protected franchise regulated monopoly utility in the same way that some electric utilities, for example, some distribution companies are.
I think that using a similar approach, if you will, to 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. How do you envision those dollars being spent? Are we looking at some more large-scale projects, like an Express Pipeline? Or do you see it more of a series of $100 million to $200 million type projects? If so, where do you see the capital going to spend?
I think it'll be primarily directed to natural gas. 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. If you look at the fundamentals that Tim took you through, we would expect to see
Not only to increase 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 much big ones we'll look at versus a collection of smaller $200 million ones. We think we'll have good opportunities there.
Okay. Thank you very much. I'll get back to you, too.
Thank you. The next question comes from Jeremy Tonet with J.P. Morgan.
Hi, good afternoon. Just wanted to turn to the business a little bit here, seems like you have some things kind of moving in your favor as far as growth is concerned in natural gas business. You noticed the Bakken, Haynesville, Eagle Ford activity there, just wanted to touch a bit more on those areas. It seems like competition is quite wide, basis differentials have come up recently there. I'm wondering what that could mean to you guys as far as possibly expanding Double H or other infrastructure you might have. The Haynesville seems like resurgence of activity there. GP might be looking to do more. Have you had any conversations with guys like that are putting more capital to work? Then the Eagle Ford as well, it seems like it's kind of coming off the trough.
I was 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. I think in all three areas that you touched on, there's going to be opportunities. 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 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. 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. There'll be a point, certainly in pockets of the Haynesville, where we'll need to expand the system to take additional volume there. The Eagle Ford, I think largely we'll be filling our existing capacity.
There may be pockets of opportunity to expand there, particularly on the NGL side, which we'll take a look at as well. Clearly the value of our existing capacity is going up to the extent it's not already sold under long-term contracts. As those deals come up for renewal, we should do better in those areas. The prospects look good.
Got you. Thanks for that. I was going to ask about Permian brownfield deep oil mentioned opportunities, in the interest of not getting in trouble, I'll hop back in the queue.
Thank you. The next participant comes from Gene with Tudor, Pickering, Holt & Co.
Good afternoon. As you evaluate next steps on KML, is there any consideration of potential asset inclusion from the KMI level, specifically maybe the U.S. portion of Cochin? I guess, to touch on that, how does that fit into the Kinder Network KML were to exit the portfolio?
Cochin does not commercially or otherwise really divide at the border, it makes sense for it to end up on one side or the other. 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. That's nobody worked out that you have your finger on somebody that you have to resolve as part of it. It is an attractive asset. It runs full. It's under contract. It's purely full. It's under long-term contract, and it is providing a valuable service to our customers. I think it's valuable whichever side it ends up on.
Got it. That's helpful. I guess this is a follow-up. You mentioned on UMTP, kind of moving away from that project. I think you filed for abandonment on the PGP 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? Just any thoughts on commercial appetite for more Northeast to Gulf Coast capacity given where spreads have moved to?
We're not pursuing that project any further. We reflect that in our accounting for the quarter, et cetera. Part of the reason for that is we haven't gotten the customer sign-up on UMTP. 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 PTP in order to take the Marcellus and Utica gas south to where the market is now growing. It's a function of a lack of opportunity on the one hand, thankfully, the emergence of a very good opportunity on the other.
No real downside in appetite for southbound capacity even with bases being a bit tighter?
Yeah, 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. It's not brand new, greenfield, long-haul pipe. It's one of the last, if not the last, pipeline reversal projects. We think it is attractive in this market right now. Clearly, it's attractive compared to greenfield cost, and it's a net pocket of capacity. It doesn't require Bcf or 2 Bcf of commitment. It's more in the couple-a-day range. I think pretty actionable. Yeah. Good grade.
Got it. Thank you very much.
Thank you. The next question comes from Cyril Younes with Credit Suisse.
Good afternoon.
Hey, good afternoon. Thanks for the questions. Just want to go back to something you said earlier. Steve, surrounding 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, some of the issues that you had. Curious if you can give a little more detail around what exactly is driving your ability to do that. Ultimately what I'm getting at is how much of that is really sustainable to 2019 versus being just commodity strength based?
Oh, yeah. As Kim said, it's the uptick that we've had in natural gas volumes and utilization. One important point of note there is that the volumes on both the supply and demand side are growing faster even in Texas. We're seeing that 14% number that we're up is 20%. That's 20% on sales, and that's 25% on transport in the Texas intrastate market, which is a good thing. That's not a FERC-regulated position for us. Really there's good tailwinds there, and they're expected to continue. We've had growth like we've never seen, at least in a 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. 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 is moved on our system. 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. I think 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. Not sure if this is where Jeremy was going, but I'll pick up that Permian question. Just in terms of the potential need for a third gas pipe out of there, I think Steve talked about it on the last call, maybe being kind of a toss-up between either expanding a current pipe or if you add a third one. I think you said it's unclear last time. Just wondering if 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 is needed? Or do you feel good at maybe 2.7 Bcf a day on the Permian?
Yeah. The 2.7, I'll start with that. 2.7 Bcf on the Permian Highway would take almost 48 inch. We went to 42 inch because the supply chain for the pipe for 42 inch was much more secure. As Kim said, we locked in our pipe there, we took care of that risk. 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, they're 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. We think there's a third pipeline.
Maybe it's two or three years out as opposed to right now, we think there'll be a third pipeline, if not more after that.
Right.
I think that's right.
Okay. Appreciate the thought. 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 in anticipation of the 4 Bcf a day of incremental supply from your two large projects as we look into 2020.
Yeah. Well, very good point. If you look at our Texas system today, it's about a 5 Bcf a day system. With these two projects that Tom's team has put together here really in a very short period of time, we're bringing another 4 Bcf to that system. Those projects come with certain downstream lease arrangements or pipeline capacity arrangements on our existing Texas intrastate system. 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. The whole Texas market and our position in it is in very good shape right now and has a very fine outlook.
Helpful. Thanks. Just to follow up, curious what areas in terms of the additions to the pipeline outside of PHP, where you're seeing growth project additions?
Okay. We touched on one with the Tennessee pipeline reversal. We have additional projects serving LNG coming out that we are looking at on NGPL as well as the 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 involve a whole bunch of capital, but all that capacity is very valuable, certainly in the near term, so we can monetize that. To the earlier question, the G&P part of our business. The Bakken is booming again, and it is bottlenecked on our system. So we are investing capital to debottleneck that system and get our customers' product to market.
Tom alluded to, in the Haynesville, in the Eagle Ford, we've got room on our existing systems to take additional volume with potentially small debottlenecking, not capital intensive expansion. We'll get some volume, not for free, but for nearly free as it grows in the Haynesville. More in the Bakken than in the other two basins.
That's great. Thank you guys very much. Appreciate it.
Our next question comes from Keith Stanley with Wolfe Research.
Hi. Good afternoon. On the KML strategic review process, is there any reason you'd want to wait until the Trans Mountain special payment in early January or the shareholder vote in November before you make a decision on KML, or are those two items not connected at all?
We don't necessarily have to wait on that for a decision. We can work our process even starting now.
Okay. One follow-up just on the backlog, maybe $800 million in the quarter. How much of that is Permian Highway and what ownership interest are you assuming there?
Yeah. We were conservative, I believe, on the ownership interest. We kind of get assuming a full exercise of the options that the large shippers on the system have to take extra pieces, net 600, something like that. It was most of the addition to the backlog in gas.
Your next question comes from Thomas Abrams with Morgan Stanley.
Thanks. This Bakken residual gas idea, that was somehow got to have to go somewhere, but where? Where does it go? It try to get to the West Coast and meet LNG development there? Would it get to the Gulf Coast and fight past all that Permian associated gas?
Considering both.
How are you thinking about that?
Yeah, I think we're considering both options, I think more likely down to the Rockies area. We're considering both.
On the New York terminaling, still have some headwinds there on Staten Island, 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 come out and improve?
We're 100% utilized in the two New Jersey facilities at Carteret and at Perth Amboy. Actually, we saw an improvement on a quarter-to-quarter basis at Staten Island. We had 948,000 barrels last quarter, and we're up to 1.7 million now. We've got a good short-term plan to keep our head above water over there. The spill tax is still a huge issue, though. We're looking at strategic options for the facility long-term, which could include looking at alternative uses for the site.
Great. Thanks.
Our next question comes from Michael Latona with Goldman Sachs.
Hey, guys. Thanks for taking my question. Real quick, it's a little bit of a two for one. How are you thinking about project returns on Elba Island now versus original expectations? 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 a real project for you guys?
Okay. First on Elba. 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 curve has actually improved since that time, and we're still looking at a double-digit after-tax unlevered return. 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 three important parties here. There's us as the project developer and manager, et cetera. There is Shell, who is the provider of the units that are being provided to do the liquefaction. That's not, if you will, on us. That's something that Shell is providing.
We entered into an EPC contract with our EPC contractor. 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. 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.
Yeah. How do you think of that next step for Gulf LNG outside of the obvious with the FERC EIS process?
Yeah. As you just said, we did get some information on Gulf LNG that the commission actually gave a timeframe on the EIS and on the expected order date for the Section 7(c), 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. That includes not just marketing the facility, but potentially looking at a JV opportunity or other things.
Got it. Thank you, guys. Much appreciated.
Our next comes from Robert Catellier with CIBC Capital Markets.
Hey, Robert.
Good afternoon, everyone. I was just hoping to make sure I understand the Trans Mountain recall rights on some of the tanks at KML. If TMX were completed, I understand they have the right to recall tanks, and I think the original expectation was they could recall or likely recall two. My question is that still the expectation, and what is the impact on EBITDA at TMO as a going concern if that in fact happens?
Yeah, that's still the expectation. The two tanks is still the expectation the time that the project actually comes into play. That's obviously, in time, the project comes into play. They've also got the ability to give two years of notice to recall additional tanks to the extent that they can't meet their existing regulated requirements after they give notice. You don't anticipate that happening.
The quantification? In quantity, give us some color on the impact.
Yeah.
Yeah.
It depends upon what we actually have in terms of third-party business out there. So it would depend on the specific situation.
Okay. Similar question then on the expiration of contracts with the Edmonton rail terminal. I think there's an important contract that expires in 2020 with favorable renewal rates for the customer. What sort of color can you provide us on the impact that might have?
It switches to a hard plus contract, we will have a management fee in place at that time. We looked at this as it would be paid off in its initial term. In April of 2020, that contract switches over to just a management contract.
Is that a material impact then?
Right now, it looks like it's about $45 million.
Yeah. Thank you.
Next question comes from Robert Kwan with RBC Capital Markets.
Great, thank you.
Robert.
Hi. Just wanted to confirm with the numbers Dax gave, both the $4 billion on the dividend and then just over $300 million on the tax, just to make sure there's no other major inflows or outflows. That's pretty much when you see that, even including debt and the cash, is that fair?
Yeah, that's about right. Pro forma for the cash taxes of just over $300 million, the dividend of about $4 billion. That's right.
Okay. Just on the $50 million-$55 million in the fourth quarter. That pretty much includes all of the phase 2 of Base Line Terminal. You get that, keeps that the full quarter of the tank lease, at least the rail contract highlighted as part of this quarter. Does it also incorporate what you think the ongoing G&A run rate is, and are there any kind of future factors?
Yeah, no, it does. I think that's a pretty clean sort of going forward run rate. The last baseline tank came in, I'd say the last one came into the fourth quarter, just after the beginning of the fourth quarter. It's got a pretty good run rate going forward for the next year going forward.
Okay. Thank you very much.
Our next question comes from Shneur Gershuni with GS.
Hello, again.
Hey, I'm following the rules. I had seven questions prepared. I just wanted to clarify something that came up earlier, about total interstate revenues and 30% of that with respect to an adverse situation. I was just wondering if you can sort of walk us through that again.
Yeah. 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. By definition, it's primarily the shippers who are paying max rates, that it's the revenue associated with that could potentially be affected, could have some reduction in it. Not elimination, but some reduction in it. Okay? Negotiated rates, discounted rates would not be affected or 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. That's very small.
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 were trying to convey.
Okay. Just to clarify, basically what you're saying is 30% of your revenues. 30% is subject to max rate, and that's where you would then see an adjustment. It's not a 30% hit to the revenues, it would be far less than that.
Correct. Very important. It's 30% of the regulated interstate revenues that we're talking about. 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%, or something like that. That's what we've been able to achieve in other settlements. It's not the whole 30%. Thank you for that clarification. Not the whole 30%.
Okay. Thank you. That clarifies. Much appreciated. As a second follow-up question, you sort of teased 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. Is it fair to assume a similar playbook in terms of buybacks if you were to get proceeds from a sale?
First of all, what we were talking about with respect to use of proceeds would apply 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 a share of buybacks. That's our current thinking. On the KML assets, we think they're great assets. 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. The Vancouver Wharves asset is a very good asset. The Cochin Pipeline is just a very good asset. 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.
We do think it tends to be a bit of a seller's market for these assets.
The Oklahoma assets or any other assets?
Yeah. Oklahoma, as you 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, Oklahoma may be one of those, we could look to monetize them. Beyond that, I'm not commenting on specific processes or specific assets.
Everything here at the price, at the right price. The whole driver is what's going to create the most shareholder value. That's it. If we find those opportunities on pieces of our asset base, as we have in the past with some of our bulk facilities, we'll certainly evaluate those.
Perfect. Much appreciated. Thank you.
Thank you. Next up is from Jeremy Tonet at J.P. Morgan.
Hey, Jeremy.
Hi. With that Permian asset base to follow my team. I think in the past, you guys have talked about 2 Bcf a day growth capacity that could be added between Texas Interstate, EPNG, and NGPL. You talked about the downstream connectivity that would be employed, I guess, based on these new pipes that you're building. Is that 2 Bcf number, is that specific to that? 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 puck recently and deep breath is ever more challenged.
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's anywhere from a Bcf to 2 Bcf of potential projects to be done at much higher cost, which really aren't supported by the market today. If it were deployed, it would be post PHP time horizon. We're certainly looking at those smaller components of those projects that may still make economic sense. Really the downstream side of it is really what Steve talked about earlier, and that is clearly a lot of the demand for this four Bcf is driven by Mexico exports, LNG exports, as well as growth along the Texas Gulf Coast and the petrochemical market. We will look for opportunities to expand and extend our Texas intrastate network to support those growth activities.
just to be clear, the one to two Bcf that you talked about, that's really downstream of the Waha and that last mile getting to market. That's not more getting out of Waha. Is that the right way to think about it?
It's more Permian happening.
That is getting out of Waha?
Yeah.
Okay. That's more.
Permian to Waha or other sites to the north, potentially up on the north main line out of El Paso or up into the Rockies via TransCanada.
Got it.
Those are, again, for the bigger quantities anyway, probably not supported by market prices today. We're certainly looking at smaller pieces of that, subsets of that, as we can get those done. The market may support them in the future as Permian continues to grow and as the big pieces of pipe capacity we built get filled up.
Got you. Thanks. Just to follow up real quick on what you were talking about Double H before. If you're going to expand that, how long would that take to do? Is that kind of a pumping thing that could be done within a year? Is this longer-term project in nature?
On Double H?
Yeah.
There's a small remaining expansion to be done. That's pump station inside.
That's like a couple quarters you could see that commitment?
Yeah, we could do that within six to eight months.
Got you. Great. Thanks. Thanks so much for taking all my questions. I'll step out.
Thank you. Now 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.