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Regarding our growth prospects, I believe we can develop good high return infrastructure projects in the range of $2 billion to $3 billion per year. In short, we are demonstrating that we can generate strong and growing cash flow and employ that cash to benefit our shareholders. That is the essence of our long-term financial strategy at Kinder Morgan.

Now, like many of you on this call, I'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.

Steven Kean -- Chief Executive Officer

Okay, thank you. As usual, we'll be covering both KMI and KML on this afternoon's call. I must start with a high-level update and an outlook on KMI, then turn it over to our President, Kim Dang, to give you the update on segment performance. David Michels, KMI's CFO, will take you through the numbers. Then, I'll give you a high-level update on KML and we'll take you through the numbers and a couple of other topics there. Then, we'll answer your questions on both companies.

We had a pivotal quarter on KMI and KML. Highlight about closing early in our schedule of our transaction to sell the Trans Mountain pipeline to the Government of Canada, which removed considerable uncertainty while providing significant value to KML and KMI shareholders.

With respect to KMI, we are having a very strong year. We are well above plan for the first 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 out performance notwithstanding the absence of earnings contribution from Trans Mountain, the delay in the completion of Elba, and the termination of a contract in our Gulf LNG joint venture, none of which was assumed when we put the budget together.

What that tells you is that our underlying business is very strong. We also made our final investment decision along with our partner EagleClaw on the Permian Highway natural gas pipeline project in the third quarter. We have now sold out all of the available capacity, 2 Bcf a day under long-term contracts, as we projected when we FID the project.

We have also already secured our pipe supply, which is a big mitigation of risk in the current rate environment. We revised our debt-to-EBITDA target down from 5.0 to approximately 4.5 times with the KML announcement regarding the use of proceeds and KMI's announcement that we will apply KMI share approximately $2 billion to debt reduction. We are achieving our leverage target. We are having a very good year, strong financial performance, tremendous progress in the balance sheet, 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; continue executing on our project backlog, particularly the completion of Elba and the advancement of Gulf Coast Express and PHP; continue maximizing the benefit of our unparalleled gas network; seek to add attractive return projects to our backlog as we did this quarter with the addition of PHP; continue returning value to our shareholders with a growing and well covered dividend.

And with respect to questions on KML and possible transaction there, as we've said previously, following the sale of Trans Mountain, KML is evaluating all options to maximize value to its shareholders. The original purpose of KML was to hold a strong set of midstream assets and to use the cash flows from those assets and the balance sheet to provide a self-funding mechanism for the Trans Mountain expansion. Clearly, that purpose no longer exists. The good news for KML shareholders is that there are good options available, which include continuing to operate that strong set of remaining midstream assets as a stand-alone enterprise. Simply put, we like the assets and we don't have to sell them.

But among the other potential outcomes is a strategic combination with another company, including possibly KMI. We will be exploring and evaluating all of the available options with the KML Board in the coming months, because strategic transactions are difficult to forecast we will likely not have further updates on this until we have something more definitive to say. But as we've consistently demonstrated, our focus will be on maximizing KML shareholder value.

The possibility though not a certainty that KML may enter into a strategic transaction, including an outright sale, means that KMI could have another use of proceeds decision. A few points on that. We have consistently said to KMI that we would evaluate the use of available cash to fund attractive projects, return value to KMI shareholders in the form of buybacks or increasing dividend.

We have also updated our leverage target to around 4.5 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 to fund the equity portion of attractive growth projects that we may add at 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.

Kimberly Allen Dang -- President

Okay. 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 US 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 4 Bcf a day, that's 14%.

If you look at power demand on our system, it was up in the quarter, up 1 Bcf or 16%. In the overall power market, natural gas now comprises approximately 38% of total generation, up from 36% in the third quarter of 2017. Exports to Mexico were up 375 million cubic feet a day on our pipes, or 13%, versus the third quarter of 2017. With total exports to Mexico on our system of just under 3.3 Bcf a day.

Overall, the higher utilization of our systems, a lot of which came without the need to spend significant capital, resulted in nice bottom line growth in the quarter and longer-term will drive expansion opportunities as our pipes reach capacity.

On the supply side, we're also seeing nice volume growth. Our gas and crude gathering volumes were up 15% -- were up 20%, sorry, and 15%, respectively, driven by higher production in the Bakken and the Haynesville and the Eagle Ford.

In the Haynesville, our gathering volumes is doubled in the quarter versus 2017.

On the project side, in natural gas, we had a few noteworthy developments. Steve gave you the update on PHP. On Gulf Coast Express, we've secured approximately 80% of the right of way. Construction is starting this month and we remain on target for October 2019 in service.

On our Elba Liquefaction Project, we now anticipate that it will be in service in the first quarter of 2019. Although the delay is impacting our DCF versus budget, the natural gas in that segment is still expected to see this 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 second quarter of 2017. Backlog volumes were up 4% versus last year and they are 6% above our plan, year-to-date, as we continue to find ways to extend the life of this field.

Currently, we're evaluating transitions on opportunities as well as of unit opportunities that are adjacent to SACROC.

Tall Cotton volumes were up versus last year, but they are below our budget. Our net realized crude price is relatively flat for the quarter despite a higher WTI price. The WTI hedges we have in place as well as the increase in the Mid-Cush differential offset the increase in WTI. For the balance of this year and for 2019, we've substantially hedged the Mid-Cush differential.

Our terminals business, we benefited from liquids expansion in our -- in Houston Ship Channel, in Edmonton, and the new Jones Act tankers that came on in 2017 that we got a full -- that we are getting a full-year benefits 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 tax, making facilities in New Jersey a more economic option for our customers, and a number of other factors which include non-core asset divestitures, contract expirations at our Edmonton rail facility, and higher fuel and labor costs in our steel business.

Bulk tonnage in the quarter was actually up 5%, primarily driven by coal and pet coke, although you don't see much benefit in this result for given the way our contracts are structured, the GAAP revenue recognition rules, and to a lesser extent some pricing changes. Liquids utilization was down 2%, primarily due to tanks out of service for API inspection and the Staten Island facility, I mentioned a moment ago.

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

Crude and condensate volumes were up 13% and that was due to increased volumes on our pipelines in the Bakken, which drove higher contributions from Double H. And in the Eagle Ford, the impact of those volumes though is largely offset by lower pricing.

And, with that, I'll turn it over to David Michels, our CFO, to go through the numbers.

David Michels -- Vice President and Chief Financial Officer

All right. Thanks, Kim. Today, we're declaring a dividend of $0.20 per share, which is consistent with our 2018 budget and with the plan that we laid out for investors in July 2017 that annualized $0.80 per share is what we expect to declare for the full year 2018 and would represent a 60% increase (technical difficulty) $0.50 per share that we declared in 2017. Once again, despite that very robust dividend increase, we expect to generate distributable cash flow of more than 2.5 times our dividend level.

As you've already heard, KMI had a great -- another great quarter. Our performance was above budget and above last year's third quarter. As Steve mentioned, we expect to beat our budget on a full year basis for all DCF, EBITDA and leverage.

Now, I'll walk you through the GAAP financials, distributable cash flow and the balance sheet. Earnings, on the earnings page, revenues are up $236 million or 7% from the third quarter 2017. Operating costs are down $453 million, or 18%. However, that does include the gains recorded on the Trans Mountain sale. Excluding certain items, which Trans Mountain is the largest, operating costs would actually be up by 162 million, or 7%, which is consistent with the growth in revenues.

Net income for the quarter is $693 million or $0.31 per share, which is an increase of $359 million, $0.16 per share versus the third quarter of 2017. Much of that increase is also attributable to the gain from the Trans Mountain sale.

Looking at earnings on an adjusted basis or looking at adjusted earnings (technical difficulty) take out certain items, the $693 million would be $469 million, which is $141 million, or 43% higher than adjusted earnings in the third quarter of 2017. Testing -- our adjusted earnings per share is $0.21 or $0.06 higher than the prior period.

Moving onto distributable cash flow, DCF per share is $0.49, which is $0.02 up from the third quarter of 2017, 4% increase. That is yet another very nice quarterly performance for 2018 and was (technical difficulty) by strong growth in our natural gas segment.

Natural gas was up $81 million or 9%. And that benefited -- that segment benefited from having 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.

Our EPNG and NGPL pipelines had greater contributions driven from -- by Permian supply growth. Our Tennessee Gas Pipeline was up due to expansion projects, which were placed in service and our CIG pipeline experienced strong growth due to greater DJ Basin production. Partially offsetting those items were lower contribution from our Gulf LNG, that's probably due to a contract termination.

CO2 segment was up $16 million from last year, driven by NGL prices and greater volume, and Kinder Morgan Canada segment was down 18 million dollar or 36% due to the sale of Trans Mountain and the loss of one month of contracts during the quarter.

G&A(ph)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 was $10 million higher, driven by higher interest rates, which will offset the benefit from a lower debt balance, as well as some interest 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 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 million, G&A costs were down $16 million. Interest expense was up $10 million, cash taxes were up $5 million. Other items, driven by an increased pension contribution were a reduction to DCF of $9 million and sustaining CapEx was higher by $38 million, that adds up to $43 million, which explains the main variances in the $38 million period over period change in DCF.

2018 remains on track to be a very good year for Kinder Morgan. We expect to exceed our budgeted financial targets for the year, driven by natural gas and CO2 segments, lower G&A, cash taxes and sustaining capital expenditures, partially offset by reduced contributions from Kinder Morgan Canada as a result of the Trans Mountain sale, as well as lower contributions from our terminal segment due to lower leased capacity in the Northeast and lower than expected Gulf(ph)throughput.

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

Moving on to the balance sheet. We expect -- we ended the quarter at 4.6 times net debt-to-EBITDA. Just to repeat that, we expect -- we ended the quarter at 4.6 times net debt-to-EBITDA, so very important milestone, a nice improvement from the 4.9 times last quarter and 5.1 times at year end 2017. The current forecast also has this pending year at 4.6 times. 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 the debt.

In the meantime, KMI consolidates all of those cash proceeds, including the amount that the public KML shareholders will receive. Therefore, as you can see on the balance sheet page, we subtract it 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 of 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 the reconcile at 2.1 for the quarter, we generated $1.093 billion of distributable cash flow. We had growth capital and contributions to JVs of $715 million. We paid dividends of $444 million. We received the Trans Mountain sale proceeds of $3.391 billion. We took out the KML public shareholders portion of those proceeds of 919 and we had a working capital use of $337 million, primarily as a result of the EPNG refund payments and that reconciles to our $2.069 million reduction in net debt for the quarter.

For the full year, our year-to-date reconciliation, we generated $3.457 billion of distributable cash flow. We had growth CapEx and contributions to JVs of $1.981 billion. We paid dividends of $1.163 billion. We repurchased $250 million of shares and we received the Trans Mountain sale proceeds of 3.391. We excluded the KML public shareholders portion of that of 919 and we had a working capital use of $455 million year-to-date, that also includes the EPNG refunds as well as interest payments and that reconciles to the $2.08 billion reduction in net debt year-to-date.

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

Steven Kean -- Chief Executive Officer

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 CAD11.40 per KML share, and on top of that KML shareholders have a strong set of remaining midstream assets and then entity with little or no debt and with opportunities for investment and 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.

Dax Sanders -- Chief Financial Officer

Thanks, Steve. Before I get into the results, I do want to update you on a couple of general items. First is, both Steve and the press release mentioned, we anticipate distributing the net proceeds associated with the sale on January 3, 2019, following shareholder votes on November 29th. More on the amount to be distributed in a second.

Specifically , the shareholder vote is to approve two things. First, a reduction in stated capital, which is in Alberta Corporate Law concept and with the reduction in stated capital, we will ensure that our distributions go to segue(ph)with Alberta Corporate Law. The overall concept of the stated capital reduction is more fully described in the proxy. Second approval is to affect a three-for-one reverse split post-payment of the special dividend. As a reminder, the vote is subject to a two-thirds majority of the outstanding shareholders in 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 5 of the 6 remaining tanks in service during Q3 and the last tank in service just after the quarter end. Overall, 10 of the 12 tanks were placed in the service on time or only. As of the end of Q3, we have spent approximately CAD342 million of our share with approximately CAD31 million remaining on the total spend of approximately CAD373 million. The CAD373 million compares to an original estimate of 398 million and, as I mentioned last quarter, is a result of cost savings on the project.

Now moving toward the results. Today, the KML Board declared a Board -- declared a dividend for the third quarter of CAD0.1625 per restricted voting share or CAD0.65 annualized, which is consistent with previous guidance. Earnings per restricted voting share for the third quarter of 2018 are CAD0.05 from continuing operations and CAD3.78 from discontinued ops and both are derived from approximately $1.35 billion of net income, which is up approximately $1.3 billion versus the same quarter in 2017.

Obviously, the big driver there was a large gain on the sale of the Trans Mountain pipeline. So, let me focus for a minute on what's driving the CAD12.4 million increase in income from continuing operations. Stronger revenue associated with the baseline tank and term loan coming online and interest income associated with the proceeds from Trans Mountain sale are the big drivers.

Adjusted earnings, which excludes certain items, were approximately CAD44 million compared to approximately CAD42 million from the same quarter in 2017. Of course, the big certain item in the quarter was a gain on the sale of Trans Mountain.

Though DCF for the quarter, which is not adjusted for discontinued ops, is CAD80.6 million, which is up CAD3.4 million for the comparable period in 2017 and within a CAD1 million of our budget, that provides coverage of approximately CAD7 million and reflects a DCF payout ratio of approximately 71%.

Looking at the components of the DCF variance, segment EBITDA before certain items is of CAD8.4 million compared to Q3 2017 with the pipeline segment up approximately CAD8.2 million and the terminal segment (technical difficulty) flat. The pipeline segment was lower, primarily due to the Trans Mountain assets going away and that was approximately CAD15 million negative. It was offset by the non-recurrence of an unrealized FX loss from some intercompany notes that were on place in 2017 and lower O&M and Cochin 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 tanking terminal project coming into service and higher contract rates and renewals at the North 40 terminal in Edmonton South terminals 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 Edmonton South facility to the government.

G&A is favorable by CAD2.5 million, due primarily to the removal of the Trans Mountain G&A term line. Interest is favorable by approximately CAD11 million, due to the interest on the Trans Mountain proceeds and lower interest expense. The cash tax line item is essentially flat. Preferred dividends were up CAD5.2 million, given Q3 2018 had both tranches outstanding for the fourth quarter.

Sustaining capital was favorable approximately CAD3.8 million compared to 2017 with the exclusion of Trans Mountain being the main driver, but augmented by timing on spending in the terminals segment.

Looking forward, as we mentioned in the release, we expect to generate CAD50 million to CAD55 million of adjusted EBITDA for the fourth quarter with almost a full quarter of the baseline tanks in service during the fourth quarter. And also and consistent with past practice, as we prepare our 2019 budget for KML, we will communicate that, which will provide more color on the earnings power of the residual assets going forward.

With that, I'll move to the balance sheet comparing year end 2017 to 9/30, and my comments will focus only on the line items related to the retained assets and not the assets and liabilities held for sale. Cash increased approximately CAD4.239 billion with CAD4.35 million(ph), and there are lot of moving pieces in the change associated with the Trans Mountain, with Trans Mountain have stemmed(ph)from the CapEx spend on behalf of the government, the government credit facility and other purchase price adjustments such that I'm not going to take you through that on this call, but if you want more detail feel free to give us a call.

Generally, the increase is a CAD4.426 billion of net proceeds received, plus DCF generated less expansion CapEx plus distributions paid net of the group(ph)unless the pay-off of that 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 approximate 11.40 per KML share, will be approximately CAD4 billion and then we'll pay capital gains tax associated with the transaction of just over CAD300 million in Q1 2019.

Other current assets increased approximately CAD19.5 million, primarily due to an increase in several items and accounts receivable were the largest component of that coming from a billing to Imperial related to the Imperial JV.

Net PP&E decreased by CAD3 million as a result of depreciation in excess of net assets placed in the service. Deferred charges and other assets decreased by approximately CAD64 million, which is a result of 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 CAD3,021 million, primarily due to the taxes payable on the Trans Mountain sale. Other long-term liabilities decreased by CAD283 million, primarily as a result of a deferred tax liability released as a result of the gain on the sale Trans Mountain. Also note, we ended the quarter without any outstanding debt.

And, with that, I'll turn it back to Steve.

Steven Kean -- Chief Executive Officer

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

And, with that, we'll turn it over to operator to come back on and start the questions.

Questions and Answers:

Operator

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

Jean Ann Salisbury -- Sanford C. Bernstein & Co. -- Analyst

Hey. How should be book into the potential downside for KMI of the 501-G outcomes? And do you have any internal projections that you can share of what EBITDA loss could be in a worst-case?

Steven Kean -- Chief Executive Officer

Yeah. It's very hard to project, because the outcome is highly uncertain. But I'll try to give you some parameters. We've said in the past that looking at the tax effect alone, it's about $100 million across our interstate assets. Beyond that, it's very difficult to predict and you understand -- you know what the mitigating factors are. We have rate moratorium in place on many of our systems. We have negotiated rates for many of our transactions in the interstate business. We have discounted rates in effect. Not all of our gas segment is interstate, some of it is our intrastate business in Texas, which were obviously growing. And not all of our regulated intrastate assets earned their cost of service, OK. So if you put that all together and you roll off several years forward and you are really just talking about the max rate revenues on our interstate business that are subject to some adjustment.

If the max tariff rate comes down, which is what rate actions do, they would be subject to adjustment and that amounts to about 30%, which by the way, to us anyway, underscores the lack of foundation for what the Commission is doing here. If you look at the action of their taking, they are treating interstate natural gas pipelines as if they were regulated franchise monopoly utilities, that hasn't been the case since the 1970s.

Over the last 30 years, the Commission has carefully crafted a competitive market through various administrations, one pro-competitive rule making after another in order to create competition between pipelines. We operate in a competitive market, not in the franchise service territory. We expect to bring that in other rate making arguments to bear as we go through the five LNG process. So thanks for giving me a chance to stay on the result.

Kimberly Allen Dang -- President

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

Jean Ann Salisbury -- Sanford C. Bernstein & Co. -- Analyst

Yeah. That make sense. And would it be fair to think about it, maybe as a multiple of the $100 million going away in a worst-case or --

Steven Kean -- Chief Executive Officer

Yeah. Again, very hard to project, because I think there are quite a few hands to play here as we work through this process and we work with our customers and we work with our regulator and we actively mitigated. 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 will be able to mitigate this and spread it overtime.

Jean Ann Salisbury -- Sanford C. Bernstein & Co. -- Analyst

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

Steven Kean -- Chief Executive Officer

Yeah, it's not be able to quantification of that.

David Michels -- Vice President and Chief Financial Officer

Yeah. I mean it's too hard to put a number on all of that. I mean, I think we're talking about $25 million or somewhere in that range, kind of year-over-year upside (multiple speakers).

Operator

Thank you. Our next question comes from Shneur Gershuni with UBS.

Shneur Gershuni -- UBS Investment Bank -- Analyst

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

Steven Kean -- Chief Executive Officer

Okay. On the first, we view it as an informational filing. And we view it as frankly a bad informational filing. There are a number of things that it overlooks, including the negotiated rates and other things that actually uses a very old litigated ROE, uses a cap structure that we don't think is appropriate and it kind of forces -- it forces information into a particular template that we don't think is consistent with the way Commission, the Commission has done rate making in the past. And so, in the course of all this, we will get an opportunity, I'm sure, to point that out. But what I would submit that you all are to be thinking about is, you're going to get -- as many of you have written, these numbers are going to be uninformative, so as these 501-Gs rollout, you need to take that into account as you're looking at them, because they have flaws in our view in particularly in light of past Commission policy and precedence. So, we think they're informational and not very much information.

On the FERC's purpose, I won't speak for them, but I think it was fairly clear from the process leading up to this that it was based on a desire to make sure that the benefits of the income that the Tax Cuts passed late last year bound 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 an appropriate. We'll continue to make that point to the Commission.

Shneur Gershuni -- UBS Investment Bank -- Analyst

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

Steven Kean -- Chief Executive Officer

I think it will be primarily directed to natural gas. We put -- we grew the backlog quarter-to-quarter $200 million after putting several projects in the service and that was largely due to a net addition to the backlog of $600 million of the natural gas segment. And if you look at the fundamentals that Kim took you through, we would expect to see not only the increased utilization of the existing system, but the opportunity to put more capital to work and we're looking at what those projects would be. It's a little hard to say how many big ones will there be versus a collection of smaller multi $100 million ones, but we think we'll have good opportunities there.

Operator

Thank you. Our Next comes from Jeremy Tonet with JP Morgan.

Steven Kean -- Chief Executive Officer

Hey, Jeremy.

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

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

Steven Kean -- Chief Executive Officer

Jeremy, that feels like a lot more than one question.

(technical difficulty) so I'm going to -- 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 -- and I will not speak too much on the crude side, but there is -- there are some projects that we're looking out to take additional volumes, south to Cushing, potentially on the crude side, there's clearly a need for additional residue solutions out of the Bakken. So I think that's an area that we're exploring as well. Clearly, there is going to be more expansion capital deployed in the Haynesville as we go up our existing capacity, I think there will be a point certainly in pockets of the Haynesville where we'll need to expand the system to take additional volumes there.

And then the Eagle Ford, I think, largely will be billing 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 haul term contracts as those deals come up for renewal, we should do better in those areas, so I think the prospects look good.

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

I was going to ask about Permian brownfield debottlenecking opportunities, but in the interest of not getting in trouble, I'll hop back in the queue.

Operator

Thank you. And our next questions comes from Colton Bean with Tudor, Pickering, Holt & Co.

Colton Westbrooke Bean -- Tudor, Pickering, Holt & Co. -- Analyst

As we're evaluating next steps on KML, is there any consideration of potential asset inclusion from the KMI level, specifically -- maybe the US portion of Cochin. And to touch on that, how does that fit into the Kinder network if KML were to exit the portfolio?

Steven Kean -- Chief Executive Officer

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

Colton Westbrooke Bean -- Tudor, Pickering, Holt & Co. -- Analyst

And I guess, just as a follow-up, so you mentioned on UMTP kind of moving away from that project. I think you had filed for abandonment on the TGP portion there in 2015. Given the abandonment filing, is there anything incremental you 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 would move to?

Steven Kean -- Chief Executive Officer

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

Colton Westbrooke Bean -- Tudor, Pickering, Holt & Co. -- Analyst

Okay. And so no real downtick in appetite for South bound capacity even with base -- this being a bit tighter?

Steven Kean -- Chief Executive Officer

Yeah. For this capacity, which is -- I don't know if it's the last one, but it's among the few remaining opportunities to take existing North bound 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 marketplace. Clearly, it's attractive compared to greenfield costs and that's -- it's a nice pocket of capacity. It doesn't require a Bcf or 2 Bcf of commitment, it's more on the (technical difficulty) day range. So, I think pretty actionable and so good rate.

Operator

Thank you. Our next question comes from Spiro Dounis with Credit Suisse.

Spiro Dounis -- Credit Suisse -- Analyst

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

Steven Kean -- Chief Executive Officer

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

Thomas Martin -- Vice President & President of Natural Gas Pipelines

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

Spiro Dounis -- Credit Suisse -- Analyst

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

Steven Kean -- Chief Executive Officer

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

Operator

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

Tristan James Richardson -- SunTrust Robinson Humphrey, Inc. -- Analyst

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

Steven Kean -- Chief Executive Officer

Yeah. Well, a very good point. So, if you look at our Texas system today, it's about a 5 Bcf a day system and with these two projects that Tom's team has put together here really in a very short period of time, we're bringing another 4 Bcf to that system. Now, those projects come with certain downstream lease arrangements or pipeline capacity arrangements on our existing Texas intrastate system, but it will create, we believe, follow on opportunities for us to do de-bottlenecking 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, right, et cetera. So, the Texas market -- the whole Texas market and our position in it is in very good shape right now and has a very fine outlook.

Tristan James Richardson -- SunTrust Robinson Humphrey, Inc. -- Analyst

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

Steven Kean -- Chief Executive Officer

Okay. Well, we touched on one with the Tennessee Pipeline Reversal. We have additional projects serving LNG coming up that we are looking at on NGPL as well as our Kinder Morgan Louisiana pipeline. We'll look at those also on the Texas Gulf Coast as time goes on and the West will continue to find, I think, some de-bottlenecking opportunities, which may not necessarily have a full bunch of capital, but all that capacity is very valuable certainly in the near term and so we can monetize that.

And then, so to your earlier question, the G&P part of our business, the Bakken is moving again and it is bottlenecked on our system. And so, we are investing capital to de-bottleneck that system and get our customers' product to market. But as Tom alluded to, in the Haynesville and in the Eagle Ford, we've got room on our existing systems to take additional volume with potentially small de-bottlenecking, not capital intensive expansion. So, we'll get some volume, not for free, but for nearly free as it grows in the Haynesville. And so, more in the Bakken than in the other two basins.

Operator

Our next question comes from Keith Stanley with Wolfe Research.

Keith Stanley -- Wolfe Research -- Analyst

On the KML strategic review process, is there any reason you'd want to wait until the Trans Mountain special payments 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?

Steven Kean -- Chief Executive Officer

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

Keith Stanley -- Wolfe Research -- Analyst

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

Steven Kean -- Chief Executive Officer

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

Operator

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

Thomas Edward Abrams -- Morgan Stanley -- Analyst

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

Thomas Martin -- Vice President & President of Natural Gas Pipelines

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

Thomas Edward Abrams -- Morgan Stanley -- Analyst

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

Steven Kean -- Chief Executive Officer

400% utilized in two New Jersey facilities that 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 were up to $1.7 billion now. And so 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 and so we're looking at strategic options for the facility kind of long-term, which could include looking at alternatives for the side.

Operator

Our next question comes from Michael Lapides with Goldman Sachs.

Michael Lapides -- Goldman Sachs -- Analyst

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

Steven Kean -- Chief Executive Officer

Okay. First on Elba. So you have to go way back in time. Though when we originally sanctioned the project, we didn't have a joint venture partner and we didn't have certain other things in place. The return has actually improved since that time and we're still looking at a double-digit after tax, unlevered return. Now part of what brought about that change is we brought in a partner and our investment, and it was promoted, our development of that 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, so that's not, if you will, on us, that's something that Shell is providing. And then we've entered into an EPC contract with our EPC contractor. So the bottom line on all that is, it insulates us from some of what you would normally think of as the cost of pain that's associated with delay. So our returns have surprisingly eroded not that much notwithstanding a fairly significant and really not acceptable from our standpoint delay. The same question was on Gulf LNG. Okay.

Michael Lapides -- Goldman Sachs -- Analyst

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

Steven Kean -- Chief Executive Officer

Yes. So as you have just said. we did get some information on Gulf LNG , the Commission actually gave a timeframe on the EIS and on the expected order date for the 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 and that includes not just marketing the facility to potentially looking at a JV opportunity or other things.

Operator

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

Robert Catellier -- CIBC Capital Markets -- Analyst

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

Steven Kean -- Chief Executive Officer

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

Robert Catellier -- CIBC Capital Markets -- Analyst

And the qualification? The qualification, give us some color on the impact?

Steven Kean -- Chief Executive Officer

Go ahead.

Thomas Martin -- Vice President & President of Natural Gas Pipelines

It depends upon what we actually have in terms of third-party business out there and so would be able to depend on the specific situation.

Robert Catellier -- CIBC Capital Markets -- Analyst

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

Steven Kean -- Chief Executive Officer

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

Robert Catellier -- CIBC Capital Markets -- Analyst

So, that's a material impact then?

Steven Kean -- Chief Executive Officer

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

Operator

And your next question comes from Robert Kwan with RBC Capital Markets.

Robert Michael Kwan -- RBC Capital Markets -- Analyst

Great, thank you.

Hi. Just wanted to confirm with the numbers Dax gave both the CAD4 billion on the dividend and then just over CAD300 million on the tax, just to make sure there's no other major inflows are outflows that pretty much means you've got -- you're going to be no debt, no cash, is that fair?

Dax Sanders -- Chief Financial Officer

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

Robert Michael Kwan -- RBC Capital Markets -- Analyst

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

Dax Sanders -- Chief Financial Officer

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

Operator

Our next comes from Shneur Gershuni with UBS.

Steven Kean -- Chief Executive Officer

Hello, again.

Shneur Gershuni -- UBS Investment Bank -- Analyst

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

Steven Kean -- Chief Executive Officer

Yeah. 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 if the revenue associated with that that could potentially be affected could have some reduction in it, not elimination but some reduction in it, OK. And negotiated rates, discounted rates, would not be affected, they're largely not affected. There's always a possibility that max rates come down enough that they get some of the discounts and they pull the rate, the max rate goes below the discounted rate, but that's very small. And so, it's really the potential for an adjustment is a potential for an adjustment to that 30% subset of the interstate regulated revenues, which in turn are a subset of our natural gas segment. That's what we're trying to convey.

Shneur Gershuni -- UBS Investment Bank -- Analyst

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

Steven Kean -- Chief Executive Officer

Correct.

Kimberly Allen Dang -- President

Right.

Steven Kean -- Chief Executive Officer

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

Shneur Gershuni -- UBS Investment Bank -- Analyst

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

Steven Kean -- Chief Executive Officer

Yes. First of all, what we were talking about with respect to use of proceeds would apply kind of wherever the proceeds came from. We've make sure that we maintain that same leverage ratio, but then we would use them. If there were available projects, we'd use them for projects, but otherwise they would go to share buybacks. So, that's our current thinking.

On the KML assets, we think they're great assets. They are -- it's a fairly new development. We've built the largest merchant terminal position in Edmonton. John and his team did that over a 10 or 12-year period. And the Vancouver Wharves asset is a very good asset. The Cochin Pipeline is a very good asset. And we think that asset packages like this are rare anywhere, but they are rare that come to market and they are rare to come to market in Western Canada. And so, we do think that it tends to be a bit of a sellers market for these assets.

Shneur Gershuni -- UBS Investment Bank -- Analyst

The Oklahoma assets or any other asset?

Steven Kean -- Chief Executive Officer

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

Operator

Thank you. Our next question comes from Jeremy Tonet with JP Morgan.

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

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

David Michels -- Vice President and Chief Financial Officer

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

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

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

David Michels -- Vice President and Chief Financial Officer

That's more Permian asset.

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

That is getting out of Waha?

David Michels -- Vice President and Chief Financial Officer

Yeah.

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

Okay. But that's more --

David Michels -- Vice President and Chief Financial Officer

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

Steven Kean -- Chief Executive Officer

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

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

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

Steven Kean -- Chief Executive Officer

On Double H?

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

Yeah.

Steven Kean -- Chief Executive Officer

Yeah. There is a small remaining expansion to be done, that's pump station. That is right.

Thomas Martin -- Vice President & President of Natural Gas Pipelines

That's right. There is pump --

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

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

Steven Kean -- Chief Executive Officer

Yeah, you can do that within 6 to 8 months.

Operator

Thank you, and I show no further questions.

Richard Kinder -- Executive Chairman

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

Operator

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

Duration: 68 minutes

Call participants:

Richard Kinder -- Executive Chairman

Steven Kean -- Chief Executive Officer

Kimberly Allen Dang -- President

David Michels -- Vice President and Chief Financial Officer

Dax Sanders -- Chief Financial Officer

Jean Ann Salisbury -- Sanford C. Bernstein & Co. -- Analyst

Shneur Gershuni -- UBS Investment Bank -- Analyst

Jeremy Bryan Tonet -- JP Morgan Chase & Co. -- Analyst

Colton Westbrooke Bean -- Tudor, Pickering, Holt & Co. -- Analyst

Spiro Dounis -- Credit Suisse -- Analyst

Thomas Martin -- Vice President & President of Natural Gas Pipelines

Tristan James Richardson -- SunTrust Robinson Humphrey, Inc. -- Analyst

Keith Stanley -- Wolfe Research -- Analyst

Thomas Edward Abrams -- Morgan Stanley -- Analyst

Michael Lapides -- Goldman Sachs -- Analyst

Robert Catellier -- CIBC Capital Markets -- Analyst

Robert Michael Kwan -- RBC Capital Markets -- Analyst

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