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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Welcome to the Quarterly Earnings Conference Call. At this time, all participants are on a listen-only mode until the question-and-answer session of today's conference. [Operator Instructions]. This call is being recorded, if you have any objections you may disconnect at this time.
I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you, you may begin.
Thank you, Jennifer.
Before we begin, as usual, I'd like to remind you that today's earnings releases by KMI and KML and this call includes forward-looking and financial outlook statements within the meaning of the Private Securities Litigation Reform Act of 1995, Securities and Exchange Act of 1934, and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures.
Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measure set forth at the end of KMI's and KML's earnings releases, and to review our latest filings with the SEC and Canadian provincial and territorial securities commissions, for a list of important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking and financial outlook statements.
As usual before turning the call over to Steve, Kim, and the rest of the team, I'd like to provide a quick update and some insight on our financial philosophy of Kinder Morgan. The important news today is that our Board has increased the dividend by 25% from $0.20 per quarter or $0.80 annualized to $0.25 per quarter or a $1 annualized. Now this is consistent with our attention which we announced in mid-2017 to increase the dividend to $0.80 in 2018 to $1 in 2019 and to $1.25 in 2020. Central to our ability to do this is the strong and growing cash flow, our assets are generating and you will see that again in the first quarter's results.
We had used that cash to get our balance sheet in shape having paid off over $8 billion of debt and receive credit upgrade from both S&P and Moody's and we intend to maintain our improved credit metrics. Beyond that we are now focusing on using our cash to fund our expansion CapEx without need to access the equity market to pay our increasing dividends and to repurchase stock when appropriate.
In short, we believe, we are being careful and conservative stewards of our cash flow and using it in ways that benefit all our shareholders. You should expect no less of us should be reassured by the fact that the management and board of KMI are significant shareholders. Steve?
Yes, thanks Rich.
We'll be updating you on both KMI and KML assessment. I'm going to start with a high-level update and an outlook on KMI and then turn over to our President Kim Dang to give any update on our segment performance, David Michels, KMI's CFO will take through the numbers, Dax Sanders will update you on KML, and then we'll take your questions on both companies.
The summary on KMI is this, we're adhering to the principles that we've previously laid out for you. We have a strong balance sheet having met our approximately 4.5X target of debt-to-EBITDA and with ratings upgrades from both Moody's and S&P; we're maintaining our capital discipline through our return criteria, a good track record of execution and by self funding our investments. We are returning value to shareholders with the 25% dividend increase announced today and we continue to find attractive growth opportunities with a net add of $400 million to our backlog during the quarter.
Again strong balance sheet, capital discipline, returning value to our shareholders, and finding additional growth opportunities. Those are the principles we operate by.
Here are a few updates on some of the key projects. First, our Permian Natural Gas Pipeline project. Our customers are anxious to have us get their gas out of the Permian, so they can also get their oil and NGLs out. We have two projects to get the gas out. Gulf Coast Express and Permian Highway each are about 2 Bcf a day of capacity. Both are secured by long-term contracts and both are in execution stage. GCX is scheduled to be in service in October of this year with Permian Highway following a year later. Both projects are on schedule. Both projects are at attractive returns which we expect to realize and both projects bring us additional opportunities in our downstream pipeline.
Combine they bring 4 Bcf a day of incremental gas to a system that moves about 5 Bcf a day today. Those projects will bring opportunities for downstream expansion and optimization as we find homes for that incremental gas through our connectivity with LNG facilities, Mexico exports, utility demand, and Texas Gulf Coast industrial and Pet Chem demand.
Our execution and our economics of these projects both look good and we're actively managing our risks and opportunities on both. These projects show us taking advantage of a very positive situation that is this, there is a large supply growth in Texas and a large demand growth in Texas and we can bridge the two and connect to our premier Texas Intrastate Pipeline Network and stay entirely within the State of Texas which facilitates permitting and commercial flexibility.
As we pointed out at the conference in January of this year, 70% of the demand growth between now and 2030 is projected to be in Louisiana and Texas largely due to LNG and our systems are well positioned to benefit from that.
Also it's worth noting that now 70% of our backlog is natural gas and 56% of that is in our Midstream growth where market based rates in terms of service prevail.
On another key project, Elba our LNG facility that we're building in Savannah, Georgia, we are closing in on the in-service date for the first unit. We now expect in-service of that unit to be around May 1, a couple of weeks from now. Getting the first unit on secures about 70% of the project revenue. That way we've experienced is certainly unwelcome but the risk allocation between us, our contractor, and our customer provides significant protection and mitigates the effect to our IRR. So we're introducing natural gas into the facility as well as refrigerants and that process has been doing well.
Also of note, we added a net $400 million to the backlog this quarter with new investments in natural gas and terminals primarily more than offsetting projects placed in service. The backlog now stands at $6.1 billion.
A few observations about our expansion capital investments over time. As several people have asked how we're doing on the capital, we deploy in those projects. So at the January conference Kim took you through our historical project performance. If you look at Page 49 of what we provided there you'll see a comparison between project EBITDA multiples and actual performance for the projects completed during the 2015 to 2018 period. You'll see that our actual performance was better than our original estimate 5.8X versus 6.1X in the original estimate. You also see that the story is even better in natural gas which makes up the bulk of our backlog as I said when we came out 5.2X versus the original estimate of 5.8X.
On Page 50, you also see some other factors that partially offset the contribution from our project investments. But overall project performance is very good. The point here is we're very careful with your capital; we don't swing at every pitch. We definitely have our hits and misses but we have shown that in aggregate we do well. We get there by having elevated return criteria well above our cost of capital. We focused on projects that we understand and primarily focus on expansions off of our existing footprint. All of this helps us invest the returns that are well above our cost of capital and helps overcome the inevitable curveballs that come up during project execution. This has served us well particularly during an increasingly challenging regulatory environment.
Next an update on 501-G. As we said in our press release Monday of last week we have reached settlements on two more systems EPNG and TGP which now resolves a vast majority of our 501-G exposure. This is an overhang that we now believe we have nearly entirely behind us. The settlements are pending at the commission right now. Here is our observations: the commission generally approves a negotiated settlement that are pending before the commission but we expect that they will be approved; and two, they respect existing settlements including rate moratoria that are in place.
The 501-G overhang has been a consistent part of the dialogue around our stock and we are pleased with our resolution of it. I believe we've said this before but when we announced the budget we did not have anything in for settling 501-G matters but we telegraphed that if we did get such settlements it would likely be a good thing for the value of the company. And we're happy with the outcome.
Finally, before turning it over to Kim, word about the KML process. As we say in the release the process is ongoing. We don't have anything more than that to say at this point. And as you'll hear when we get to KML we've been attentive not only to the process but also to managing and developing the existing business. It's comprised of a very good set of midstream assets. It gets a good deal of effort and focus from our management team. But what I want to say from a KMI investor standpoint is that you need to keep in mind that while our process gets a lot of attention KML makes up about 2% of KMI EBITDA on a consolidated basis so just to put it in perspective for KMI.
And with that, I'll turn over to Kim.
Thanks, Steve.
So looking at the segments Natural Gas had another outstanding quarter it was up 12%. If you look at the market fundamentals they remain very strong for 2019 Lower 48 natural gas demand is expected to increase by 5.5 Bcf to approximately 95 Bcf a day and the Lower 48 production is expected to increase by 7.5 Bcf a day. Growth in the Natural Gas markets in the first quarter is driving very nice results on large diameter pipes.
Transport volumes on our transmission pipe increased approximately 4.55 Bcf a day or 14%. This is the fifth quarter in a row in which volumes have exceeded the comparable prior period by 10% or more. If you look on the demand side deliveries to LNG facilities off of our pipes, I'll put almost 1.5 Bcf a day in the quarter, that's an increase of approximately 900 million cubic feet a day versus the first quarter of 2018.
Power demand on our system for the quarter was down slightly primarily due to warmer weather. Exports to Mexico were up 183 million cubic feet to 3.2 Bcf a day which is a 6% increase versus the first quarter of 2018.
On the supply side, production out of the key basins we continue that we serve continues to increase. You look at the Permian Natural Gas wellhead volumes increased approximately 30% and the Bakken Natural Gas wellhead volumes increased about 31% percent and the Haynesville they increased 29% and in Eagle Ford they increased 8%.
If you look at where these volumes showed up on our transmission pipes, EPNG volumes were up 1.1 Bcf a day primarily due to Permian volumes. Rig volumes were up 900 million cubic feet a day and CIG volumes were up approximately 550 a day both due to growth in the DJ Basin.
KML -- KMLA volumes were up 570 million cubic feet a day primarily due to LNG exports.
On our gas gathering assets, volumes were up 21% or 570 million cubic feet a day driven by the production increases that I mentioned in the Haynesville and the Eagle Ford and the Bakken.
Overall, the higher utilization on 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 as our systems go up will drive nice expansion opportunity.
If you look at the longer-term by 2024 the Natural Gas market is projected to grow to almost 110 Bcf a day driven by increases in power generation, LNG, and Mexico Exports and continued industrial development with most of that supply growth expected to come out of the Permian, the Haynesville, and the Marcellus.
On the product segment it was down slightly in the quarter. We had increased contributions from our Southeast refined products assets, Calnev, and our Bakken crude assets that were more than offset by lower contributions from KMCC. Volumes on KMCC were actually up 16% in the quarter but that was more than offset by lower rates.
Overall crude and condensate volumes were up 8%, refined product volumes in the quarter were flat.
From the terminals business it was up modestly in the quarter. The liquids business which accounts for about 80% of the segment was driven by strength in the Houston ship channel and on our baseline terminal expansion project in Edmonton. These increases were slightly offset by the increased lease expense at our Edmonton South terminal and that became a third-party obligation post the Trans Mountain sale. We added 1.4 million barrels of tankage versus the first quarter of 2018 due to the baseline project coming online bringing our total leasable capacity to almost 92 million barrels as the bulk business in our Terminal segment was roughly flat.
Our CO2 segment was down in the quarter and that was primarily due to lower crude and NGL prices but also to slightly lower production -- oil production volumes. Our net realized crude oil price was down about $11 per barrel and NGL prices were down about $4 per barrel. That crude oil production was down approximately 1,200 barrels a day or 3% due to lower production at Katz and Goldsmith. Katz and Goldsmith are two of our smaller fields and accounts for roughly 10% of our overall production. In these fields since we are not implementing new development projects, we would expect to continue decline over time. On the other hand at SACROC which is our largest field and accounts for well over 60% of our production we continue to find attractive projects.
The CO2 sales and transport business went up slightly in the quarter due to about 5% higher CO2 volumes, CO2 prices were essentially flat. That's it for the segment overview and I'll turn it over to David.
Thanks, Kim.
So today we're declaring a dividend of $0.25 per share, up from $0.20 per share last quarter and in line with our budget to declare $1 per share for the full year 2019. As Rich mentioned, this would be a 25% increase over $0.80 per share compared to 2018. KMI had a good quarter. We grew significantly from last year's first quarter and we overcame a number of items to end the quarter in line with our budget.
We generated DCF per share of $0.60 which is 2.4 times our declared dividend or over $800 million in excess of that dividend. Additionally as the press release points out for the full-year 2019, we forecast our DCF to be on budget and that is even after incorporating the approximately $50 million impacts from our announced FERC 501-G settlement so very nice overall performance from our underlying business.
Turning to the earnings page. Revenues were in line with the first quarter 2018 but operating income was higher due to lower quarter-over-quarter costs.
Net income available to common stockholders for the quarter was $556 million which is a 15% increase from the first quarter of last year. That includes the benefit of zero preferred dividend payments down from $39 million we paid last year in the quarter as a result of the conversion of our preferred equity securities in October of last year.
Adjusted earnings per share was up it was 25% up $0.03 or 14% from the prior period, very nice growth there.
Moving on to distributable cash flow. We believe distributable cash flow is a good reflection of our cash earnings and it was up it was $0.60 per share for the quarter up $0.04 or 7% from Q1 of 2018. Natural Gas segment was the largest driver of that growth up $127 million or 12%.
As has been the consistent theme for that segment recently we benefited on multiple fronts. TGP benefited from multiple expansion projects placed in service in 2018. EPNG was up driven by Permian supply growth more than offsetting the unfavorable impact from the FERC 501-G settlement in the quarter.
Texas and Louisiana gathering and processing assets were up driven by increased volumes from the Haynesville and Eagle Ford Basin. Kinder Morgan Louisiana pipeline was up due to the Sabine Pass expansion.
Our product segment was down $4 million, our terminals segment was up $2 million, our CO2 segment was down $48 million or 20%, as Kim covered the drivers behind those segments performance for the quarter.
Kinder Morgan Canada was down $46 million from Q1 2018 as a result of the sale of our Trans Mountain assets.
Our G&A expense was lower by $6 million due to greater amounts of costs capitalized to growth projects as well as lower G&A resulting from the transition zone sale. Those items were partially offset by higher pension expenses in the quarter and those pension expenses are non-cash and are backed out of our DCF metric and replaced with actual cash contribution. Excluding the higher pension costs, G&A would have been $16 million lower than Q1 2018.
Interest expense was $14 million lower driven by lower debt balance and lower average rate on our bonds as well as greater interest capitalized to our growth projects. That was partially offset by higher LIBOR rates which impacted the interest rate swaps which settled in the quarter.
Preferred stock dividends were down $39 million as I mentioned before. So total DCF of $1.371 billion, was up $124 million or 10% from the prior period.
And to summarize the main changes greater segment EBDA of $38 million when you include the NCI change which relates to the segment generated from greater natural gas contributions offset by lower contributions from CO2 in Canada. $14 million lower interest expense, $16 million lower G&A expenses excluding the non-cash pension expense, and $39 million lower preferred stock dividend which gets you to $107 million of the $124 million increase in the quarter.
DCF per share of $0.60 was again up $0.04 to 7% with the same drivers as total DCF but inclusive of the incremental shares issued as a result of the preferred stock conversion.
Moving onto the balance sheet, once again we have two net debt-to-EBITDA figures listed at the bottom of the table. At year-end 2018 KMI's balance in our adjusted net debt figure included all of the KML's Trans Zone sales proceeds and the adjusted net debt figure excludes the portion of those proceeds that was paid to the KML public shareholders in early January.
Beyond year-end 2018 there was no difference between the net debt and adjusted net debt figures. At the end of the quarter at 4.6% times debt-to-EBITDA which is consistent with our budget is slightly higher than year-end 4.5 times.
Our end of year 2019 leverage is currently forecasted to be 4.6 times which is slightly unfavorable to our plan of 4.5 but is consistent with our long-term leverage target of approximately 4.5 times but slightly higher than budget year-end leverages due to slightly lower than planned EBITDA. The reason EBITDA is forecast to be slightly below budget but while DCF is expected to be on budget it's because of the add-back non-cash pension expenses, the low EBITDA, and EBITDA does not take up the benefit of our favorable interest expense.
Some items to note on the balance sheet changes from year-end. Our cash reduction of $3.1 billion due to -- $1.3 billion used to pay down KMI bonds maturing in the quarter, $800 million distribution to public KML shareholders, $340 million of Canadian taxes due to the Trans Mountain sale, and almost $300 million of lower revolver and CP borrowings. In other assets $700 million of the $712 million increase is due to booking a right to use assets resulting from a new lease accounting standard. The offsetting liabilities in short-term and long-term liabilities include $647 million which are in long-term liabilities which explains most of the increase of the $618 million in other liabilities.
In our short-term and long-term debt changes, in short-term that was mainly due to the payoff of the $1.3 billion of bonds and $700 million of other bonds which rolled into the short-term category and out of the long-term category.
Our adjusted net debt ended the quarter at $34.8 billion which is an increase of $668 million from year-end and to reconcile that we generated $1.371 billion in DCF. We spent approximately $750 million in growth capital and contributions to our joint ventures. We paid approximately $450 million of dividends; we paid $340 million of taxes on our Trans Mountain sale, and we had a working capital use of cash of approximately $500 million. The largest items in that are greater interest payments in the quarter, bonus payments, payroll and property tax payments.
With that I'll turn it back to Steve.
Okay. Now we're going to turn to KML and that KML again we realized burning question here is the process we previously announced and which is we said today remains ongoing and we should have an update for you in the coming weeks. All we have to say at this point about the process is in the press release but clearly we'll have more to say once we have something to announce.
In the meantime as you'll hear from Dax and as we've said all along we've got a good business here that we continue to operate and invest in as a standalone business. And we're in the good position of not being forced to do anything. So we'll work through the process and we'll have we believe a conclusion in the coming weeks much to know more about it at that time.
With that, I will turn over to Dax.
Thanks, Steve.
Before I get into the results, I do want to update you on a couple of general business items. On the announced diesel export project, we received our required air permit amendment and key building permit to satisfy the key condition process that customer's contract. As such we can now commence construction activities planned to do so in May. Consistent with previous statements this is an approximately $43 million project that contemplates two new desolate tanks with combined storage capacity of 200,000 barrels underpinned by a 20-year take or pay contract that we expect to put in service during the first half of 2021.
Of the shed six reactivation project that we discussed we expect to get our key building permit shortly which will allow us to start construction in May also and have the project in-service in December 2019. As a reminder the total CapEx on that project is approximately $8 million.
Now moving towards the results and of note as I talk through the results I'm generally only going to reference results from continuing operations as discontinued ops only relates to prior periods and is less relevant.
Today the KML board declared a dividend for the first quarter of 0.1625 per restricted voting share or $0.65 annualized which is consistent with previous guidance. Earnings per restricted voting share for continuing operations for the first quarter of 2019 are $0.12 and that is derived from approximately $21 million of income from continuing operations which is up approximately $7 million versus the same quarter in 2018.
Revenue increased across most all of KMLs assets and was led by the contribution from the baseline tank and terminal assets coming online but was partially offset by the expiration of a third-party contract on ESRP which we've previously discussed. The increase in revenue was partially offset by higher G&A and depreciation.
Total DCF from continuing operations for the quarter was $22.4 million which is down about a $1 million from the comparable period in 2018. That reflects coverage of approximately $1 million and reflects the DCF payout ratio of approximately 85%. The coverage and payout ratio this quarter were skewed by the large cash tax amount of almost $21 million which is $14 million higher than the almost $7 million in comparable period last year. As we previously discussed, we were not required to make cash tax payments in 2018 or 2018 operations but rather were able to defer them to this year. As such, we made a cash tax payment in the first quarter of $17.3 million for 2018 which is consistent with what we budgeted and a payment of $3.5 million for 2019 which together make up the almost $21 million.
As we sit here today while we have not finalized the 2018 Canadian return, we believe the tax ultimately owed will be less than the $17.3 million that we budgeted and paid and that we'll be able to apply the excess to 2019.
Looking at the other components of the DCF variance, segment EBITDA before certain items up $13 million compared to Q1 2018 with the Terminals segment up $9 million and the pipeline segment up $4 million. The Terminals segment was higher due primarily to baseline coming online which accounted for about $7.3 million. The North 40 added about $2.2 million largely from rate increases in new TSAs and Vancouver Works added about $1.7 million due to incremental volumes. Those positives were offset by $2.4 million negative variance on ESRP primarily due to the expiration of the contract that I mentioned a second ago.
Pipeline segment was higher primarily due to lower O&M on coaching of approximately $2.7 million due to the non-occurrence of inline inspection, dig, and other integrity management items performed in Q1 2018 and higher revenues of approximately $1.3 million largely from FX and a short-term deal not in place in Q1 2018.
D&A is negative about 1.5 million compared to Q1 2018 largely due to some transition services costs related to the Trans Mountain sale and some higher labor.
Interest is favorable by approximately $1.6 million due primarily to interest income on the $308 million of cash we held until making the cash tax payment of the same amount on the Trans Mountain gain on February 28.
I've already discussed cash taxes, preferred dividends are flat, and sustaining capital was slightly unfavorable compared to Q1 2018 due to timing.
With that, I'll move onto the balance sheet comparing year-end 2018 to 3/31 of this year. Cash decreased approximately $4.292 billion to approximately $47 million which is due to $22 million of Bcf plus net borrowings of $50 million offset by $3.977 billion in special distributions, $19 million in common dividend, $37 million paid on the final working capital adjustment on Trans Mountain paid to the government, $13 million of cash paid for expansion capital, $308 transmission of cash taxes paid on the Trans Mountain gain and a working capital other usable about $10 million.
Other current assets increased approximately $14 million primarily due to the prepaid asset associated with the federal income taxes that I mentioned earlier and a small increase in accounts receivable.
Net PP&E decreased by 17.3 as a result of depreciation in excess of net assets placed in service.
Leased assets increased from 0 to approximately $514 million as we adopted the new accounting rule ASC 842 which requires us to report present value of operating leases.
Deferred charges and other assets increased approximately $1.3 million primarily as a result of a contribution to the coach and reclamation process.
On the right hand side of the balance sheet, the credit facility balance increased by $50 million from zero as we borrowed a bit from general working capital needs. Distributions payable and distributions payable to related parties went to zero as we made the January 3rd special distributions of the Trans Mountain from sale proceeds. Currently these liabilities increased $17 million which is the current portion of the lease liability. That is the other side of the entry related to the ASC 842 lease accounting that I mentioned.
Other current liabilities decreased by approximately $363 million primarily due to the payment of the taxes payable on the gain that I mentioned $308 million in the final Trans Mountain working capital payment of $37 million that I mentioned to the government.
Lease liabilities increased by almost $497 million which is the long-term portion of lease liability that is the other side of the entry related to the ASC 842 lease accounting I mentioned. Other long-term liabilities increased by about $1 million primarily due to a small increase in the liabilities associated with the coach and reclamation process. From a liquidity perspective, we ended the quarter with $47 million in cash and significant available liquidity as we had only $50 million drawn out of the $500 million revolver. Our debt to LTM adjusted EBITDA ratio was just under 1.4. However given potential rating agency adjustments on operating leases and other items, this ratio is not necessarily indicative of our debt raising capability and our credit rating.
And with that, I'll turn it back to Steve.
All right, thanks, Dax.
And before the Q&A as we've been doing for the last few quarters as a courtesy to all callers we're asking that you restrict yourself to one question and then one follow-up question and if you have more questions not answered please get back in the queue and we will come back around to you and answer your question. Okay. And with that, Jennifer you can open it up.
Thank you. [Operator Instructions].
And our first question comes from Shneur Gershuni from UBS. Your line is open.
Hi, good afternoon everyone. Are you able to answer any questions about the KML process like the order does that mean anything?
The order?
The order in the press release has the three options is it likelihood of success or preference?
I hear you, Shneur. So, no, beyond the press release as would be customary when you're running a process like this we're just going to run the process and really not comment beyond what we've said publicly in the release.
Okay, fair enough. Just a couple of questions here. You're spending $3.1 billion in CapEx this year. You've added $600 million to the backlog. You recently walked from the DLCC Board opportunity. Where do you see incremental opportunity to spend CapEx in the next 18 months based on -- in addition to where you're at right now and do you have kind of a sense on the zip code of what 2020 would look like would it be higher or lower than where you expect 2019 to shake out?
On the last we're again continuing to guide to between $2 billion and $3 billion and we won't get to that finally until we do our budget for 2019. But I think to your first question as we mentioned in talking about what's going on in the Texas market and what's going on in Midstream generally as Kim took you through the numbers there. We continue to see good opportunities in natural gas which makes up 70% of the backlog. We're seeing some opportunities here and there in refined products; continue to see small incremental opportunities there. As the year goes on, there is less coming in 2019 and we feel comfortable with kind of what we guided to in terms of discretionary CapEx at the beginning of the year as being where we will end up with it. But that's where the opportunities are coming from, that's what we expect for 2019, and we're working on 2020 and beyond as we speak to take the $2 billion to $3 billion as a reasonable guide.
Okay. And a follow-up question. Given there seems to be a trend towards product exports. Is your operating leverage in your terminals and refined product system to be able to benefit around more export at a decent ship channel or what we're seeing right now kind of where you're at?
Yes, there is. So we have 11 ship docks and 12 barge docks and we have been growing kind of at an 8% annual year-over-year rate --
8.5%.
8.5%.
Year-over-year over the last five years.
8.5% year-over-year over the last five years, as John points out. And you won't quite see that in the first quarter because we had some fog, we had some issues in the ship channel associated with the ICC incident which restricted that but it's not for a lack of demand to move U.S. refined products to overseas markets.
And I don't think there's anybody better positioned than we are with the amount of docks there.
Right. We have some spare capacity which is part of your original question.
All right. Perfect, thank you very much. Appreciate the color guys.
The next question comes from Colton Bean from Tudor, Pickering, Holt & Company. Your line is open.
Good afternoon. Just wanted to follow-up on the comments on leverage. You've seen some positive action from the ratings agencies but it does seem like balance sheet has shifted higher in the priority list for the public markets. Could you just provide an update as to how you're looking at the 4.5 times target and whether the strategy around capital allocation has shifted at all?
Sure. We think the 4.5 is the right place to be for our particular assets given the size, the stability of cash flow, the diversity of the businesses that we have, the quality of customers, the dividend coverage you put all those things together we actually map higher than BBB flat. And we think that all of those factors with respect to our business is what has made the rating agencies comfortable with the upgrades that they've given us. So we think the 4.5 times given all of those considerations is a fine place to be.
Got it. And then on KMCC, I think you all noted over the last few quarters that you have seen some rate reductions. Can you just update us as to where we stand in terms of the recontracting process there?
Yes, sure. The recontracting process is ongoing and we do expect to see some additional capacity commitments forthcoming but granted at lower rates. The other thing -- the other key development for us on KMCC is that we've kind of set this out as a goal and talked about it over time as we want to get that type to access Permian Barrel.
So right now of course it primarily see -- it primarily is a takeaway for growing Eagle Ford production but there's a lot of capacity away from the Eagle Ford. So even as it grows, it takes a while to fill that capacity back up and hence the rate -- the rate reductions we're experiencing on the base business. But we participated in a Roanoke Expansion that open season was just extended to April 30. However we've got some pretty good commitments there and I think we're going to be successful in getting Permian barrels attracted to KMCC. And so that'll be a part of our picture going forward as we mitigate and add back some growth from the outside, okay.
Got it. And just a quick follow-up on that, so you mentioned the Permian barrels, is there an ability to use that pipe as a logistical backstop for Corpus exports as well if you had a weather issue in Corpus could you use that to get barrels up to Houston market?
Yes. And so that's if you put your finger right on it. So I think what we're seeing is that and for good reason is that I think customers are looking particularly at the early periods here and they're looking for an alternative. And there's really no better alternative than the Houston market with the refining base that we have with the access to the Pet Chem markets and global markets over docks all of the infrastructure that we and others have in the ship channel makes Houston an attractive market for these barrels. So it's -- I'd say more than a backstop it's a nice market outlet alternative, a nice market option that we'd expect to be particularly strong in the early days but we'll be around for a long time.
The next question comes from Tristan Richardson from SunTrust. Your line is open.
Hey good afternoon guys. Just briefly on the slightly lower EBITDA commentary, should we think of that deviation from budget is purely the incorporation of a final 501-G settlement you guys talked about last week or there's some other puts and takes to think about?
Go ahead, Kim.
There are some other puts and takes and obviously you've got the delay on elbow which has an impact versus the budget. The pension expense that David talked about which add back that non-cash pension expense and tracked out the cash contributions for DCF and that's why you see the difference between the EBITDA and DCF and then also impact of a slightly lower commodity prices primarily the NGL price impact on DCF.
So the interesting thing, I think the interesting conclusion is that notwithstanding those moving parts and not all of them affect DCF and EBITDA the same way. But we're basically flat on DCF and slightly down on EBITDA and we've absorbed and put behind us the significant regulatory risk that we did not budget for settlements on. And so really that tells you that that the base business is strong and overcoming a lot in the way of headwind.
Great, very helpful. And then just a follow-up could you talk about your potential JV project serving the Bakken and Rockies and just sort of the timing of the commercial process there and that evolution?
Sure. So that's our project with Tallgrass and we are in customer discussions right now. We think we have a good project because it is using in significant part existing pipeline assets. So our AA system which is not something to be contributed to the joint venture but our -- one of our Vic medicine [ph] laterals and the Cheyenne Plains system which provides significant takeaway capacity really for three sources of supply.
One is the Bakken, second is some heavy barrels arriving from Canada at currency, and third is Powder River and DJ Basin barrels. There's also the PXP Systems that is part of the joint venture that Tallgrass is contributing. So bottom-line on all that is we're offering a lot of way to provide true takeaway capacity with a lot of existing pipe only about 200 miles of new build to get to Cushing with the converted gas pipes. So significant capacity probably more than we would expect to contractually fill up but we're in contractual discussions right now and I think we've got a good proposal for the market but not in the backlog and not nothing more definitive to announce at this point.
Helpful. So could potentially have a decision this year?
That's possible.
The next question comes from Gabriel Moreen. Your line is open.
Good afternoon everyone. First question for me is just what are the backlog around Bakken, GMP has just shifted it all upwards since the Analyst Day. Just curious whether that's -- that's you've added anything there?
Yes. We've had had some capital additions there. We continue to see good performance from our customer shippers' there and particularly a compelling need for additional gas processing and takeaway capacity. And so we have added a couple of projects and call it 10 to million ballpark to what we already had in when we did the January conference.
Okay, thanks Steven, and I was going to ask on Tall Cotton now that Phase 2 is completed, can you maybe give us your latest thoughts on proceeding with Phase 3 given the performance out of the reservoir?
So Tall Cotton as we said in the release, we've seen year-over-year growth in the production there. But it's behind our plan. And so frankly we are deferring further investment decisions in there until we get a better sense for downhaul conformance and in other words that we'd like to do to get confidence that we're going to get what we get confidence in what we're going to ultimately be able to recover from the reservoir.
In previous quarters we had talked about operational issues regarding compression and gas handling and things like that. We think we have those behind us at this point but it's still a question of what do we need to do in terms of conformance. And we're going to get ourselves satisfied on that before we make a further significant capital commitment to it.
And does oil price matter at all for that Steve or is it just agnostic of oil price?
No, oil price always matters, fam. It always matters.
The next question comes from Spiro Dounis from Credit Suisse. Your line is open.
Hey good afternoon everyone. Just wondering if you could provide some guidance or maybe some color just around Waha gas prices and maybe some of the volatility negative basis we've seen their lately. Just wondering if you could expect that basis to stay negative and maybe even get worse over time until GCX comes online and is there anything you can do to actually to speed GCX up at this point?
As I said at the beginning, we're doing everything we can for our customers there both with our existing infrastructure as well as prosecuting our projects just as quickly as we can. And we feel very good about our schedule on GCX and I think we're making extremely good progress there. I think to answer your question about basis, you have to take a lot of other things into account like what producer self help is available, more docks, and things like that and so we don't have any special insight into forward basis and how much of that can be mitigated by producer activity. But there's no question that there is heavy demand to get out of the Permian and we're doing our best to fill that demand for our customers.
Yes and I mean this is nothing that isn't already at the rides. There were two main drivers have caused little severe negative basis that we experienced over the last few weeks. Outages and then well really outages on an intrastate system and interstate system and so as those come back on things should relieve a bit. Then the other thing we're hearing [indiscernible] some of the dry gas portions of the Permian we're seeing some nominal shutdowns and so you get more relieved, out of the basin and so all that should improve somewhat but it's actively a pretty good market, really good. GCX online and then I think beyond that I think it's initiated a little bit very quickly and we could be in somewhere [indiscernible] next year.
Fair enough. I appreciate that color. And then want to respect your process on Canada, so I won't ask specifically around that review but I guess we have new data points coming out of Alberta in terms of the government turning over there and that would seem to sort of favor energy in Canada. Just curious how much of that sort of factoring into your decision making process in general and maybe how you view the landscape there?
Look I think we're generally we feel good about having the terminal position that we have in Alberta with the activity that it has with the customer base we have with what we've been able to see on contract renewals and the performance that we've had on our expansion projects up there. We're not really opining on governments and all of that we just work with our customers to get the do business as best we can. Of course other people have written about what they believe the implications are for the energy business and we just kind of refer to those.
The next question is from Keith Stanley from Wolfe Research. Your line is open.
Hi, good afternoon. On KML just the one thing in the statement is that I think before you guys have decided a transaction with KMI as one of the alternatives and that's not in the release this afternoon. Any color on why KMI, KML transactions not one of the options.
I'm going to stick to my script Keith and just say what we say in the press release is kind of all we have to say about it at this point.
Okay. On the Permian gas side you guys have obviously led and been the only one successful in building a gas takeaway pipelines in the Permian. Is there any potential for a tender to build a third Permian pipeline even potentially just given the downstream sort of benefits on connectivity that you guys have?
Yes. And there are some discussions ongoing. There's nothing to announce and of course it's not the backlog because we're not under contract or anything but the demand to get out of the Permian continues to grow and the desire to be able to unlock the value that's in oil and the NGLs as well as the natural gas continues to put pressure on the need for additional takeaway capacity.
And so short answer is, yes. And if you look at the projections they would show you that a GCX a year almost is what's required in order to satisfy the need for takeaway capacity and to unlock the value of the other commodities out of the Permian, I don't know that it's going to be anything like that pace or that is going to be at that pace. But there's certainly interest already in the Phase 3.
The next question comes from Dennis Coleman from Bank of America Merrill Lynch. Your line is open.
Hi, good afternoon everyone. Thanks for taking my questions. If I can start maybe a little bit more on GCX, you talked about doing everything you can for your customers; I guess center of that is trying to get it online as soon as possible, some anecdotes that they're from different sources that it is well ahead of schedule. I guess maybe the simple question is how much ahead of schedule might you be able to come on, is it -- could it be are we talking weeks, is it months?
This is a long pipeline with a lot of compressor stations to commission meter stations, to commission booster compression to commission and final testing and backfill all the things you have to do to get a pipeline a long linear asset where every inch is a critical path. All that work we have to do, so we're going to leave it at.
We're doing well. We're doing well on schedule. We're happy with where we are in the construction process and we're going to do everything we can to be there for our customers just as fast as we can. But because of -- because it's a long linear project with a lot of mechanical parts to it that we've got to get completed we're not comfortable in projecting some kind of an early in-service date anything other than the October 1st at this point.
Sure. And that's totally fair. I guess maybe a different question is, the revenue turns on when you get FERC approval to put in service, I guess no FERC approval there?
It’s not a FERC pipeline. The contracts go into service, service and we're able to provide the two DCF capacity that's associated with this pipeline.
Okay. My follow-up sort of more of a blue sky question, I guess but with the increase in gas production that you're talking about storage does come to mind particularly as we push up the volume of LNG that we're exporting. There hasn't been much growth in storage in recent years there is the old reason of somewhere in an arbitrage doesn't exist. Is that something that you'll look at over time or how do you think about storage as an opportunity maybe, maybe not in the next couple of years but beyond that as that volume grows?
Absolutely, Tom?
I mean clearly as the market grows polymetrically in the way, it's talked about today there's going to be a need for more storage over time. We and obviously certainly need commensurate value to expand storage capability beyond what we have today. And so we'll be watching that. I mean I guess the one comment I'll make that although the seasonal values have not really increased but probably contracted a bit. If you look at it historically, we've seen certainly, seen an increase in extrinsic value volatility value but if you look at the components of supply and demand that makes a lot of sense. So to the extent the sum of intrinsic and extrinsic rose and to support future expansion. Obviously customers hope that come in and stepped up behind all that. We'll look at expanding our storage footprint. We're in a great position with the existing capability we have across all of our markets today to provide storage service and that's an upside potential for us as the market rose.
Great. Would you expect it to be more salt or more sort of single turn buildup?
Yes, I think clearly with the volatility being more of the component and obviously by stopping renewables I think multi-cycle high delivery types of storage makes the most of it, which Tom's team has a lot of Texas and has -- is facing additional LNG demand coming on which is very chunky as well as additional supply coming on which in this case is chunky with Gulf Coast Express coming on. So having our Texas Intrastate System a significant amount of self-dome storage capability is an advantage as we see this play out.
The next question comes from Michael Lapides from Goldman Sachs. Your line is open.
Hey guys, thanks for taking my question. Actually I have two unrelated ones, one regards to connectivity for crude pipeline capacity between Corpus and the Houston Ship Channel and the Houston market, just curious are there lots of people concerned about enough pipeline capacity between the two markets relative to the size of exports and in them pipes. But there are opportunities to expand KMCC or are you looking at that market and seeing what could be congestion down the road as more inbound crude pipelines come online?
Okay. So I think that it's not like there's a lot of pipe going from Corpus to Houston or other way around. However there is pipe that can't get to Corpus or can get to Houston. And if you look at Gray Oak for example, Gray Oak is being built all the way over to well being built to Freeport too but also to Corpus ultimately and it interconnects with it will interconnect with KMCC which then creates execution option.
So that creates the kind of connectivity that you're talking about. And as we said in response to your earlier question we expect that option to Houston to get some pretty good utilization as things come on and then yes, we do have expansion capability on KMCC as well.
Got it, okay. Kind of my apologies, coming hard to introduce said about 70,000, 75,000 barrels. We can talk offline on that. Then any change in status or thoughts about kind of the embedded call option that is both LNG in terms of just next step, next steps from here if any?
We are going to continue to work with all of our stockholders defined write next step, we did today get approval of our EIS from the condition on the version that we filed earlier. But really there is nothing more to update or report at this point.
The next question comes from Mirek Zak from Citigroup. Your line is open.
Hi, good afternoon. Last week you nearly saw Presidential Executive Orders but this potentially create or renew any opportunities for you to move gas further into the northeast. Maybe something similar to the northwest direct or maybe not as large or has not enough change perhaps on the market demand side for anything to move forward.
It’s good but not that good. I think there's a lot -- there are a lot of others it is good, okay there does need to be some rationality in the way the delegated authority is handled by the states under the environmental regulations, their permitting authority. So that's a good thing just generally but there are a lot of things to work through in the Northeast on getting new pipeline infrastructure in place and we continue to work on those projects. Any D is a very big project and that's not a very likely resurrection, what we think is that we will find smaller one-off kind of -- one-off kind of projects to do work very closely with our utility customers and we have we have one of those that's ongoing right now and we're working on another.
Okay, great. And then switching to the Permian here on all your gas pipelines outlets out of the Permian, do you have any level of open or market capacity or any of those lines available to you that allows you to take some advantage of the low Waha pricing there and if so can you quantify the level at all?
Yes, I mean everything that well first of all we do have takeaway capacity that's existing capacity out of the Permian. And so we do have the opportunity to take advantage of that provide outlets for our customers but every nook and cranny is in use.
Okay, got it. Thank you.
By our customers.
[Operator Instructions].
And the next question comes from Jeremy Tonet from JPMorgan. Your line is open.
Hi good afternoon. Just wanted to touch based on the environment building pipeline Texas and your thoughts on how still the 991 and if there is any chance to pass this share and just in general is it getting a little bit more difficult or you take a little bit more time to build a pipes in Texas, any thoughts you could provide there?
So yes, there is Texas legislature is in session right now and so there are number of builds are being considered regarding eminent domain and modifying the existing evident domain process. We had really and let me put it this way; this is not a traditional landowner versus pipeline issue any longer. I mean this is about the value of the Permian that benefits the entire State of Texas and the profound public interest that's at stake there when it comes to royalties, taxes, royalties going to the state to fund schools et cetera.
And so I think it's fair to say that people in the Texas legislature understand how important it is to unlock the value of this resource in the public interest and that's what you have eminent domain for. And so our view is that and what will emerge from that process ultimately will be a rationale properly balanced -- properly balanced approach to eminent domain. In the meantime we are actively working with our landowners in order to get concessional arrangements in place and we're using the existing process with eminent domain where that makes sense as well. But we don’t currently see any kind of excess potential threat to our project by any stretch.
That’s helpful, thanks for that. Suppose you might not give a lot of color here but just trying to put your comments together as far as the impact to EBITDA guidance here, and is $50 million to $150 million of impact, is that kind of booking what we’re looking at here or is this a right zip code or I'm off on that field?
We’re just going to stick with this slightly down and what that implies, it's not a material impact.
Got it. One last one if I could. IMO 2020 just wondering if that's any impact that you guys are seeing with regards to your storage position, any benefits that you guys see in the different storage areas of Houston?
Yes, John Schlosser from our Terminals Group.
It's a very small amount of flat visits less than 3% and it’s under a long-term agreement, most of it here at our BOSTCO facility but there are opportunities for a segmentation project at BOSTCO to handle both high sulfur and low sulfur and as one of the largest handlers at this point in the United States, there is opportunities for blending there as well.
And it sounds like the New York market or anything else like that?
It has not helped New York market, our opportunities are mostly in the Gulf Coast but there are smaller opportunities up and down the East Coast.
There are no further questions in the queue at this time.
Good. Thank you very much.
That does conclude today’s call. Thank you for participating. You may disconnect at this time.