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. At that time, to ask a question, please press star and the number one on your phone and record your name at the prompt. 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, the Securities Exchange Act of 1934, and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measures set forth at the end of KMI's and KML's earnings releases. To review our latest filings with the SEC and Canadian provincial and territorial securities commissions for a list of important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking and financial outlook statements.
As 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 at 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 $1 annualized. This is consistent with our intention, which we announced in mid-2017, to increase the dividend to $0.80 in 2018, to $1 in 2019, and to a $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 have used that cash to get our balance sheet in shape, having paid off over $8 billion of debt and received credit upgrades for both S&P and Moody's. 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 and 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 this afternoon. I'm going to start with a high-level update and outlook on KMI, then turn it over to our President, Kim Dang, to give you the update on our segment performance. David Michels, KMI CFO, will take you through the numbers. Dax Sanders will update you on KML. Then we'll take your questions on both companies. The summary on KMI is this: we're adhering to the principles that we 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. 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 that 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. 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. Both projects bring us additional opportunities in our downstream pipelines. Combined, 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 on these projects both look good. 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. 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. Our systems are well-positioned to benefit from that. Also, it's worth noting that now 70% of our backlog is natural gas. 56% of that is in our midstream group, 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. The delay we've experienced is certainly unwelcome, but the risk allocation between us, our contractor, and our customer provides significant protection and mitigates the impact to our IRR. We're introducing natural gas into the facility as well as refrigerants, and that process has been going 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.
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 original estimate, 5.8x versus 6.1x in the original estimate. You'll also see that the story is even better in natural gas, which makes up the bulk of our backlog, as I said, where we came out 5.2x versus the original estimate of 5.8. On page 50, you'll 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 focus on projects that we understand and primarily focus on expansions off of our existing footprint. All of this helps us invest in returns that are well above our cost of capital and helps overcome the inevitable curve balls 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 resolve 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's our observations. The commission generally approves negotiated settlements. They're pending before the commission, but we expect that they will be approved. 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, a 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.
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 is 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. Just to put it in perspective for KMI. With that, I'll turn it over to Kim.
Okay. Thanks, Steve. 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. 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 our assets. Transport volumes on our transmission pipes 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 were almost 1.5 Bcf a day in the quarter.
That is 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 that we serve continues to increase. If you look at the Permian, natural gas wellhead volumes increased approximately 30%. In the Bakken, natural gas wellhead volumes increased about 31%. In the Haynesville, they increased 29%, and in the 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.
WIG 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. KMLP 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 fill up, will drive nice expansion opportunities.
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. The products segment 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. The terminals business 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 Base Line Terminal expansion project in Edmonton. These increases were 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 Base Line project coming online, bringing our total leasable capacity to almost 92 million barrels. The bulk business in our terminals segment was roughly flat. Our CO2 segment was down in the quarter. That was primarily due to lower crude and NGL prices, but also to slightly lower oil production volumes. Our net realized crude oil price was down about $11 per barrel, and NGL prices were down about $4 per barrel.
Net crude oil production was down approximately 1,200 barrels a day, or 3%, due to lower production at Capps and Goldsmith. Capps and Goldsmith are two of our smaller fields and account for roughly 10% of our overall production. In these fields, since we're not implementing new development projects, we would expect a continued 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 was up slightly in the quarter due to about 5% higher CO2 volumes. CO2 prices were essentially flat. That's it for the segment overview, I'll turn it over to David.
Thanks, Kim. 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 of 2019. As Rich mentioned, this would be a 25% increase over $0.80 per share declared for 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 impact from our announced FERC 501 settlement.
Very nice overall performance from our underlying business. Turning to the earnings page, revenues were in line with the first quarter 2018, 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 $0.25, 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, 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, it 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 Form 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 terminal segment was up $2 million.
Our CO2 segment was down $48 million or 20%, 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 asset. Our G&A expense was lower by $6 million due to greater amount of costs capitalized to growth projects, as well as lower G&A resulting from the Trans Mountain sale. Those items were partially offset by higher pension expenses in the quarter. Those pension expenses are non-cash and are backed out of our DCF metric and replaced with actual cash contributions. 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. Total DCF of $1.371 billion was up $124 million or 10% from the prior period. To summarize the main changes, greater segment EBITDA 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 and KM Canada. $14 million lower interest expense, $16 million lower G&A expenses, excluding the non-cash pension expense, $39 million lower preferred stock dividends, 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 or 7% with the same drivers as total DCF, but inclusive of the incremental shares issued as a result of the preferred stock conversion. Moving on to 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, excuse me, Trans Mountain 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 is no difference between the net debt and adjusted net debt figures. We ended the quarter at 4.6 times debt to EBITDA, which is consistent with our budget and 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. The slightly higher than budget year-end leverage is 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 is because we add back non-cash pension expenses below EBITDA, and EBITDA does not pick up the benefit of our favorable interest expense.
Some items to note on the balance sheet changes from year-end are 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, CAD 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 asset 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. 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 CAD 340 million of taxes on our Trans Mountain sale. 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. At KML, again, we realize the burning question here is the process we previously announced, which as we said today, remains ongoing. We should have an update. All we have to say at this point about the process is in the press release. 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. We'll work through the process, and we'll have, we believe, a conclusion in the coming weeks and let you know more about it at that time. With that, I'll turn it 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 that satisfied a key condition precedent in the customer's contract. As such, we can now commence construction activities and plan to do so in May. Consistent with previous statements, this is an approximately $43 million project that contemplates two new distillate 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. On the Shed 6 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. 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 period 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 KML's assets and was led by the contribution from the Base Line tank and terminal assets coming online, but was partially offset by the expiration of a third-party contract on ESRP, which we have previously discussed. The increase in revenue was partially offset by higher G&A and depreciation. Total DCF from continuing operations for the quarter is $22.4 million, which is down about $1 million from the comparable period in 2018. That reflects coverage of approximately $1 million and reflects a DCF payout ratio of approximately 85%. The coverage and payout ratio this quarter are skewed by the large cash tax amount of almost $21 million, which is $14 million higher than the almost $7 million in the comparable period last year.
As we previously discussed, we were not required to make cash tax payments in 2018 for 2018 operations, but rather were able to defer them to this year. As such, we made a cash tax payment in the 1st 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 was up $13 million compared to Q1 2018, with the terminal segment up $9 million and the pipeline segment up $4 million.
The terminal segment was higher due primarily to Base Line coming online, which accounted for about $7.3 million. The North 40 added about $2.2 million, largely from rate increases in new PSAs, and Vancouver Wharves added about $1.7 million due to incremental volumes. Those positives were offset by a $2.4 million negative variance on ESRP, primarily due to the expiration of the contract that I mentioned a second ago. The pipeline segment was higher, primarily due to lower O&M on Cochin of approximately $2.7 million due to the non-recurrence of inline inspection digs and other integrity management items performed in Q1 2018, and higher revenue of approximately $1.3 million, largely from FX and a short-term deal not in place in Q1 2018. G&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 28th. I've already discussed cash taxes. Preferred dividends are flat, and sustaining capital is slightly unfavorable compared to Q1 2018 due to timing. With that, I'll move on to the balance sheet comparing year-end 2018 to 3/31 this year.
Cash decreased approximately $4.292 billion to approximately $47 million, which is due to $22 million of DCF, plus net borrowings of $50 million, offset by $3.977 billion in special distributions, $19 million in common dividends, $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 million of cash taxes paid on the Trans Mountain gain, and a working capital/other use of 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 million as a result of depreciation in excess of net assets placed in service.
Lease assets increased from zero to approximately $514 million as we adopted the new accounting rule, ASC 842, which requires us to record present value of operating leases. Deferred charges and other assets increased approximately $1.3 million, primarily as a result of a contribution to the Cochin Reclamation Trust. On the right-hand side of the balance sheet, the credit facility balance increased by $50 million from zero as we borrowed a bit for 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 sale proceeds. Current lease 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, and 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 the lease liability. That's the other side of the entry related to the ASC 842 lease accounting I mentioned. Other long-term liabilities increased by about a million, primarily due to a small increase in the liability associated with the Cochin Reclamation Trust. 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 a $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 current rating. With that, I'll turn it back to Steve.
All right, thanks, Dax. For 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. 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. With that, Jennifer, you can open it up.
Thank you. Just a reminder, if you would like to ask a question, it is star one from your phone. Please record your name and company at the prompt. 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 of the three options. Is it likelihood of success or preference?
I hear you, Shneur. 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 VLCC port opportunity. Where do you see incremental opportunity to spend CapEx in the next 18 months, in addition to where you're at right now? Do you have a sense on a 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, we won't get to that finally until we do our budget for 2019. I think to your first question, as we've 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's less coming in 2019, we feel comfortable with what we guided to in terms of discretionary CapEx at the beginning of the year as being where we'll end up with it. That's where the opportunities are coming from.
That's what we expect for 2019, we're working on 2020 and beyond as we speak. I think the $2 billion-$3 billion is a reasonable guide.
Okay. As a follow-up question, given there seems to be a trend towards refined product exports, is there operating leverage in your terminals and refined product system to be able to benefit around more export out of Houston Ship Channel? Is what we are seeing right now where you are at?
Yes, there is. We have 11 ship docks and 12 barge docks, and we have been growing at an 8% annual year-over-year rate.
8.5% over the last five years.
8.5% year-over-year over the last five years, as John points out. You will not quite see that in the first quarter because we had some fog. We had some issues in the Ship Channel associated with the ITC incident, which restricted that. It is not for a lack of demand to move U.S. refined products to overseas markets.
I don't think there's anybody better positioned than we are with the 11 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 & Co.. Your line is open.
Afternoon. I just wanted to follow up on the comments on leverage. You've seen some positive action from the ratings agencies, it does seem like balance sheet has shifted higher on the priority list for the public markets. Can 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 triple B flat. We think that all of those factors with respect to our business is what has made the rating agencies comfortable with the upgrade that they've given us. We think the 4.5 times, given all of those considerations, is a fine place
Okay, perfect. On KMCC, I think you all have noted over the last two 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?
Yeah, sure. The recontracting process is ongoing, and we do expect to see some additional capacity commitments forthcoming, but granted, at lower rates. The other key development for us on KMCC is, and we've set this out as a goal and talked about it some over time, is we want to get that pipe to access Permian barrels. Right now, of course, it primarily is a takeaway for growing Eagle Ford production, but there's a lot of capacity away from the Eagle Ford. Even as it grows, it takes a while to fill that capacity back up, and hence the rate reductions we're experiencing on the base business. We participated in the Gray Oak expansion. That open season was just extended to April 30. However, we've got some pretty good commitments there and think we're going to be successful in getting Permian barrels attracted to KMCC.
That'll be a part of our picture going forward as we mitigate and add back some growth to the asset. [inaudible] Tammy, then Ryan.
Got it. Just a quick follow-up on that. 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 the Houston market?
Yes. You put your finger right on it. I think what we're seeing is that, and for good reasons, is that I think customers are looking, particularly in the early periods here, they're looking for an alternative. There's really no better alternative than the Houston market with the refining base that we have, with the access to the petchem 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. 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 will be around for a long time.
Thanks. We'll leave it there.
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 as purely the incorporation of the 501-G settlements you guys talked about last week, or are there some other puts and takes to think about?
Kimberly, go ahead.
There are some other puts and takes in that. You've obviously got the delay on Elba, which is an impact versus the budget. The pension expense that David talked about, which we add back that non-cash pension expense and subtract out the cash contribution for DCF. That's why you see a difference between the EBITDA and DCF. Also, impact of slightly lower commodity prices, primarily the NGL price impact on CO2.
I think the interesting conclusion is that notwithstanding those moving parts, not all of them affect DCF and EBITDA the same way. We're basically flat on DCF and slightly down on EBITDA, and we've absorbed and put behind us a significant regulatory risk that we did not budget for settlements on. Really that tells you that net, the base business is strong and overcoming a lot in the way of headwinds.
Great. Very helpful. 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. That's our project with Tallgrass, we are in customer discussions right now. We think we have a good project because it is using, in significant part, existing pipeline assets. Our Double H system, which is not something being contributed to the joint venture, but one of our WIC Medicine Bow laterals and the Cheyenne Plains system, which provide significant takeaway capacity really for three sources of supply. One is the Bakken, second is some heavy barrels arriving from Canada at Guernsey, and third is Powder River and DJ Basin barrels. There's also the PXP system that is part of the joint venture that Tallgrass is contributing. Bottom line on all that is we're offering a way to provide crude takeaway capacity with a lot of existing pipe. Only about 200 miles of new build to get to Cushing with the converted gas pipes.
Significant capacity, probably more than we would expect to contractually fill up, we're in contractual discussions right now and think we've got a good proposal for the market, not in the backlog and nothing more definitive to announce at this point.
Helpful. You could potentially have a decision this year?
That's possible.
Okay. Thanks, guys, very much.
The next question comes from Gabriel Moreen. Your line is open.
Hey, good afternoon, everyone. First question for me is just whether the backlog around Bakken G and P has shifted at all upwards since the Analyst Day. Just curious whether you've added anything there.
Yes. We have 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 take away capacity. We have added a couple of projects and call it the tens of millions ballpark to what we already had in when we did the January conference.
Okay. Thanks, Steve. 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?
Sure. Tall Cotton, as we said in the release, we've seen year-over-year growth in the production there. It's behind our plan. Frankly, we are deferring further investment decisions in there until we get a better sense for downhole conformance and other work that we'd like to do to 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.
Does oil price matter at all for that, Steve, or is it just agnostic of oil price?
No, oil price always matters. Yeah.
Yeah.
It always matters.
Okay. Thanks very much.
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 there lately. Just wondering if you'd expect that basis to stay negative and maybe even get worse over time until GCX comes online. Is there anything you can do to actually 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. We feel very good about our schedule on GCX. We 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. We don't have any special insight into forward basis and how much of that can be mitigated by producer activity. 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.
Yeah, this is nothing that isn't already out in the rags, but really two main drivers have caused the real severe negative basis that we've experienced over the last few weeks. Outages and then, well, really outages on an intrastate system and interstate system. As those come back on, things should relieve a bit. The other thing we're hearing, and again, this is in price as well, is some of the dry gas portions of the Permian are seeing some nominal shut-ins until you get more relief out of the basin. All that should improve somewhat, but it's not going to be a pretty market until we get GCX online, and then I think beyond that, I think GCX fills up very quickly, and we could be in similar situations this time next year.
Fair enough. I appreciate that color. 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. That would seem to sort of favor energy in Canada. Just curious how much of that's sort of factoring into your decision-making process in general and maybe how you view the landscape there.
Look, I think we feel good about having the terminal position that we have in Alberta with the connectivity 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, get the new business as best we can. Of course, other people have written about what they believe the implications are for the energy business, we just kind of refer to those.
Appreciate the color. Thanks, guys.
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 had cited a transaction with KMI as one of the alternatives, and that's not in the release this afternoon. Any color on why a KMI-KML transaction is 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 pipeline from the Permian. Is there any potential for Kinder to build a third Permian pipeline even potentially, just given the downstream sort of benefits on connectivity that you guys have?
Yes, there are some discussions ongoing. There's nothing to announce.
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. The short answer is yes, 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 in the other commodities out of the Permian. I don't know that it's going to be anything like that pace or that it's going to be at that pace, but there's certainly interest already in pipe three.
Okay. Thank you.
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 question. If I can start maybe a little bit more on GCX. You talk about doing everything you can for your customers. I guess I interpret that as trying to get it online as soon as possible. Some anecdotes out there 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? 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. 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. 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 for anything other than the October 1st at this point.
Sure, that's totally fair. I guess maybe a different question is, the revenue turns on when you get FERC approval to put in service, or I guess no FERC approval here?
It's not a FERC pipeline. The contracts go into service when we're able to provide the 2 Bcf of capacity that's associated with this pipeline.
Okay. My follow-up, sort of more of a blue sky question, I guess. 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 summer winter 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 not in the next couple of years, but beyond that as that volume grows?
Absolutely. Tom?
Yeah. Clearly as the market grows volumetrically the way we've talked about today, there's going to be a need for more storage over time. We and others certainly need commensurate value to expand storage capability beyond what we have today. We'll be watching that. I guess the one comment I'll make is that although the seasonal values have not really increased, in fact, probably contracted a bit if you look at it historically, we've certainly seen an increase in extrinsic value, volatility value, which if you look at the component of supply and demand, that makes a lot of sense. To the extent, the sum of intrinsic and extrinsic grows and can support future expansions. Obviously, customers have 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 grows.
Great. Would you expect it to be more salt or more sort of single turn stuff?
I think clearly with volatility being more of the component and obviously backstopping renewables, I think multi-cycle high delivery types of storage makes the most sense.
Tom's team has a lot of in Texas and 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. Having in our Texas intrastate system a significant amount of salt dome storage capability is we think an advantage as we see this play out.
Great. Thanks very much.
The next question comes from Michael Lapides from Goldman Sachs. Your line is open.
Hey, guys. Thanks for taking my question. Actually, I had two unrelated ones. One regards 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 export and inbound pipes? Are there 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. I think that it's not like there's a lot of pipe going from Corpus to Houston or other way around.
Correct.
However, there is pipe that can get to Corpus or can get to Houston. If you look at Gray Oak, for example, Gray Oak is being built all the way over to, well, it's being built to Freeport too, but also to Corpus, ultimately. It will interconnect with KMCC, which then creates a Houston option. 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 the things come on. Then, yeah, we do have expansion capability on KMCC as well.
Right. James, back to you. Can we expand them to get another 70,000, 75,000 barrels a day out of there?
Got it. Okay. My apologies. Having a hard time. I think you said about 70,000, 75,000 barrels.
Correct.
We can talk offline on that. Any change in status or thoughts about kind of the embedded call option that is Gulf LNG in terms of just next steps from here, if any?
We're going to continue to work with all of our stakeholders to find the right next steps. We did today get an approval of our EIS from the commission on the version that we filed earlier. Really there's nothing more to update or report at this point.
Got it. Thank you, Steve. Much appreciated.
The next question comes from Mirek Zak from Citigroup. Your line is open.
Hi, good afternoon. With last week's newly signed presidential executive orders, does this potentially create or renew any opportunities for you to move gas further into the Northeast? Maybe something similar to the Northeast Direct or maybe not as large, or has not enough changed perhaps on the market demand side for anything to move forward?
It's good, but not that good. 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. That's a good thing, just generally. There are a lot of things to work through in the Northeast on getting new pipeline infrastructure in place. We continue to work on those projects. NED 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 projects to do working very closely with our utility customers. We have one of those that's ongoing right now, and we're working on another.
Okay, great. Switching to the Permian here. On all your gas pipeline outlets out of the Permian, do you have any level of open or marketing capacity on any of those lines available to you that allows you to take some advantage of the low Waha pricing there? If so, can you quantify the level at all?
Yeah. Well, first of all, we do have takeaway capacity that's existing capacity out of the Permian. We do have the opportunity to take advantage of that and provide outlets for our customers. Every nook and cranny is in use.
Okay. Got you. Thank you.
By our customers.
By our customers.
Got it. Thank you.
Just a reminder, that is star one if you would like to ask a question from the phone. The next question comes from Jeremy Tonet from JPMorgan. Your line is open.
Hi, good afternoon. Just want to touch base on the environment for building pipelines in Texas and your thoughts on Texas House Bill 991 and if there's any chance of passage there. Just in general, is it getting a little bit more difficult or take a little bit more time to build pipes in Texas? Any thoughts you could provide there?
Sure. The Texas legislature is in session right now, a number of bills are being considered regarding eminent domain and modifying the existing eminent domain process. Let me put it this way. This is not a traditional landowner versus pipeline issue any longer. 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. 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. Our view is that what will emerge from that process ultimately will be a rational, properly balanced approach to eminent domain.
In the meantime, we are actively working with our landowners in order to get consensual arrangements in place, and we're using the existing process of eminent domain where that makes sense as well. We don't currently see any kind of existential threat to our projects by any stretch.
That's helpful. Thanks for that. I'm supposing you might not give a lot of color here, just trying to put your comments together as far as the impact to EBITDA guidance here. Is $50 million-$150 million of impact, is that kind of bookend what we're looking at here? Is this the right zip code or am I off in left field?
We're just going to stick with the slightly down, what that implies. It's not a material amount.
Got you. 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 outside of Houston?
Yeah. John Schlosser from our terminals group.
Yeah. It's a very small amount of our business. It's less than 3%, and it's under long-term agreement, most of it here at our BOSTCO facility. There are opportunities for a segmentation project at BOSTCO to handle both high sulfur and low sulfur. As one of the largest handlers of distillate in the United States, there's opportunities for blending there as well.
Has this helped the New York market or anything else like that?
It has not helped the New York market. Our opportunities are mostly in the Gulf Coast, there are smaller opportunities up and down the East Coast.
Got you. That's it for me. Thanks.
There are no further questions in the queue at this time.
Great. Thank you very much.