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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. All lines have been placed in listen-only mode until the question-and-answer session. Today’s call is being recorded. If anyone has any objections you may disconnect at this time.
I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.
Thank you, Kim. Before we begin, as usual, I’d like to remind you that today’s earnings releases by KMI and KML and this call include forward-looking and financial outlook statements within the meaning of the Private Securities Exchange Litigation Reform Act of 1995, Securities and Exchange Act of 1934 and applicable Canadian provincial and territorial securities laws, as well as certain non-GAAP financial measures.
Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking and financial outlook statements and use of non-GAAP financial measurement 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.
Before turning the call over to Steve and the team, let me make a few quick remarks. As you can see from our excellent 2018 results and our 2019 budget overview already released, the assets at KMI are generating strong and growing cash flow. This is obviously a very good thing but the question is how we deploy that cash in most effective way to benefit our shareholders. On that question, we get lots of suggestions from analyst and investors.
As we have said so frequently, we can use the cash for four different purposes; to pay it out as dividends; to buy-back shares; to pay down debt; and to reinvest in capital projects. Over the past three years, we have used our cash for all of those purposes in varying degrees. We have paid off over $8 billion of debt and reduced our debt-to-EBITDA ratio into our targeted 4.5 level, and had our credit rating upgraded by both S&P by Moody's. We've raised the dividend for $0.50 in 2017 to $0.80 in 2018, and reiterated our intention to increase it to $1 in 2019 and to $1.25 in 2020. We have bought back over $500 million worth of shares and we have funded our growth capital without leading to access external sources.
Now in my view that's pretty positive story. You can prevail about how the money gets allocated, but I believe investors should appreciate the overall flexibility that this strong cash flow provides. And we will continue to use our cash flow in a disciplined way that most benefits our shareholders. As we have said so many times the management and board of KMI are significant shareholders, and our interests are pari passu with the rest of the shareholder base. Steve?
Yes, thanks Rich. As usual, we will be updating you on both KMI and KML as I start with the high level overview, and then turn it over to our President, Kim Dang, to give you an update on our segment performance. David Michels, KMI CFO will take you through the numbers. Then Dax Sanders will update you on KML and we'll take your questions on both companies.
The fourth quarter capped a transformative year for KMI as we grew our business, strengthened our balance sheet, increased our dividend and continued to find attractive new opportunities to expand our network. We experienced outstanding performance in our natural gas segment, our largest segment where we saw significant year-over-year growth. We brought expansion projects online and added new project opportunities to the backlog, highlighted by our Permian Express Pipeline Project, which we outlined to you earlier in the year and which brings an additional 2 bcf a day from the Permian basin to our extensive intrastate pipeline network on the US Gulf Coast. That project, like our Gulf Coast Express Project, is secured by long-term contracts.
We experienced a record increase in natural gas supply and demand across the country, and 2019 is projected to be another solid year of growth for U.S. natural gas. That growth drives the value of our existing network and creates opportunities for us to invest capital at attractive returns to expand that network. We have solid contributions from other parts of our business as well and Kim and Dave will take you through our results. We made tremendous progress during 2018 in strengthening our balance sheet. We self-funded our expansion capital expenditures as we have since the latter part of 2015.
We also sold our Trans Mountain Pipeline and the Trans Mountain Expansion Project to CAD4.5 billion Canadian. That transaction allowed us to return substantial value to our KML and KMI shareholders, while enabling the strengthening of our balance sheet and the de-risking of both entities. A large measure as a result of that transaction, we were able to end the year with our debt to EBITDA multiple at 4.5 times candidly exceeding our goal of 5.1 times, which is what was assumed in the 2018 plans. So we had a very good 2018 and as we showed in our 2019 guidance release, we're expecting good year-over-year growth in 2019 as well.
Now we will cover -- we will be focused on our 2018 results in today's call. The timing of this call as always comes right before we do our Investor Day. We will have that next week and we'll go into the details on 2019 at that time.
With that, I'll turn it over to Kim.
Thanks Steve. Natural gas had another outstanding quarter, it was up 8%. Market fundamentals there remain very strong. For the full year, natural gas demand increased from approximately 81 bcf a day to approximately 90 bcf a day, a 9 bcf a day or 11% increase. This is driving nice results on our large diameter pipes.
For the fourth quarter, transport volumes increased approximately 4.5 bcf a day on our transmission system, a 15% growth. Deliveries to LNG facilities were over a bcf in the quarter and that's approximately 400 million cubic feet a day increase versus the fourth quarter of 2017. Power demand on our system for the quarter was up 300 million cubic feet a day and exports to Mexico on Kinder Morgan pipeline were up a little over 70 billion cubic feet per day.
Overall as Steve said this higher utilization of our system a lot of which came without the need to spend capital resulted in nice bottom-line growth in the quarter and longer-term will drive expansion opportunities. On the supply side, we're also seeing nice volume growth. On our gas and crude gathering systems, volumes were up 21% and 13% respectively, driven by higher production in the Haynesville, the Bakken and the Eagle Ford. In the Haynesville, our volumes more than doubled in the quarter and now are over just slightly over a bcf per day.
A few updates on the large projects. On PHP, we have identified opportunities to increase the capacity by about 100 million cubic feet a day and are currently working to sell that capacity. On GCX, we've secured the 100% of the runway, construction is underway and we remain on target for an October 2019 and further. On our Elba Liquefaction Project, we currently anticipate that we will be in service at the end of the first quarter. Of course this has continued to be delayed, but fortunately we do not expect the delays to have a material impact on our costs, given the way our construction and commercial contract is structured.
In our product segment, we benefited from increased contributions from Cochin, Utopia, and Double H, offset somewhat by lower contributions from KMCC due to lower contract rates on that pipe. Refined volumes were up 1%, which is consistent with the EIA. Crude and condensate volumes were up 10% and that’s due to increased volumes on our pipelines in the Eagle Ford. However, there in the Eagle Ford, as I said on KMCC, the impact of those incremental volumes was more than offset by the lower pricing and higher volumes in the Bakken, where volumes were up 38%. NGL volumes were down 11% due to unattractive product differentials. However, the lower volumes here have minimal financial impact given the nature of our contract.
Our terminal business was down 5% in the quarter. The primary driver is a weak payment from Edmonton South to Trans Mountain, and prior to the sale of Trans Mountain was eliminated as an intercompany transaction. Excluding the lease payment, the terminal segment would have been down less than 2%. Our liquids business was accounted for approximately 80% of the segment was essentially flat with expansions in the Houston and Alberta offsetting weakness from the North East. Our bulk business was down due to certain asset divestitures and lower contributions from coal, primarily due to a customer contract expiration and that’s despite higher coal volumes. Our bulk tonnage was up 10% in the quarter with the largest driver being coal volume. Coal volumes were up almost 1 million ton. Our liquid utilization was essentially flat in the quarter.
CO2 segment benefited from higher CO2 prices but that benefit was offset by lower average crude oil price and lower NGL volumes. Net crude oil production was flat versus the fourth quarter of 2017 with increased volumes at SACROC, largely offset by reduced volumes at our smaller fields. SACROC volumes were up 5% versus last year. They were 8% above our plan as we continue to find ways to access the significant remaining lower plays in that field.
Tall Cotton volumes were up 26% versus last year but below budget, and NGL volumes were down 7% in the quarter due to a planned outage, but that has since been remedied. Our net realized crude oil price was down 6% in the quarter and that’s despite a higher WTI price. The WTI hedges we have in place as well as the increase in the mid-Cush differential offset the increase in the WTI price. For 2019 as we told you previously, we substantially hedge the mid-Cush differentials.
And that’s the update on the segments. And with that, I'll turn it over to David Michels.
Thanks Kim. Today, we’re declaring dividend of $0.20 per share, which round out our $0.80 per share dividend declared for full year 2018, that’s consistent with our 2018 budget and the plan that we announced to shareholders in July 2017. It also represents 60% increase over the $0.50 we declared for 2017. We also generated distributable cash flow of 2.65 times our declared dividend for the year and KMI had a very good quarter to cap off a very strong year. We grew meaningfully from last year's fourth quarter and ended the full year nicely above plan and nicely above 2017.
In addition, as Steve mentioned, we significantly strengthened our balance sheet during the full year and that strengthening helps result in recent credit rating upgrade by both Moody's and S&P's at mid BBB each as Rich mentioned. On earnings, our revenues were up $149 million or 4% from the fourth quarter 2017 and operating costs were down $101 million or 18%. However, there were certain items both this quarter and in the fourth quarter of 2017 that create a little comparability noise. As a reminder, we define certain items as items that are recorded under GAAP that are non-cash or occur sporadically, which we believe are not representative of businesses' ongoing cash generating capability.
So excluding certain items, operating income would have been -- would be up $35 million or $3% from the fourth quarter of 2017. Net income available to common stockholders for the quarter was $483 million or $0.21 per share, which is an increase of $1.528 billion or $0.68 per share versus the fourth of 2017, a 146% increase. This very large change was driven by a reduction in our deferred tax assets taking as certain items are in the fourth quarter of 2017 as we go through the Federal tax rates cut. That’s a good example of certain items that can make it difficult to compare our business' operating performance period over period.
Looking at earnings adjusted for all certain items, this quarter we generated $565 million of adjusted earnings versus $469 million in first quarter of last year, that’s $96 million improvement or 20% better quarter over quarter. Adjusted earnings per share is $0.25, which is $0.04 or 19% higher than the fourth quarter of 2017.
Moving on to distributable cash flow, EPS per share is $0.56 for the quarter, up $0.03 or 6% from the fourth quarter of 2017. The natural gas segment was the largest driver of that growth. The natural gas segment was up $3 million or 8%, and that segment benefited in multiple parts. As Kim mentioned, EPNG and NGPL were both driven primarily by Permian supply growth. Kinder Hawk and South Texas assets were up, driven by increased volumes from Haynesville and Eagle Ford. CIG was also up through the growing DJ Basin production. Those are partially offset by lower commodity prices impacting our Highland assets and lower contribution from [geology] due to an arbitration ruling calling for contract termination.
Product segment was up $3 million, terminals were down $15 million and CO2 is down $12 million, and cover the main drivers behind the change into those segments. KMC was down -- Kinder Morgan Canada was down $50 million or 100%, and that’s due to the Trans Mountain sale, which closed in August. G&A or general administrative expenses were lower by $66 million, driven by a greater amount of overhead capitalized due to a greater amount of spending on both projects, the non-recurring expenses we incurred during the fourth quarter of 2017 and lower G&A from the sale of Trans Mountain.
Interest expense was $6 million higher driven by higher short-term interest rates, which more than offsets benefit we received from having a lower debt balance, as well as interest income earned on the Trans Mountain sale proceeds. First stock dividends were down in the quarter due to the conversion of our mandatory convertible securities occurred in October. Cash taxes were lower by $1 million, driven by higher state tax refund. Sustaining capital was $9 million higher versus 2017. Our natural gas product segment was partially offset by lower sustaining capital for the sale of Trans Mountain. That was consistent with what we budgeted, we budgeted sustaining capital for 2018 would be higher than 2017 and are ending the year relatively close to plan except for the Trans Mountain sale.
Total DCF of $1.273 billion is up $83 million or 7%, driven by greater contributions from natural gas, lower G&A expenses and lower preferred stock dividend, partially offset by the sale of Trans Mountain and higher sustaining CapEx. DCF per share was up $0.56 per share, up $0.03 or 6%, same main drivers as DCF but with partial effect on the incremental shares from the conversion of our preferred stock. For the full year of 2018 versus 2017, DCF was up $248 million or 6% and DCF per share was $2.12 per share or $0.12 and 6% above 2017 compared to full year 2018. For the full-year relative to budget, DCF of $4.730 billion was up $163 million or 4% from our budget for the year, and our DCF per share of $2.12 was up $0.07 from our budget of $2.05 and 3% higher. So very nice performance for the full-year versus plan as well, especially considering the sale of Trans Mountain and had budgeted all the liquefaction of NGL differential we receive.
Now turning to the balance sheet, just like last quarter, you are going to see two net debt-to-EBITDA figures. The 4.4 times includes all of the Trans Mountain sale proceeds as we consolidated all of that cash from KML's balance sheet on to KMI. Including the cash, I would say to KML public shareholders on January 3rd, which is estimated at the end of the year of $890 million, our adjusted net debt-to-EBITDA was 4.5 times [indiscernible]. That 4.5 is a little bit better than last quarter of 4.6 with much improved year-end 2017 at 5.1, as well as the 5.1 we budgeted for the full year of 2018.
Obviously, Trans Mountain sales was the largest driver of that improvement, and proceeds have now been distributed to both KMI and to the public KML holders. We used a portion of our share to pay down a little more than $400 million that we had on our revolver and we've included most of the remainder of to fund a $1.3 billion bond maturity that’s coming up here in February. Two largest changes on the balance sheet to note here are from year-end our cash and PP&E, and both of those are largely driven by the Trans Mountain sale. Net debt ended the quarter at $34.2 billion, an increase of $2.5 billion from year-end and a decrease of $400 million from last quarter, while reconcile of those in [Q3].
Quarter change, we had $1.27 billion in DCF, we spend $586 million in growth CapEx contributions to our joint ventures and dividend of $455 million we repurchased $23 million of shares, we had a growth capital source of $184 million, which is largely driven by tax refund we did in the quarter, approximately $400 million reduction for the quarter. For the full year, the $2.5 billion lower debt driven by $4.7 billion of our DCF, growth CapEx and JV contribution is $2.57 billion, $1.6 billion of dividends, $273 million of share repurchases. But the divestiture of proceeds mostly because of Trans Mountain at $3.4 billion less the KML public shareholders' portion of those proceeds of $890 million and then we had a working capital use of $300 million, which was largely driven by our late refund payments that we have reconciled to $2.5 billion lower [debt].
And with that, I'll turn it back to Steve.
Okay, now we're going to turn to KML and Dax Sanders will give you the updates.
Thanks Steve. Before I get into the results, I do want to update you on a few general items. First as in the release mentioned, we made the promised return of capital distribution associated with Trans Mountain sale on January 3rd. More specifically, we distributed almost $1.2 billion to KML restricted voting shareholders for approximately $11.40 a share. We also completed a 3:1 reverse stock split that was approved at the shareholders' meeting last November.
With respect to the sale of Trans Mountain, you will recall that the agreement calls for a customary final working capital adjustment. We are substantially through that process and the review of the calculation with the Government of Canada, and believe that the final adjustment will result in us making a final cash payment back to the Government of approximately $35 million in the first quarter and as such, we have booked this amount. This adjustment should not be viewed as a lowering of the purchase price or an otherwise change to the economics of the deal rather it simply reflects that at closing we deliver less cash to the government than was contemplated. Consequently, and as I'll walk you through in a minute, this will not have an impact on the previously communicated net cash and net debt position of KML.
Moving to the business front, this is the first quarter where baseline was essentially in-service for the entire quarter and it contributed nicely to the portfolio. As of the end of the year, we have spent approximately $348 million of our share with just over $8 million remaining with the total project spend with our share of $357 million. The $357 million compares to the original estimate of $398 million and as I have mentioned previously, it is a result of cost savings on the project.
Finally, a topic that I know is on everybody's mind is KML's ongoing strategic review. While we don't have anything to announce since the review is ongoing, we are hopeful that we will have the review completed in direction to announce by the next earnings call. While this review is taking some time, the time we are taking is necessary given the range of options and cross border complexity, the fact that a strategic combination or sale of the company are among the options and the evaluation of those options require third-party price and term discovery and that process takes time.
Now moving towards the results and of note, as I talk to the results, I'm generally only going to reference results of continuing operations as we believe those are much more useful and relevant. Today, the KML Board declared a dividend for the fourth quarter of 0.1625 per a split adjusted restricted voting share of $0.65 annualized, which is consistent with previous guidance. Earnings per restricted voting share from continuing operations for the fourth quarter of '18 are $0.30 and that is derived from approximately $40 million of income from income continuing operations, which is up approximately $22 million versus the same quarter in 2017. The biggest contributors to the increase are strong revenue associated with baseline tank and terminal coming online and interest income associated with proceeds from the Trans Mountain sale.
I do want to offer one comment on the almost $28 million loss of discontinued ops, that is due almost entirely to the $35 million payment on Trans Mountain that I mentioned. Adjusted earnings from continuing operations, which exclude certain items, were approximately $43 million compared to approximately $18 million from the same quarter in 2017. Total DCF from continuing operations for the quarter is $62.9 million, which is up $28.7 million from the comparable period in 2017. That provides coverage of approximately $13 million and reflects a DCF payout ratio of approximately 31%, which is obviously somewhat skewed from the interest income.
Looking at components of the DCF variance, segment EBITDA before certain items is up $9.9 million compared to Q4 '17 with the pipeline segment up approximately $6.1 million and the terminal segment up approximately $3.8 million. The pipeline segment was higher primarily due to the recognition of efficiency revenue on Cochin and the non-recurrence of an inline inspection done in Q4 2017. The terminal segment was higher due primarily to Base Line coming on line as the asset was not in service in 2017 and higher contract renewals rates at the North 40, partially offset by the expiration of the contract on the Imperial JV and the onetime nature of the capital true up via the same asset in 2017.
G&A is essentially flat. Interest is favorable by approximately $24.7 million due to the interest on the Trans Mountain proceeds and lower interest expense. The cash tax line item was essentially flat. Preferred dividends were up $2.6 million given Q4 2018 had both projects outstanding for the fourth quarter [indiscernible]. Sustained capital was unfavorable approximately $3.6 million compared to Q4 '17 due to timing and support on both Cochin and within the Terminal segment. Looking forward to 2019, as with last year, I'll walk you through the details of KMLs budget at the analyst conference next week.
With that, I'll move onto the balance sheet comparing year-end 2017 to 12/31/18 and my comments will focus only on the line items related to the retained assets and not the assets or liabilities held for sale. Cash increased approximately $4.227 billion to $4.338 billion, and as I mentioned last quarter, there is a lot of moving pieces and the change associated with Trans Mountain stem from the CapEx spend on behalf of government, the government credit facility and other purchase price adjustments such that I’m not going to take you through all on this call. But if you want more details, feel free to give us a call. Generally, the increase is the proceeds received from Trans Mountain plus DCF generated less expansion capital, less distributions paid net of growth and less the payoff of the debt we had when we received the sale proceeds.
More importantly, let me take you through the pro forma reconciliation of what that year-end cash balance looks like, taking into account immediate uses of the Trans Mountain proceeds following year-end. Starting with the $4.338 billion in cash, approximately $3.977 billion is paid out with special distribution on January 3rd that’s the sum of the 1.195 distribution payables to restricted voting shareholders and the 2.782 billion distributions payable to KMI, both shown on the balance sheet. That’s approximately $308 million of cash taxes from the gain on the sale will be paid in Q1. Finally, you deduct the $35 million final adjustment back to Canada that I have mentioned. Getting all those items leaves you with the net cash position obviously with no debt of approximately $18 million. This is consistent with the comments we have previously about KMI having little or no net debt after taking into account all the moving pieces associated with Trans Mountain sale on associated distributions.
Other current assets increased approximately $2 million due to an increase in AR associated with Base Line coming online, transition services agreement billing from Trans Mountain and interest receivable from interest on the Trans Mountain proceeds. Net PP&E decreased by $7 million as a result of depreciation in excess of net assets placed in service. Deferred charges on other assets decreased to approximately $63 million as a result of write off of the unamortized debt issuance cost associated with Trans Mountain facility that we canceled.
Moving on to the right hand side of the balance sheet, as I mentioned, distributions payable and distributions payable to related parties increased 0 to 1.2 and 2.8 billion respectively as reflected with special distribution. Other current liabilities increased $337 million, primarily due to taxes payable on the Trans Mountain sale. Other long-term liabilities decreased by $283 million, primarily as a result of the deferred tax liability release as a result of the gain on Trans Mountain sale.
And with that, I will turn it back to Steve.
Okay, thanks Dax. We want to take a moment to honor our late General Counsel, Curt Moffatt, who passed away on December 28 while skiing with his family. In addition to being a fine lawyer, Curt was a fine human being and deep personal connections with the people he worked with. We lost a trusted colleague, but many at Kinder Morgan also lost a friend and a mentor. Curt loved this work and his heart shown through with it. We'll miss him.
Okay. With that, Tim, if you will come back on, we will take questions. Like we did last time, as a courtesy to everyone who has questions, we ask that you ask one question -- that you hold yourself to one question and one follow up. And if you have more questions, we will get to them. You just get back in the queue and we will take you up in due course. Thank you.
[Operator Instructions] And our first question comes from Jeremy Tonet with JPMorgan.
Just want to start off here on the CO2 segment and taking in account some of the volatility we've seen in commodity prices here. Just wondering how of the $5.7 billion in the backlog relates to the CO2 segment. And does the commodity price environment impact I guess the pace or how you think about that spend given this volatility?
So in the CO2 segment, we got about $1.6 billion of backlog and we'll go through this in more detail on the conference. And yes, CO2 and also in our gathering and processing business, we will get CapEx on an ongoing basis. So we take into account commodity prices and obviously the breakeven economics with the return for the projects that we look at. So we typically will have ins and outs in both of those segments. And obviously, if commodity prices are lower they tend to be out. So the main topic there is Tall Cotton and we will continue to evaluate Tall Cotton, and whether we make substantial additional investments in there and the year goes on.
And just want to touch on SG&A, and it just seem down 40%, $67 million here year-over-year. It seems like a big step down, and it seems like some of that’s relate to growth CapEx and capitalization there. But just wondering if you could provide a little bit more color on that? And is this a new run rate or is the run rate something lower, or any more color you could provide would be helpful? Thanks.
That’s right, a good bit of it does relate to capitalization. But David, do you want to go through that?
About half of it is capitalization. We had greater burnable capital spend in the year of about $300 million relative to the prior year we put a reasonable capitalization rate on that and would get to around $30 million of greater capital SG&A cost. So a lot of that was driven by GCX, which is a pretty major project, Elba liquefaction spend. And so we had a couple of major projects as a percentage here as well as all of our ongoing projects as well. And then a big chunk of that also was one time G&A cost that we had in 2017 and it was really is a result of an internal policy change, which allows more paid time off to be carried over to the subsequent year and then of course we had lower G&A cost in 2018 as we go from Trans Mountain.
So 130 is more of a real run rate G&A going forward the way to think about it?
Well, depending on the capital -- the level of the capital spend, [indiscernible]…
And we'll show you our G&A budget for 2019 at the conference next week.
And just my first question just to confirm real quick, 1.6 CO2 is of that 5.7, that's the right way to think about that for the backlog?
And almost all of the remainder is in natural gas.
Thank you. And our next question comes from Colton Bean with Tudor, Pickering, Holt & Co.
So you mentioned the improved results there in the Permian network. Is that primarily a result of throughput, or are you still seeing some further increases in negotiated rates? And I guess just as a follow-on to that when you bring GCX in the service later this year. Is there any potential for rate improvement on maybe the Tejas network there in South Texas?
Yes, so I guess first part of the question, yes, it is improvement in ultimately the rates that come-up for renewal. And I think on the second part just as more gas comes into the State of Texas dispersing that across our network, both for domestic consumption and export demand. I think there are some opportunities, which create so many contracts that have renewal options.
Then I guess just on the proposed joint venture with Enbridge and Oiltanking for the coal terminal. Just any thoughts as to how that project integrates with the existing footprint and whether there might be some ancillary opportunities if you were to reach FID there?
So additionally, there is not integration the initial size that we would expect. And again, this is not in our backlog, this is something that we are working on with our partners and we're in development on. And before we would put it in our backlog, we would need to see substantial commitments from shippers. In the early part of the project, we would -- the first bill, we wouldn’t expect to necessarily see it but we could add connectivity in larger bills to KMCC.
Thank you. Our next question comes from Danilo Juvane with BMO Capital Markets.
My first question is on BHP with a little uptick in capacity the 100 million. I was under the impression that you already capped out in terms of MAOB. What were you able to do to get this incremental 100 million squeezed out, and can you do the same things at GCX?
Well, when we ordered compression, we upsized the compression order. So it was a long lead time item and we though there is market for it if we can squeeze some more out. And so we ordered a larger compression with the large capacity compression equipment. And GCX will look for little pockets here and there, but I would say tapped out there.
And my second question is sticking on the pipes, obviously, what's happening with PG&E in California will be yet to come up with respect to having I think -- and we understand the [$5 million] of contracts. How should we think about that? Has the potential for bankruptcy unfolds there? Are those contracts tied to assets that are base load and month to month, how are you guys thinking about that process...
I think there's some -- there's always uncertainty in a bankruptcy proceeding, but I think there's some cause for optimism. Let me first -- around the Ruby contracts in particular, let me first start out by pointing out that it is Ruby specifically and exclusively that would be impacted by the potential of PG&E bankruptcy, so two contracts. One of those contracts serves the electric generations that PG&E uses to obviously generate power and service load. The other provides service to PG&E's gas distribution business. So we view both of those as core -- or contracts that are core to PG&E's business. So those two contracts together represent about $93 million a year of demand revenue. So it is a material matter to our interest in Ruby.
Again, while the bankruptcy process is uncertain there's important facts. One is what I said that they serve PG&E's core business. These contracts are used by PG&E and we've been told to expect continued utilization of those contracts. These contracts help PG&E meeting its service obligation to core customers. The contracts were approved by the CPUC when they are entered into. The CPUC does require PG&E to maintain upstream firm transport capacity. And so those reliability aspects we think help improve the chances of affirmation. Again, process is uncertain. And I'd also say those reliability aspects were confirmed recently with the GTN outage and diminished capacity there, which caused an increase it takes on the Ruby contracts.
So even though the current basis is lower and below the long-term contract rate, there are reliability benefits to be considered. And finally, it's our understanding at least that prior -- PG&E's prior bankruptcy proceeding, they did not reject firm transport contracts. So that's not proof of what they'll do this time, but we think there are reasons for optimism with these contracts.
Thank you. And our next question comes from Spiro Dounis with Credit Suisse.
Just want to start off with 2019 CapEx guidance. Looks like cash flows should fund the majority of that and dividends, but looks like I think back into number about $400 million hole to make up somewhere else. Should the remaining CapEx -- should the assumption be that basically funded with debt at this point, or could we see some non-core asset sale there?
Those are not really linked we would look at those individually. But at these numbers, there would be an expectation of some small debt financing. So we would be financing more than all of the equity requirement as a substantial portion of the debt requirement for those capital investments. And again we'll take you through that in next week's conference.
And there's plenty of availability on our revolver.
And then just wanted to touch base again on the Bakken, on your latest thoughts around expanding Double H, now that the projects have been announced, I think there's 300,000 barrel a day open season on the Express Liberty pipeline announced 350,000 barrels in season two, so call it, 650,000 needs to get down to during this somehow if both of these go through. Just curious what that means for Double H here?
Yes, that’s something that we are actively looking at. Volumes continue to grow and we continue to work on solutions for our customers to get them through Cushing. And there is some expansion capability on Double H.
Our next question comes from Harry Mateer with Barclays.
First, just a follow up on Ruby. How should we think about the indemnification agreement that’s in place from KMI on 50% of Ruby's debt? And then just to clarify Steve, have you even talked since the recent bankruptcy headline, or is that you should continue to expect utilization of those gas supply contracts?
First, the indemnification no longer exists. And second, we are in pretty continuous conversations with our customers.
And then David, you mentioned the KMI plans to pay down the February maturities. So I know the Analyst Day is next week. But can you just give us a sense for how you are planning to manage the timing and/or magnitude of new debt issuance for the balance of the year? Or should we just assume late in 2019 given the bond maturity that comes due in December?
We will provide more on that during the Analyst Day, but no near term needs because of the cash we have on hand.
Our next question comes from Tristan Richardson with SunTrust.
Just curious on the projects added to the natural gas backlog in 4Q. Could you give us some highlights there where that is either geographically or around the chain, whether it'd be midstream or transmission in general regions?
So it's probably half midstream, which part of that is on our intrastate system other on the GMP side, and the other half I would say is supporting the LNG projects yet to come.
And then just a quick follow up and you talked about the following up on previous question on the Bakken, the volume growth you saw there. And seems like utilization today and whether or not there is further headroom for growth on the existing asset base or the potential for expansion would require capital?
So we are investing in our gathering assets in the Bakken, because they are constrained. And so we have investments to expand our takeaway capability there gas and crude. To get more out of Double H, we would have to expand it. We would have to invest capital in it.
Our next question comes from Dennis Coleman with Bank of America Merrill Lynch.
Couple of questions, one if I could go back first to the KML strategic review, maybe this is reading a little bit too much into what I'm hearing. But Dax seemed like you emphasized that the options you listed were just among the options that are available. And I wonder if you might talk about what you mean by that or what other options we should be thinking about?
I think the options that are table are all the ones that we've articulated before. KML has good set of assets that can continue as the going concern. It could be one of the strategic transactions that I talked about. It could come back to KMI. So, I think all of the options that there is not anything new that we have previously spoken about. And I think we’re going to be very through in thinking about every single one of those and which one makes the most sense.
Okay, that’s what I -- there is nothing new there that hasn’t been. And then I guess just to dig a little bit deeper on the terminals decline, I understand the Edmonton Terminal. But the other thing that’s talked about in the releases is the New York Harbor issues. I wonder if you might just expand upon that a little bit. And is it a one-time thing, is it season, or is there some impact on the business that is more permanent?
It's the same issue that brought up last time, it's Staten Island. We’re roughly 60% utilized there. We've done a great job over the last two quarters of getting our head back above water but we’re looking at strategic alternatives for the site at this point. And we're hoping that we'll have clarity on that in Q2 and we'll be able to indicate it on the next earnings call.
But the reason that Staten Island is uniquely impacted is because there [indiscernible] and access…
13.75% on every barrel that goes through there, which makes it -- renders it uncompetitive with New Jersey terminals, our will be two of them…
Our next question comes from Jean Ann Salisbury with Bernstein.
Is the government shut down having any impact on your actions with FERC, either the federal LNG process or on the pipeline permitting and approval side?
No, FERC is funded and so the answer there is no. I mean, I think this is separate question about how a deadlocked commission will operate on certain things. But the answer is no. And more broadly, Jean Ann, the government shutdown is not having really much of any impact on it right now. In time with U.S. commission wild life not funded, it could have some impact on permitting but nothing that’s constraining its critical path, nothing that’s on a critical path currently. It's not having much of an impact on us at this point.
And then another question, it seems like there is some debate about whether Permian gas pipeline have good returns. You have a slide in your appendix of the last Investor Day, which shows a multiple in line with or better than your average, but I think some others that proposed the projects have said that mix of returns in duration didn’t meet their bar. Can you just clarity the Permian gas pipe projects that you're working on in line with your backlog average? And are you comfortable with the duration of the projects and just any other color?
We’re getting these projects under contract at attractive returns with long-term contracts. And so they're good double-digits unlevered after tax returns and if not a 15% unlevered after tax return but there are good solid returns. And I agree with the observation just generally, I mean we looked at other opportunities out in the Permian crude and otherwise and we haven’t been able to find the return levels that we would require to participate in that. But we're satisfied with the returns and their in-line returns on our gas transportation expansion projects out of the Permian.
This does have with what we said again in the call, which is we are using a disciplined approach as to how we allocate our capital. So we are not chasing deals that don’t make the bottom sense for Kinder Morgan.
Thank you. Our next question comes from Robert Catellier with CIBC Capital Markets.
I just wanted to ask what is the impact on operations from the production curtailments in Alberta?
The contracts that we have are take or pay there and then they're monthly warehousing charge so we have not seen an impact.
But you're not -- I understand that take or pay wouldn’t see an impact there. But operationally, are you seeing anything any different…
No, we actually in our Alberta crude terminal, we had record volumes in the fourth quarter. We have been averaging 77,000 a day. We had 146 in the fourth quarter and in December we were up to 168 and hitting all time one day high of 265. So volumes have been very strong. Now, we have seen it fall off a little bit in January as we would have expected but it had no impact on the bottom line.
And then if I could the net interest impact on the Trans Mountain sales proceeds that impact on the DCF for KML. What I'm trying to extract is the interest income specifically related to the proceeds versus other interest expense you might have?
Yes, I think you can assume we had what we paid-back for the quarter, we didn’t have any debt drawn during the quarter for KML.
No, it's how much of interest income or is it with DCF…
So I think it's the 24.7, it's the full amount there. So I am saying that total amount, we didn’t have any amounts during that piece, so the full amount is the…
And that's for pretax or post tax amount, 24.7…
That’s [pretax] amount…
Thank you. And our next question comes from Michael Lapides with Goldman Sachs.
Can you quantify what the impact on volumes being move towards Mexico was that in your system either for the quarter or for the full-year?
Impact on volumes moved to Mexico…
Yes, or volumes directed to Mexico through your system. I'm just trying to get a gauge of whether your system is seeing a material benefit yet and if not now when?
So we moved 73 million cubic feet a day incremental to Mexico on our system during the fourth quarter versus the fourth quarter of '17.
So it's relatively small relative in the grand scheme of things?
That's incremental…
We're in excess of 3 bcf a day on average.
Thank you. And our next question comes from Chris Sighinolfi with Jefferies.
I guess following on the question -- the last question. I just want to ask about export trends you are seeing on the refined product side. It looks with rush of articles recently about growing gas prices to Mexico with efforts where government cracks down on pipeline sub. So curious if at all how that's impacting you and how that seems might be responding.
We had record volumes on the ship channel from an export standpoint. We were up almost 8.5% from a volumetric standpoint over our ship docks and 10.1 on total volume so very, very strong movement on the gasoline and diesel over our docks. In Houston alone, gasoline was up 8% and distillates were up 6%.
Those figures, are those 4Q numbers you're reporting or are those full year?
Full year numbers…
And has that changed in August, we're very early in the New Year but it seems like a lot of this has escalated once the calendar turns. Just curious if the conditions there have altered in any way.
No, the only thing we've seen a little more of is we're seeing more volume move via rail out of our former crude by rail facility, which is now been repurposed to handle gasoline and distillates and that's starting to ramp up, and that’s all Mexico.
Our next question comes from Eric Beck with Citigroup.
Just a quick one from me, in the CO2 segment, the mid-cush differential that you have to hedge mostly for 2019. Are those levels fairly similar to what we saw in fourth quarter?
It's roughly $8 a barrel.
And just one quick follow-up, regarding the acquisition of the [indiscernible] Field. Are you looking to potentially do additional acquisitions of this type going forward, or might that depend on how you see Tall Cotton develop over time?
That was a bit unique given its relationship to our SACROC field and our ability to use that field for multiple purposes. Meaning it produces oil and NGL, but also the CO2 that it uses could be perhaps better used elsewhere in our portfolio and perhaps offsetting capital investments that we might make in order to expand CO2 production. So I would call it somewhat unique, but it's an example of the things that we look out for and things that -- and that integrate well with our existing operations.
Our next question comes from Becca Followill with U.S. Capital Advisors.
Two questions, one given that you're in settlement discussions on EPNG and pre-settlement on Tennessee. Any change to the guidance you've given for roughly $100 million impact over time and no impact in '19?
No change -- yes, we're early in those discussions. We're encouraged to be engaged on those two systems but we don't have any update in our guidance or outlook there. I think the $100 million is still good from our perspective, it reflects the tax only component of that. And we'll just have to see where the discussions come out. But we prefer this environment, we've traditionally been able to work things out with our customers and we would rather be doing it here than in a FERC process, so we're happy to be engaged on both of those systems.
And then back to Ruby, can you remind us of the structure there? I think Pembina has a preferred and so that carves off a big chunk of the EBITDA. So if by chance PG&E were to abrogate or to re-cut that contract. Would that disproportionally hit KMI?
It would disproportionally hit KMI. And you're correct, Pembina's interest is the preferred and that’s why as I said, it is a material matter to our interest and Ruby. But as I also said, we think that there is reason to be optimistic about these contracts.
Our next question comes from Danilo Juvane with BMO Capital Markets.
Couple of quick follow-up questions for me, firstly on KML. Are there any major second points that may cause a potential slippage beyond the next earnings call?
There is always a potential for that. But I think we feel like we will be able to give you an update at the next earnings call.
Yes, I think that’s right. That's our estimated time. It takes on and we feel like we will have an answer about that one.
And as a follow up to Jean Ann's question on the Permian pipeline returns. The 6 times multiples that you have outlined before. Is that over the course of the 10 year contract duration?
Yes, what that is showing, I think we stated the same way and all these are 6 times the second year in EBITDA multiple, and the contracts -- the underlying contracts are for 10 years. And when we make the decision of the project investment, we are careful to look at a variety of terminal value assumptions to make sure that we are satisfied with returns that we are getting on our capital in a variety of scenarios.
Our next question comes from Jeremy Tonet from JPMorgan.
Just a quick little follow up, I want to touch base in Elba here. I was wondering if you could expand a little bit more and the drivers to the delay. And I think it was during first quarter you said before now end of first quarter, you guys feel comfortable with the timeline. Or what's happened there exactly?
Yes, so the delay continues to be associated with contractor productivity. We are obviously getting into the final days here. We have people on the ground watching the progress that we are making. We are in commissioning activity simultaneous with the completion of the project. And so we think end of Q1 is a good and reasonable estimate for when it will be compete. There is obviously a band of uncertainty around that date, but we think we are closing in on it here.
At this time, I'm showing no further questions.
Great. Well, thank you all very much for spending time with us, and we will see most of you next week at the Investor Day. Thank you.
Thank you. This concludes today's conference. You may disconnect at this time.