Kinder Morgan Inc - Class P (KMI) — Q4 2018 Earnings Call Transcript

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 the use of non-GAAP financial measurements 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 the most effective way to benefit our shareholders. On that question, we get lots of suggestions from analysts 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 and Moody's. We've raised the dividend from $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 excessive external sources. Now in my view, that’s a pretty positive story. You can debate 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 aligned with the rest of the shareholder base. Steve?

Thank you, Rich. As always, I will provide an overview of both KMI and KML, then hand it over to our President, Kim Dang, for an update on our segment performance. David Michels, KMI CFO, will present the financial numbers, followed by Dax Sanders who will discuss KML, and then we will address your questions regarding both companies. The fourth quarter concluded a transformative year for KMI as we expanded our business, improved our balance sheet, increased our dividend, and continued to explore new opportunities for network expansion. Our natural gas segment, the largest one, showed exceptional year-over-year growth. We launched expansion projects and added new ones to our backlog, notably the Permian Express Pipeline Project, which we discussed earlier in the year, bringing an additional 2 bcf a day from the Permian basin to our extensive pipeline network on the US Gulf Coast. This project, similar to our Gulf Coast Express Project, has long-term contracts in place. We saw a record rise in natural gas supply and demand nationwide, and 2019 is expected to be another strong growth year for U.S. natural gas. This growth enhances the value of our current network and gives us chances to invest capital at attractive returns for its expansion. Other areas of our business also contributed effectively, and Kim and Dave will discuss our results. In 2018, we made significant strides in strengthening our balance sheet. We self-financed our expansion capital expenditures as we have done since late 2015. We also sold our Trans Mountain Pipeline and the Trans Mountain Expansion Project for CAD 4.5 billion. This deal allowed us to provide substantial value to our KML and KMI shareholders while strengthening our balance sheet and reducing risks for both entities. Consequently, we ended the year with a debt to EBITDA multiple of 4.5 times, exceeding our target of 5.1 times assumed in our 2018 plans. Overall, we had a very successful 2018, and as indicated in our 2019 guidance release, we anticipate good year-over-year growth for 2019 as well. Today’s call will focus on our 2018 results. The timing of this call, as per usual, is just before our Investor Day next week, where we will delve into the details for 2019. With that, I'll pass it on 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 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 100% of the runway, construction is underway and we remain on target for an October 2019 completion. 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 accounted for approximately 80% of the segment and was essentially flat with expansions in Houston and Alberta offsetting weakness from the Northeast. 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 tons. Our liquid utilization was essentially flat in the quarter. The CO2 segment benefited from higher CO2 prices, but that benefit was offset by lower average crude oil prices 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, 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 hedged the mid-Cush differentials. And that’s the update on the segments. And with that, I'll turn it over to David Michels.

Thank you, Kim. Today, we are announcing a dividend of $0.20 per share, bringing our total dividend for the full year 2018 to $0.80 per share. This aligns with our 2018 budget and the strategy we communicated to shareholders in July 2017. It shows a significant 60% increase over the $0.50 we declared for 2017. We also achieved distributable cash flow that was 2.65 times our declared dividend for the year, and KMI had a strong quarter that capped off an overall successful year. We saw significant growth compared to last year's fourth quarter and finished the year well above our expectations and those of 2017. Additionally, as Steve pointed out, we made considerable improvements to our balance sheet throughout the year, which contributed to recent credit rating upgrades from both Moody's and S&P, now rated at mid BBB. Our revenues increased by $149 million or 4% from the fourth quarter of 2017, while operating costs decreased by $101 million or 18%. However, certain factors in this quarter and in the fourth quarter of 2017 affect comparability. We designate certain items as non-cash or sporadic expenses recorded under GAAP, which we believe do not accurately reflect our business's ongoing cash-generating ability. Thus, excluding these items, operating income would have increased by $35 million or 3% compared to the fourth quarter of 2017. Net income available to common stockholders for the quarter was $483 million or $0.21 per share, reflecting an increase of $1.528 billion or $0.68 per share compared to the fourth quarter of 2017, marking a 146% rise. This substantial increase was largely due to a reduction in our deferred tax assets resulting from certain items in the fourth quarter of 2017 as we adapted to federal tax rate changes. This illustrates how certain items can complicate the comparison of our business's operating performance over time. Looking at adjusted earnings, we generated $565 million this quarter, compared to $469 million in the first quarter of last year—representing a $96 million improvement or a 20% increase quarter over quarter. Adjusted earnings per share stood at $0.25, which is $0.04 or 19% higher than the fourth quarter of 2017. Regarding distributable cash flow, earnings per share were $0.56 for the quarter, up $0.03 or 6% from the fourth quarter of 2017. The natural gas segment was the primary driver of this growth, increasing by $3 million or 8%, benefiting from various factors. As Kim noted, EPNG and NGPL experienced growth mainly due to Permian supply expansion. Kinder Hawk and South Texas assets increased, fueled by higher volumes from Haynesville and Eagle Ford. CIG also showed growth from rising DJ Basin production, although this was partially offset by lower commodity prices affecting our Highland assets and reduced contributions from geology due to an arbitration ruling that mandated contract termination. The product segment rose by $3 million, while terminals fell by $15 million and CO2 decreased by $12 million, which highlights the main shifts in those segments. Kinder Morgan Canada saw a decline of $50 million or 100%, resulting from the Trans Mountain sale that closed in August. General and administrative expenses dropped by $66 million, attributed to a higher volume of capitalized overhead from increased project spending, non-recurring expenses from the fourth quarter of 2017, and reduced G&A due to the Trans Mountain sale. Interest expenses rose by $6 million due to higher short-term interest rates, which offset the advantages gained from a lower debt balance and interest income from the Trans Mountain sale proceeds. First stock dividends decreased in the quarter due to the conversion of our mandatory convertible securities that happened in October. Cash taxes were reduced by $1 million due to a larger state tax refund. Sustaining capital was $9 million higher compared to 2017. Our natural gas product segment was partially balanced by lower sustaining capital following the Trans Mountain sale. This aligns with our budget forecasting for 2018 being higher than in 2017, and we are concluding the year fairly close to our planned figures except for the impact of the Trans Mountain sale. For total distributable cash flow of $1.273 billion, we noted an increase of $83 million or 7%, driven by increased contributions from natural gas, reduced G&A expenses, and lower preferred stock dividends, partially countered by the Trans Mountain sale and higher sustaining CapEx. Distributable cash flow per share reached $0.56, up $0.03 or 6%, with similar main drivers affecting distributable cash flow but with partial effects from incremental shares due to preferred stock conversion. For the full year of 2018 versus 2017, distributable cash flow increased by $248 million or 6%, and per share it was $2.12, marking an increase of $0.12 or 6% over 2017. Relative to our budget, 2018's distributable cash flow of $4.730 billion was $163 million or 4% above budget, and our DCF per share of $2.12 was $0.07 higher than budgeted at $2.05 or 3% higher. This performance is commendable for the full year against planned figures, especially with the Trans Mountain sale and the budget expectations for liquefaction of NGL differentials. Turning to our balance sheet, similar to last quarter, we are reporting two net debt-to-EBITDA figures. The 4.4 times figure includes all proceeds from the Trans Mountain sale, as we consolidated that cash from KML's balance onto KMI's books. Including cash anticipated from KML's public shareholders on January 3rd, estimated at $890 million at year-end, our adjusted net debt-to-EBITDA stands at 4.5 times, slightly improving from last quarter's 4.6, compared to 5.1 at year-end 2017 and the 5.1 we budgeted for the entirety of 2018. The Trans Mountain sale was the primary factor behind that improvement, and proceeds have been allocated to both KMI and public KML shareholders. We have utilized a portion of these proceeds to reduce over $400 million in our revolver and most of the remainder is being used to finance a $1.3 billion bond maturity due in February. Two notable changes on the balance sheet since year-end are cash and property, plant, and equipment, both largely driven by the Trans Mountain sale. Net debt concluded this quarter at $34.2 billion, which represents an increase of $2.5 billion from year-end but a decrease of $400 million from the last quarter, reconciling previous changes in Q3. Quarter-over-quarter, we reported $1.27 billion in distributable cash flow; we allocated $586 million to growth CapEx contributions and distributed $455 million in dividends; we repurchased $23 million in shares; and we obtained $184 million from growth capital primarily from tax refunds received during the quarter, culminating in a $400 million reduction for the quarter. Over the full year, we achieved a $2.5 billion reduction in debt attributable to $4.7 billion in distributable cash flow; growth CapEx and joint venture contributions totaled $2.57 billion; dividends amounted to $1.6 billion; and $273 million was spent on share repurchases. However, proceeds from divestitures, mainly from the Trans Mountain sale, accounted for $3.4 billion less the $890 million allocated to KML public shareholders, along with a $300 million reduction in working capital largely due to late tax refunds, reconciling with the overall $2.5 billion debt reduction. 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 the 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 delivered 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 and a 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 requires 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 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 operations; 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 Baseline coming online as the asset was not in service in 2017 and higher contract renewal rates at 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 of 2018. 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 KML's 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 are a lot of moving pieces and the change associated with Trans Mountain stem from the CapEx spend on behalf of the government, the government credit facility, and other purchase price adjustments such that I’m not going to take you through 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 payable 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 the Trans Mountain sale and associated distributions. Other current assets increased approximately $2 million due to an increase in AR associated with Baseline 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 writing off the unamortized debt issuance cost associated with the 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 to $1.2 billion 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 the Trans Mountain sale. And with that, I will turn it back to Steve.

Thank you, Dax. We want to take a moment to remember our late General Counsel, Curt Moffatt, who passed away on December 28 while skiing with his family. Curt was not just an excellent lawyer, but also a remarkable person who formed deep personal connections with his colleagues. We have lost a trusted colleague, and many at Kinder Morgan have also lost a friend and mentor. Curt was passionate about his work, and his dedication was evident. We will miss him. Now, Tim, if you could rejoin us, we will start taking questions. As a courtesy, we ask that everyone limit themselves to one question and one follow-up. If you have more questions, please return to the queue, and we will address them in due course. Thank you.

Just want to start off here on the CO2 segment and taking into account some of the volatility we've seen in commodity prices here. Just wondering how 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 as the year goes on.

And just want to touch on SG&A, and it just seems down 40%, $67 million here year-over-year. It seems like a big step down, and it seems like some of that’s related 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, which 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, and 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 as 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 costs in 2018 as we go from Trans Mountain.

So $130 million is more of a real run rate G&A going forward is the way to think about it?

Well, depending on the level of the capital spend...

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 billion in CO2 is of that $5.7 billion, that's the right way to think about that for the backlog?

And almost all of the remainder is in natural gas.

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 an 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 at 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 wouldn’t expect to necessarily see it, but we could add connectivity in larger builds to KMCC.

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 thought there was a 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.

My second question is about the pipes. We are aware of the situation with PG&E in California and the related contracts worth $5 million. How should we approach this? What is the potential impact of bankruptcy? Are those contracts linked to month-to-month base load assets, and how are you approaching this situation?

I believe there is always uncertainty in a bankruptcy proceeding, but there is some reason for optimism. Specifically regarding the Ruby contracts, it is important to note that only Ruby would be affected by the potential PG&E bankruptcy, involving two contracts. One contract supports the electric generation that PG&E utilizes to produce power and meet service demands, while the other serves PG&E's gas distribution sector. We consider both contracts essential to PG&E's operations, contributing approximately $93 million annually in demand revenue, making this a significant concern for us regarding Ruby. While the bankruptcy situation is unpredictable, some key points stand out. Firstly, these contracts are integral to PG&E's core business, and we have been informed to anticipate ongoing use of them. They help PG&E fulfill its service obligations to primary customers and were approved by the CPUC at the outset. Additionally, the CPUC mandates that PG&E maintain upstream firm transport capacity, which we believe enhances the likelihood of these contracts being upheld. It is worth noting that this reliability was recently validated during the GTN outage, which led to increased demand on the Ruby contracts. Even though current pricing is lower than the long-term contract rate, the reliability advantages are significant. Furthermore, our understanding from previous PG&E bankruptcy proceedings is that they did not reject firm transport contracts, which is not a guarantee of what will happen this time, but does provide some reasons for optimism regarding these contracts.

I want to begin with the 2019 capital expenditure guidance. It appears that cash flows should cover most of that and the dividends, but we will likely need to address a gap of about $400 million from elsewhere. Should we assume that the remaining capital expenditures will be funded through debt at this point, or could we potentially see some sales of non-core assets?

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 a 300,000 barrel a day open season on the Express Liberty pipeline announced 350,000 barrels in season two, so call it, 650,000 needing 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.

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 should we 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 that 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.

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 be midstream or transmission in general regions?

So it's probably half midstream, which part of that is on our intrastate system, and the other half I would say is supporting the LNG projects yet to come.

And then just a quick follow-up. You talked about the following up on the 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.

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 tabled are all the ones that we've articulated before. KML has a good set of assets that can continue as a 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 — there is not anything new that we have previously spoken about. And I think we’re going to be very thorough in thinking about every single one of those and which one makes the most sense.

Okay, there isn't anything new to discuss. I would like to explore the decline in the terminals further. I understand the situation with the Edmonton Terminal, but the releases also mention issues in the New York Harbor. Could you elaborate on that a bit more? Is this a one-time occurrence, a seasonal issue, or does it indicate a more permanent impact on the business?

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 are tariffs 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...

Is the government shutdown 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 a 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 wildlife 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 clarify 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 they are 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 bottom-line sense for Kinder Morgan.

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.

I understand that take or pay contracts wouldn’t be affected. But operationally, are you noticing anything different?

No, we actually in our Alberta crude terminal 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 an 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 million; 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...

Can you quantify what the impact on volumes being moved towards Mexico was in your system either for the quarter or for the full year?

Impact on volumes moved to Mexico...

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.

Following up on the last question, I would like to inquire about the export trends you are observing in the refined product sector. There has been a surge of articles recently discussing rising gas prices to Mexico and the government's crackdown on pipeline subsidies. I am curious about how this is affecting you and how you 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 has now been repurposed to handle gasoline and distillates and that's starting to ramp up, and that’s all Mexico.

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 the fourth quarter?

It's roughly $8 a barrel.

And just one quick follow-up, regarding the acquisition of the 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 perhaps be 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 integrate well with our existing operations.

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?

We are still in the early stages of discussions and are pleased to be involved with both systems, but we do not have any updates to provide regarding our guidance or outlook. We still believe that the $100 million estimate is valid, as it represents the tax-only aspect. We will have to wait and see how the discussions develop. We prefer this environment for negotiations; historically, we have been successful in resolving matters with our customers, and we would much rather handle it here than go through a FERC process, so we are glad to be engaged with both 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 disproportionately 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 in Ruby. But as I also said, we think that there are reasons to be optimistic about these contracts.

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 is that we are maintaining the same perspective, and all these are six times the second year in EBITDA multiple, with the contracts being for 10 years. When deciding on project investments, we carefully evaluate various terminal value assumptions to ensure we are satisfied with the returns on our capital across different scenarios.

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 on the drivers for the delay. And I think it was during the 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 complete. There is obviously a band of uncertainty around that date, but we think we are closing in on it here.

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.