Kinder Morgan Inc - Class P (KMI) — Q2 2018 Earnings Call Transcript

Okay. Thank you. Before we begin, as usual, I'd like to remind you that today's earnings releases by KMI and KML and this call includes forward-looking and financial outlook statements within the meaning of the Private Securities Litigation Reform Act of 1995, the Securities 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 measures 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 Kean and the team, let me again offer a few thoughts regarding what I would term our financial philosophy at Kinder Morgan. As you will hear from David Michaels, our CFO, KMI continues to generate large amounts of cash flow. In the second quarter alone, we generated over $1.1 billion of DCF. And that cash flow is growing with both our DCF and EBITDA increasing substantially for the second quarter compared with the same period in 2017, and in fact on a year-to-date comparison. So we have strong cash flow and it's growing. Cash from management and the board is to make certain that cash is deployed wisely and productively. As you know, we are doing these things; we're de-levering our balance sheet; we're funding our expansion CapEx with internally generated funds; we have increased our dividend with further announced substantial increases targeted to both 2019 and 2020; and we bought back shares. As stated in our earnings release today, we intend to use KMI’s share of the proceeds from the sale of the Trans Mountain pipeline, estimated at approximately $2 billion, to pay down debt. In my opinion, using our cash for any and all of the purposes I've mentioned benefits our shareholders. And we will continue to use that shareholder benefit analysis as the litmus test on how to deploy our future cash flow. Let me just assure you, we will not foolishly waste our most precious asset, which is the cash we generate each and every quarter. Steve?

As usual, we will be updating you on both KMI and KML this afternoon. I am going to start with a high-level update and outlook on KMI, then turn it over to our President, Kim Dang, to give you an update on our segment performance. David Michaels, our CFO, will take you through the numbers. Now, I'll give you a high-level update on KML and Dax will take you through the numbers and a couple of other topics on KML. And then we'll take your questions on both entities. We had a successful quarter on KMI and KML. Starting with KMI, we are having a very strong year. We are well above plan for the second quarter of the first half of the year. We expect to end the year at or above our plan. Our leverage continues to go down and we are showing a 9% improvement year-over-year in DCF per share for the quarter. Just as importantly, what's driving much of that improvement is strong underlying fundamentals, particularly in U.S. natural gas, where our volumes are up sharply year-over-year due to increasing U.S. supply and demand, including export demand. That drives value on our underlying assets, as well as creating opportunities for projects. We expect those fundamental drivers to continue, and we are benefiting from it in our transportation and sales business. In addition to being the nation's largest transporter of natural gas, we also own and operate a large collection of storage assets. The improving fundamentals have not yet driven up storage values, but we would expect to see that improve and contribute to our performance as well in the longer term. So, very good underlying operating performance and year-over-year growth. We've been saying for a while now that we want our leverage metric to be at or below 5 times debt to EBITDA. We ended the second quarter at 4.9 times, and that obviously is before closing the Trans Mountain sale at KML. Management and the Board view the proceeds KMI receives as a result of that transaction should be applied to further reduce KMI leverage, giving us greater financial strength and flexibility. We believe it should also put us well on our way to an upgrade. Getting to where we are today required intense focus by our whole team, focus on our day-to-day operations at maintaining cost and capital discipline without compromising the safety of our operations. It's also the result of improving performance in our business, which Kim will take you through. On May 29th, KML announced that we have agreed to sell the Trans Mountain pipeline and the expansion project for CAD4.5 billion or approximately $2 billion to KMI shares. We guided to a late Q3 or early Q4 close and agreed with the Canadian government on a restart of planning and construction activity to be funded by a government recourse only credit facility. Everything is progressing as we said then. We have obtained some of the required regulatory approvals and we're making progress on the remaining. We have set a KML shareholder meeting date of August 30 and we are still expecting that late Q3 or early Q4 close. We are having a good year. I'll cover the negatives as well on KMI. First, we continue to weigh in on the FERC tax notice of proposed rulemaking. We continue to believe that the impact of that rule, even if it stays in its current form, will be mitigated and spread over time. We still estimate that the tax-only impact of the rule is about $100 million annually if fully implemented. As an aside, the NOPR is not on the agenda for the July meeting. We don’t have any special insight into why. We hope the commission will take, and we've been urging the commission to take more time to deliberate because this is a big issue and there clearly have been unintended consequences from it. We think the design of the 501-G form is flawed and will produce uninformative looks at the appropriate cost of service for our assets. So if that process goes forward as is, everyone needs to keep that in mind as those forms come out. Second, it's frustrating to see our strong fundamental economic performance this quarter overshadowed a bit by the impairment of our investment in gathering and processing assets in Oklahoma. These are not bad assets but they are not as well positioned as our other assets, for example, in the Bakken and the Haynesville. And we have better risk-adjusted return opportunities elsewhere in the portfolio, like the opportunities we’re pursuing in the Permian. We will look at appropriate alternatives with respect to these particular assets. Also note that the value of our gathering and processing assets in the Bakken and the Haynesville is improving. But of course, you don’t get to write those assets up. Notwithstanding this non-cash accounting charge, we’re having a very good year on the fundamental economics of our business. And with that, I’ll turn it over to Kim.

Thanks, Steve. Overall, the segments showed an 8% increase compared to the second quarter of 2017, reflecting strong performance. Natural gas had an exceptional quarter. Transport volumes on our large diameter pipes increased by 3.5% Bcf a day, which translates to a 12% rise, driven by higher supply from the Permian and DJ plays, alongside growing demand from exports to Mexico, increased power demand, new projects coming online, and some colder weather early in the quarter. The greater utilization of our systems, much of which occurred without significant capital expenditure, led to notable bottom line growth for the quarter, and will create expansion opportunities in the long run as our pipes reach their capacity. Gas and crude gathering volumes rose by 7% and 19% respectively, propelled by higher production in the Bakken and Haynesville, despite some decline in the Eagle Ford. On the project front, we had several significant developments in natural gas this quarter. Since our last call, we've contracted 6% of the remaining capacity for the Gulf Coast Express pipeline, which is now fully subscribed. The Right Away acquisition is in progress with mainline construction expected to commence in October of this year, with service anticipated by October 2019. We also announced a letter of intent with EagleClaw and Apache to jointly explore the Permian Highway project, an approximately $2 billion DCF project aimed at transporting volumes from the Permian to the Texas Gulf Coast, with Apache and EagleClaw positioned to be major shippers if we proceed. Lastly, regarding the Elba liquefaction project, we now expect it to be operational in the fourth quarter of this year, about a quarter later than planned, but this delay has been considered in our guidance for the year, which David will explain further. Our CO2 segment benefitted from increased crude volumes along with rising NGL and CO2 prices. Net crude oil production rose by 4% compared to the second quarter of 2017. SACROC volumes increased by 6% year-over-year and are 6% above planned year-to-date as we continue to find ways to extend the project's lifespan. We are currently assessing transitions and adjacent off-unit opportunities where we already hold mineral rights. Though Tall Cotton volumes have risen compared to last year, they remain below budget. For the full year, we expect our total crude production to align closely with our plans. Our net realized crude price remained relatively stable for the quarter, despite higher WTI prices, as the increase in the Mid-Cush differential counterbalanced the WTI price rise. For the remainder of the year, approximately 87% of the Mid-Cush differential has been hedged. The Terminals business saw a 3% increase, benefiting from liquidity expansions in the Houston Ship Channel and Edmonton, along with the new Jones Act tankers introduced in 2017 and improved volumes across both sides. These gains were somewhat offset by weakness in the northeast, especially at our Staten Island facility, which is now subject to a New York spill tax, making it less economically viable compared to facilities in New Jersey. Non-core divestitures have occurred as we have refocused our business on core hub positions and faced lower charter rates in our existing Jones Act portfolio. Bulk tonnage increased by 16% during the quarter, primarily driven by coal and steel. Liquid volumes decreased slightly, by approximately 4%, largely due to the Staten Island facility previously mentioned. In our product segment, we observed strong performance from our refined products division. Overall refined product volumes rose by 3%, significantly outpacing EIA forecasts. We benefited from a refinery outage in Salt Lake that positively impacted our Las Vegas volumes. Even after accounting for this impact, our volumes exceeded EIA expectations. On the crude and condensate front, volumes increased by 5%, driven by strong numbers in the Bakken due to economic spreads and in the Eagle Ford as shippers aimed to meet minimum requirements. Lastly, on the product side, ethanol volumes increased by 10%, mainly propelled by expansion projects at our southeast terminals. I will now hand it over to David Michaels to discuss the financials.

Thank you, Kim. Today, we are announcing a dividend of $0.20 per share, matching last quarter's declaration and our 2018 budget, as well as the plan shared with investors last July. The total expected annual dividend is $0.80 per share, reflecting a 60% increase compared to the $0.50 per share declared for 2017. Importantly, as mentioned in our budget, we anticipate substantial cash flows that will exceed our dividend despite the significant increase year-over-year. As you've already heard, KMI had a strong second quarter, performing above our budget and last year’s second quarter. We expect to meet or surpass our DCF budget for the full year. I will now go over the GAAP financials before discussing the DCF, which we mainly use to evaluate our performance. For the quarter, the net loss attributable to common shareholders was $180 million, or negative $0.08 per share, reflecting a decrease of $517 million and $0.23 per share compared to the second quarter of 2017. This decrease was largely due to after-tax expenses of $647 million, which we classify as certain items. For those who follow us, we define certain items as non-cash expenses or those that occur sporadically and do not represent our ongoing cash generation capabilities. This quarter, certain items included a $600 million impairment of gathering and processing assets in Oklahoma, which Steve mentioned. When adjusted for these certain items, the $180 million net loss translates to a net income of $459 million, which is $155 million or 51% higher than the adjusted earnings in the second quarter of 2017. Adjusted earnings per share is $0.21, reflecting a $0.07 increase or 50% more than the previous year's second quarter. Moving on to DCF, DCF per share stands at $0.50, which is up $0.04 or 9% compared to the second quarter of 2017. The total DCF of $1,117 million is $95 million or 9% higher than last year's quarter. This notable increase in DCF resulted primarily from enhanced contributions from our natural gas and product segments, aided by favorable cash taxes, although somewhat offset by elevated G&A costs, interest expenses, and sustaining capital. Overall, segments rose by 8% or $137 million, with natural gas increasing by 11% quarter-over-quarter, adding $96 million to that total improvement. The natural gas segment saw benefits from increased volumes from the Bakken and Haynesville, while our other segments also thrived due to growth in supply and margins. The products segment increased by $28 million or 10%, driven by better performance from Plantation, Cochin, and our KMST assets. G&A costs rose by $11 million due to the timing of certain expenses. Year-to-date, we are roughly flat compared to last year. Interest expense increased by $9 million compared to the second quarter last year due to higher interest rates, offsetting benefits from a lower balance. Income attributable to non-controlling interest rose by $13 million, driven by the IPO of our Canadian assets last May. We also benefited from lower cash taxes, and sustaining capital expenses were about $7 million higher than the previous year's second quarter. To sum up, segments improved by $137 million, offset by $13 million for non-controlling interest. Cash taxes were positively impacted by $15 million, while G&A costs increased by $11 million and interest expenses and sustaining capital combined added $16 million. These elements together indicate a $112 million increase in DCF, slightly exceeding the $95 million noted earlier. 2018 appears to be a very promising year. We anticipate DCF for the full year to reach or exceed our budget, driven by better-than-expected performance in our natural gas and CO2 segments, lower cash taxes, and reduced G&A costs, somewhat balanced by the planned sale of our Trans Mountain assets later this year. We also expect higher interest expenses attributed to rising LIBOR rates and lower performance in our liquids terminals business, especially in the northeast. Finally, although natural gas is currently ahead of plan year-to-date and is expected to finish strong, we anticipate some budget impact in the second half due to delays with our Elba Island LNG project, as noted by Kim. Regarding our balance sheet, we concluded the quarter at 4.9 times debt to EBITDA, an improvement from last quarter and year-end, both of which were at 5.1 times. This quarter's improvement was aided by timing, with expected increased spending in the second half of the year relative to the first. We expect this increased expenditure to be more than balanced by the impact of the Trans Mountain sale. Without the effects of that sale, we aim to finish the year below our 5.1 times budget. The net debt at the end of the quarter was $36.6 billion, including a 50% share of the KML preferred equity, which is $11 million lower than year-end and down $342 million from the end of the first quarter. To clarify the quarter's change reflecting the reduction in net debt of $342 million, we generated $1,117 million of distributable cash flow, allocated $621 million to growth capital and joint ventures, paid $442 million in dividends, and had a working capital source of cash of $288 million, primarily from accrued interest, which explains the $342 million debt decline for the quarter. In comparison to year-end, the $11 million lower net debt can be reconciled by our generation of $2,364 million of distributable cash flow, $1,266 million in growth capital and joint ventures contributions, $719 million in dividends, $250 million in share repurchases in the first quarter, and a working capital cash use of $118 million, largely from a bonus property tax payment in the first quarter. With that, I will hand it back to Steve.

So turning to KML, the big news during the quarter is of course the $4.5 million Canadian Trans Mountain sale transaction. As we said at the time of the announcement, the sales price amounts to about CAD12 per KML share. And on top of that, we have a strong set of remaining midstream assets in an entity with very limited debt and with opportunities for continued investment and expansion, as well as potential for a strategic combination. We are laser-focused right now on closing this transaction and that process is going well. The KML board will be reviewing the use of proceeds alternatives and will provide further guidance on that as we advance the transaction to close. Again also consistent with what we said the day we announced the transaction. As pointed out in the release, while all options are on the table, we generally don't view it as attractive to KML shareholders for us to sit on a big pile of cash while management hunts around for a transaction to use it on. So we are strongly indicating there I think that we’re going to look for the best alternative for KML shareholders and that's what we’re going to work through with the KML board. Dax, go ahead.

Thanks, Steve. Before discussing the results, I'd like to share some general comments regarding KML. We currently anticipate that the sale of Trans Mountain will close at the end of the third quarter, beginning in the fourth quarter, pending the necessary regulatory approvals. This transaction is expected to yield significant proceeds of about $4.2 billion after tax, and we will provide updates on our plans for these proceeds after the KML shareholder meeting that will approve the deal. As noted in our press release, since we are divesting a significant portion of KML, we are retracting our previous guidance and will furnish updated guidance with more detailed information about the earnings potential of our remaining assets around the time the transaction closes. Concerning KML's future, while the initial purpose of establishing KML—being a standalone entity to fund TMX—has changed, KML will continue to be a robust company after the sale of TM concludes, as we have strong fee-based residual assets. The KML Board will evaluate all options for the company, and we are considering every possibility. Now, moving on to our results, the KML Board has declared a second-quarter dividend of $0.1625 per restricted voting share, which annualizes to $0.65 and aligns with our budget and prior guidance. Earnings per restricted voting share for the third quarter of 2018 are about $0.02, resulting from a net income of approximately $13.7 million, reflecting a decrease of around $1.4 million or 45% compared to the same quarter in 2017. Increased revenue from the Base Line Tank and Terminal assets, additional equity at AEDC linked to Trans Mountain expenditures, and a one-time gain from selling a small asset were countered by higher interest expenses due to the write-off of unamortized costs from the canceled Trans Mountain construction facility. Additionally, we recognized a foreign exchange loss in the second quarter of 2017 related to settled intercompany loans at the IPO, which does not repeat in 2018. Adjusted earnings, excluding specific items, amounted to approximately $54 million, compared to approximately $36 million in the second quarter of 2017. During the second quarter, we encountered three specific products; a $60 million write-off for the unamortized issuance cost of the canceled Trans Mountain construction facility, around $3 million in expenses related to the Trans Mountain sale, and a $9 million gain from selling small assets. The total DCF for the quarter reached $91.8 million, notably up $12.4 million from the same period in 2017, although this was approximately $7 million below our budget. This amount provides a coverage of about $10 million, reflecting a DCF payout ratio of around 63%. The main reason for the budget variance was that we had anticipated the gain from asset sales as a budget item. While we typically do not budget for specific items, we did account for this gain. After recognizing the gain, we decided to exclude it from the DCF, given its one-time nature. Regarding the DCF variance components, segment EBITDA before certain items rose by $19.6 million compared to Q2 2017, with the pipeline segment increasing by roughly $14.7 million and the Terminal segment by about $4.9 million. The pipeline segment benefited mainly from increased AEDC related to spending on the project and somewhat favorable O&M. The Terminal segment grew primarily due to the Base Line Tank and Terminal project assets entering service, as well as higher contract revenues and renewals at the North Line terminal. We placed six of the twelve tanks in service during the first and second quarters, with four more expected to come online in the third quarter and the final two in the fourth quarter. G&A expenses were up by $3.3 million, mainly due to the costs of being a public company. Lower interest costs and higher preferred dividends mostly balanced each other out. Sustaining capital was unfavorable by about $1.8 million compared to 2017 due to increased spending on Trans Mountain, although terminal spending decreased. Cash taxes rose by $1.5 million compared to the same quarter in 2017, as we were not obligated to make estimated cash tax payments in 2017 but made significant payments into Q2. Shifting to the balance sheet, comparing year-end 2017 to June 30, cash decreased by approximately $12 million, driven by $144 million of DCF, which excludes $25 million in AEDCs that are non-cash, along with $247 million in net borrowing proceeds and $4 million from other working capital sources, offset by $322 million in cash spent on expansion capital and $85 million in distributions net for proceeds. Other current assets increased by around $26 million, mainly due to an uptick in prepaid property taxes associated with mid-year payments. PP&E rose by $357 million, largely due to spending on expansion projects. Deferred charges and other assets fell by approximately $60 million, reflecting the write-off of unamortized debt issuance costs related to the facility I mentioned. On the right side of the balance sheet, total debt increased from zero to $247 million, with this amount combining with the approximately $115 million and $132 million line items observed. The approximately $133 million represents the balance on the new $500 million working capital facility that supplanted the canceled TMX construction and working capital facility, with this debt remaining with KML post-transaction. The approximately $115 million reflects the facility we established with the Government of Canada during the project's construction on their behalf until the transaction closes. This debt will be transferred to the Government of Canada without any purchase price adjustment, meaning KML will not be liable for its repayment. Other current liabilities rose by nearly $62 million, mainly due to an increase in TM expansion approvals and income taxes payable. Other long-term liabilities went up by around $36 million, primarily due to the receipt of stock premiums from shippers. Now, I'll hand it back to Steve.

All right, thanks. And with that, we’ll open up the line to questions on both KMI and KML.

So just to follow up on the comments around KML there. Following the close of the Trans Mountain sale, you’ve highlighted the possibility of being acquisitive in the Canadian market. Given some of the recent deals and valuations we’ve seen though, would you consider further divestitures if the interest is there?

Yes, we will explore all options. Regarding mergers and acquisitions, there are a few key points to consider. First, this is a valuable group of midstream assets that align well with other companies. Second, we are exiting this situation with very little debt on the balance sheet, which provides us with flexibility, even after distributing the proceeds. In terms of divestitures, selling an asset likely wouldn't be practical from a tax or business integration perspective. We still maintain a solid set of relatively integrated assets with the KML entity. However, we will evaluate all alternatives, including strategic combinations.

Let me get to switching gears to the Permian Highway. So on PHP, the base design calls for a 42-inch pipeline. You also noted the possibility for a 48-inch line. We’ve seen some projects propose with a similar diameter with up to 5 Bcf a day of capacity. Are there any physical limitations that would prevent that level of compression on PHP, or is it more a question of commercial support?

I’m not sure how you arrive at 5 Bcf for a 48-inch line, especially since a fully powered up 48-inch is around 2.7. The context isn’t entirely clear to me. However, on the Permian Highway Pipeline, customer sign-ups and interest have been increasing rapidly. Just last quarter, we signed a 2 Bcf pipeline project from the Permian to our Texas Intrastate system, and we are now in advanced discussions on a second project of similar or potentially larger size. This is quite remarkable and highlights two key points: the strong growth in production from the Permian and the value of our downstream network, which provides customers with good options to transport their gas to the Houston market, as well as to meet power demand, petrochemical needs, LNG, and Mexico exports. We are making progress but haven’t included it in the backlog or reached a final investment decision yet. However, we anticipate being able to share more information about this in the current quarter.

And so the 2.7 area. Is there any work that you’d have to do on the downstream side of this, thinking more so along the Gulf Coast as you’re connecting into the legacy system?

Yes, there is some. It brings a lot of gas into the network. And so there is some downstream debottlenecking that would take place to make sure that we get that gas dispersed off to valuable markets.

I guess just one last one here. So you highlighted incremental capacity sales for the Permian systems. Are you seeing any pricing power with regard to negotiated rates on either KM Texas or maybe El Paso as legacy contracts roll off there?

Yes, one important distinction here is that our Texas Intrastate system is not a FERC regulated asset, which is important to know. I think we are generally doing negotiated rate transactions, and I’ll turn it over to Tom to answer on the intrastate pipelines.

Negotiated rate transactions and really I think we’re seeing, both on EPNG, NGPL as well, opportunities to have very, very attractive negotiated rate deals for at least the two to three-year period. So some of these other projects, where projects come in to service and in some instances longer term than that, so a lot of demand for capacity to get out of the Permian.

Just continuing with the Permian here, and just want to check. Is there any opportunities left in EPNG, NGPL, Texas Intrastate kind of squeeze out any other incremental capacity? Or you guys fully tapped out on that side?

We’re continuing to expand on all three of those systems. We’ve been doing some external surveys and we are looking at others as well.

I'm curious about the size of these deals; are they small, or could there be some significant opportunities due to upcoming constraints?

Starting with Texas, it's the most significant area because the higher value market in the U.S. is currently along the Texas Gulf Coast. If we exclude New England for now, the price differentials are notable, with a depressed price in the Permian region of West Texas and a strong price in the Houston Ship Channel. This region sees all the additional demand. All the gas, including supplies from the Northeast and along the Gulf Coast pipeline, as well as from new pipelines that Tom and his team are developing, is aiming to connect to our system and others in the Texas Gulf Coast. The largest project we are actively working on is the 2 Bcf project, along with the 2.7 Bcf project that is in advanced stages of development.

It seems like you’ve been ahead of those pipelines coming online there could be big bottlenecks, I don’t know if it’s like 100 mcf or is it bigger or smaller? Just trying to feel like how much we could see there, because there is concern that the production of gas in West Texas, if there’s not enough takeaway that could impede production growth rate?

Yes, there continue to be bottlenecks and the infrastructure is trying to catch up to that now. And if you look at long-term within all these projections, they’re going to be subject to debate. But if you look at the long-term projection, there is a long-term projection for continued strong basis between the Permian and the Houston Ship Channel, and that's a consequence of just expected continued growth in oil and associated gas production. So we’re trying to help our customers by de-bottlenecking those constraints a bit, but the growth in production continues to make those constraints and those differentials fairly persistent, which is a good thing for a company and the business that’s moving the stuff from place-to-place. And it’s also a good thing that we have, essentially with our assets, we lap the part of the market that's really growing in terms of demand on the Texas Gulf Coast and even Louisiana.

And then I guess just looking at the balance sheet, and if you are able to get $2 billion of cash move from KML to KMI, what type of target leverage are you looking for? You said you could be on uplift for upgrade there. Would you look to buy back bonds or keep cash on the balance sheet for projects? And how does this play into the buyback program, how much have you executed there?

Yes, I think what we’re telling you, of all the alternatives that Rich has talked about in terms of the use of cash, we’re trying to give you some guidance here that we think the best use of that is, as particular instances, to further de-lever, to further reduce our leverage. And so that's what we intend to do and that’s what we’re telling you today.

So do you have…

As opposed to buybacks or something else.

Do you have a targeted leverage ratio that you’re looking to get to at this point? And is there room still left on your authorized buyback program?

Jeremy, KML has not specified what it plans to do with the funds. As Steve mentioned, we do not believe it is wise to allocate our cash in anticipation of a possible acquisition. Therefore, we are awaiting KML's decision. KMI has stated that once we receive the proceeds, we will use them to reduce debt. After we have more information, we will update you on any changes to our leverage metrics at that time. Currently, we are maintaining our leverage metrics of 5 times or better.

And obviously, it doesn’t take a genius to figure out that if you are reducing your debt by $2 billion or something in that range, that will have a material impact on the ratio.

It would be well below 5 times?

It would be well below 5 times and at that time is when we would share any resulting targets.

And one last one if I could, the ENI arbitration ruling. Is that an NPV neutral event for you guys, or any more color you can share there?

Not a lot more color than what we have in the press release. It's under a confidentiality arrangement. For disclosure purposes, we can state essentially what we've stated here, which is that we had a result, the result was the termination of the contract but also substantial cash award to Gulf LNG.

Just a couple from me, the first one is I've had a number of clients with concerns about your Permian Highway Pipeline partners’ ability to fund their share of the project. Could this be a possible show stopper, or would Kinder Morgan be willing to take a larger share if it came to that assuming the customer contracts were there?

It's an attractive project to us and so we would take a larger share of that if that's an issue, we don't expect it to be an issue though.

And then now that your debt is below 5x and U.S. oil prices and production have recovered, it seems like there's more room than in the past to sell non-core assets and reshape your portfolio a bit. When you look at your asset base, do you see a benefit in trimming in some areas where you don't have a huge presence? Are you pretty happy with your portfolio as is and perhaps even view the diversity as a benefit?

Generally, very happy with the portfolio that we have. We do continue to look at those things, so where they make sense. And John and his team in terminals have, over a couple of years, they've pruned the assets to get his business lined up more towards the things that are the real hub positions, as well as really strong positions in the bulk business. Tom has done a bit of that too, mentioned Oklahoma G&P that's not necessarily divestiture for a JV or other alternatives we'll look at there, so we'll continue to look at it.

Just a couple of questions and some of them are re-asking some of the other questions that have been previously asked. But first just starting with the TMX proceeds. So you clearly outlined that you're going to pay down debt, that's the first priority right now. Given the fact that a chunky pay down of debt would be materially below, when we think about 2019, 2020 and so forth, in a scenario where operating cash flows after fully funding CapEx and the dividend, in the past I think in your analyst day this year, you had said I think it was $565 million was available to buy back shares. Would that be the approach that you would take between ’19 and beyond that if there's cash available after funding CapEx and dividends out of operating cash flow that you would then direct it towards that? Or would you still want to get meaningfully below the chunky pay down of debt that you're indicating right now?

I don't know what you mean by chunky pay down paying down debt is paying down debt, Shneur. So once we have reached our targeted level of debt, which as Kim said we will share with you, once the distribution of proceeds is finalized, then I think we can give you a clear roadmap to where we’ll be in the future. But our thought on this is we’re de-levering, we’re strengthening the overall portfolio of the Company in that respect. And as I said in my opening remarks, that still gives us the opportunity to do all these other things, all of which benefit the shareholders. We’ve already plugged in and anticipated substantial additional increases in dividends. We bought back $500 million worth of stock. We can do more of either one of those. And obviously, we will continue to fund our expansion CapEx internally. So it just gives us a lot more runway I think on a going forward basis, which we can share with you after that distribution is made.

So maybe two follow-up questions, first one follow-up on the Permian infrastructure. You sounded like you have some de-bottlenecking opportunities, and it sounds like some compression here and there and so forth that can give a couple hundred of new capacity. But at the same time, the plan is to bring on costs down more or less, you expressed here, you’re talking about potentially PHP. I mean, how do you balance between spending capital to debottleneck for what would be addressing a short-term issue versus cannibalizing a longer-term issue? Can we expect that these types of debottlenecking capital projects have a much lower multiple in terms of expected returns? I am just trying to understand how you balance those types of items.

Yes, those returns are very attractive, but we handle both aspects. I want to highlight the value that increased production and the growing supply and demand across our network bring to our existing system. Even without expansion or significant capital investment, we are seeing the value of our existing capacity improve. Previously, people would move on EPNG to the hub for free and then aggregate for a downstream move. Now, even small bits of capacity are valuable, and we are realizing that value. Smaller projects often yield very attractive multiples, while larger projects like Gulf Coast Express also generate attractive returns, though not at the same multiples as some smaller capital projects. Additionally, there is a positive impact on the value of our existing network.

And just one follow-up on that, to the extent that it is a short-term opportunity, because those volumes will ultimately move on Gulf Coast Express or on Permian Highway, we're taking that into account in our economics that we run to the extent that the short-term opportunities require capital. As Steve said, they don’t always require capital.

So, just to paraphrase, effectively these short-term projects are high return projects but you also get operating leverage downstream from those projects, which I assume you would also have operating leverage once Gulf Coast Express and PHP come online. Is that the right way to characterize it?

Yes, I think that's fair.

And then I guess just one last thing to touch on the FERC update and the news or the updates on the NOPR process. Can you frame out for us timing of what you’re expecting over the next few months in terms of outcome on any type of final ruling?

We have regular conversations with the agencies. We had some conversations in advance of this call, and we’ll have some after the call. We think with what we’re disclosing here, we should be poised for everything eligible for an upgrade but don’t want to put anything ahead of the agency. So we’ll be talking to them in the coming days.

I just had a couple of questions on KMI, and I think I’d like the start with credit. I just want to understand what the pro forma company’s credit profile will be. It looks like you have a new $500 million credit facility but that might expire upon the sale of Trans Mountain. So if that’s the case, what access to credit will you have pro forma?

We will establish another facility. As I mentioned, the government loan will be utilized, and we will have working capital requirements. Therefore, we will implement a facility after closing, and we are obviously preparing for the related announcements.

And then just going back to the question about what happens upon closing. How would you weigh keeping KML as a public company, now that its original intended purpose has changed? Or is that still not relevant vs the advantages of simplifying the corporate structure?

Keeping KML as a public company is definitely one of the options. It is smaller, but it is strong enough to operate independently. We have a solid business with good operations that we understand, and John and his team can maximize its potential. We are exploring a couple of expansion opportunities. This is certainly a viable option for us and remains on the table.

So I have some housekeeping questions. You guys talked earlier in Q&A about some slack capacity in Staten Island until there is a resolution. Can you just get into what the potential resolutions are?

There are a number of resolutions from leasing it out to a specific customer to shutting it down, and we're evaluating all of those. It has a very small earnings impact overall, but it does have a meaningful impact on utilization.

And then what drove the one-quarter delay in the Elba project, and should we assume that all subsequent trains are delayed by the same timing?

First of all, there’s some context here. Train one, once there are 10 trains in total, will attract about 70% of the revenue once it is in service. So it's a little less of an issue for the subsequent trains. However, we still expect to complete the entire project in Q3 of 2019. The reasons for the delay are multifaceted. There was a delay in getting the units assembled and delivered to the site, along with some construction delays. We have been actively involved with our EPC contractor, who is also working to address these issues. We believe we have identified and improved the challenges, but we are definitely experiencing a one-quarter delay. We still expect to finish this project, which is under budget, and we have remaining contingency. It will still be a very economical project for us and our partners, but we have encountered this one-quarter delay.

And then can you remind us, for the unhedged portion of your crude production and CO2. Is that fully exposed to the Midland basin?

No, in 2018, we have 87% of the Mid-Cush spread hedged.

And then the 13% is not?

And then the 13% of Mid-Cush is not, right.

In the event that you are in good shape for Gulf Coast Express but do not receive a waiver for the Permian Highway Pipeline deal, should we expect the pipeline to absorb the costs, or will the tariff be adjusted? How should we approach this situation?

Yes, first of all, it's not necessarily seeking a waiver in order to do it. It's really more for making a decision about where we’re going to get the pipe and making sure we’ve got a clear path to get it, not relying on a state department waiver of our ability to get the pipe or get this deal for that. We are working on making sure that our cost estimate is adequate and to make sure that we’re fully protected. It is a competitive market though and so there is some limit on the ability to try to negotiate a pass through arrangement with shippers.

I just wanted to suggest that if you do close down Staten Island, I think that place could use a really massive water park.

We’ll take that into consideration...

But I wanted to ask if you have any preliminary thoughts on how your vessels might respond to IMO 2020.

Our vessels don’t burn that type of fuel oil, it's all on-road and there is no impact on our business there.

When we look at KMI and we see its recovery as a leader in the midstream and volumes in the profits. And you talked about your great attribute to the company being strategically positioned fee-based assets predictable cash flows. It seems like the CO2 business, you live with downside and we don't realize the upside. Can you just add a little more color, help us understand why it makes sense to remain involved in that business?

Part of that business is our overall segment earnings before depreciation, depletion, and amortization. CO2 accounts for about 11% of that based on our budget for 2018. This 11% is divided into 4% for transportation, which resembles a midstream business, and 7% for enhanced oil recovery. As I mentioned earlier, there is economically recoverable oil available at current prices and even at lower price levels, and the only way to extract it is through CO2. We have the CO2 available, as well as the field and expertise in enhanced oil recovery. This represents an integrated opportunity for us. We initially started with the pipeline and then expanded into enhanced oil recovery. We achieve good returns in this sector, which we understand well. We employ hedging strategies to make cash flows more predictable for our investors, resulting in more stable and reliable cash flow. Our production is very consistent, typically deviating only 1% to 1.5% from our annual budget. Furthermore, while we focus on being a shareholder-driven company, if the right opportunity arises with sufficient value and benefits to our shareholders, we would certainly consider it. However, for the time being, we are content to maintain our position.

Okay. Well, Sheila, thank you very much and thanks to everybody for listening to a rather lengthy call. We appreciate your attention.