Kinder Morgan Inc - Class P (KMI) — Q1 2018 Earnings Call Transcript

Okay. Thank you, Sheila. And welcome to our first quarter analyst call for both KMI and KML. 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. With that out of the way, let me make just a few comments before turning the call over to Steve. First of all, on a very positive note, our board today made some important personnel decisions, which I believe will benefit KMI for years to come. We promoted four really outstanding people: Kim Dang to President of the company; Dax Sanders to Executive Vice President and Chief Strategy Officer of KMI; David Michaels to Vice President and Chief Financial Officer; and Anthony Ashley, currently, VP and Treasurer to Treasurer and VP of Investor Relations. I will remain Executive Chairman and Steve will remain CEO. But we're very pleased with those outstanding individuals, and we look forward to many good years of performance. Now let me talk about - a little bit about our results in a broad sense. As you can see from 2017 full year results and from the results of the first quarter of '18, which Kim will share with you today and from our full year 2018 budget and outlook, KMI continues to generate strong cash flow, and we intend to use that cash in a fiscally responsible manner to benefit our shareholders. In that regard, when you think about it, there are several potential uses of these funds. We can use them for expansion CapEx or selective acquisition, either of which helps us grow the company. We can use the funds to pay dividends to our shareholders. We can buy back shares or we can pay down our debt. In my judgment, any and all of these options create value for our shareholders. And speaking of dividends, consistent with our prior announcements, we are this quarter, raising our dividend payable to our common shareholders by 60% from an annualized rate of $0.50 a share to $0.80 per share. I'm very pleased in our ability to reward our shareholders by returning this additional cash to them. And I would remind you that we'll continue to fund all of our capital expenditures with internally generated funds and ask Kim will describe, that we have bought back additional shares during the first quarter.

Thanks, Rich. I'm going to update you on KMI performance highlights and then turn it over to Kim as usual to take you through the financials. Following that, I will update you on KML and again, turn it back to Kim who's still into Dax Sanders on today's call. So that she can review KML's financial performance with you then we'll take your questions on both KMI and KML. Starting with KMI. We had a strong quarter at KMI with positive signs for full year performance. KMI as a whole generated DCF per share of $0.56 for the quarter, an increase of about 4% year-over-year. Both natural gas and the CO2 segments were above planned and solidly up year-over-year of 6% to 7%, respectively. We continue to execute well on our growth projects, we placed $700 million worth of expansions in service during the quarter. And we continue to find attractive new opportunities and added $900 million worth of projects to the backlog during the quarter. The vast majority of the backlog additions are in our Natural Gas segment. Turning to the Natural Gas segment. Our transport volumes were up 10% year-over-year in the first quarter and gas gathered and crude gathered volumes were up 1% and 3%, respectively. The 10% increase in the transport volumes is on top of an 8% year-over-year increase that we had in the fourth quarter of last year. So two quarters in a row of strong year-over-year growth. On the gathering, there were pluses and minuses. We're up in the Haynesville on our gathered gas volumes and on our Hiland assets in the Bakken, we're up on both gas and crude gathered volumes, and those are partially offset by lower gathered volumes in the Eagle Ford. We also continue to see strong pull and demand side power was up 22% year-over-year on our systems. Mexico exports were up 2% and reminder, Kinder Morgan exports about 70% of the gas that is exported to Mexico. So on the volumes, we had a normal winter overall with extremes early in January that drove all-time records on four of our large networks. Cold weather helps remind the market of the value of the holding firm transportation and storage capacity. But there is more going on here in the gas segment than a few cold winter days. Gas supply and demand is growing across the US. Volumes are growing in the Permian, the Bakken, and the Haynesville, driving producer push activity and growing LNG exports are creating demand pull. This elevates the value of our existing network and creates opportunity for new investment. A couple of data points to illustrate that. About 90% of our $900 million of backlog additions in the quarter were in the gas segment. A further illustration, we signed up about 1.2 Bcf of Permian capacity on our El Paso natural gas transmission line. These are short haul moves and the expansion capital is required - is very modest, for a little over $30 million and with an EBITDA multiple of less than 2 times. This illustrates the value of having pipe in the ground, while overall utilization of the network is climbing as a result of a growing supply and demand, including export demand. We made progress during the quarter signing up the remaining capacity on our 2 Bcf a day Gulf Coast Express project; 94% of the capacity is now spoken for under long-term reservation-based contracts. The last 6% is a long-term gas purchase by our Texas and trust state to serve our sales business in the State of Texas. That commitment is pending, and we would expect to conclude it soon. Attention, the basin is now turned underneath for a second pipeline and discussions are in early stages. In the CO2 segment, we benefited from both higher crude production and higher prices. Our largest field, SACROC has performed above plan in the first quarter and is up 4% year-over-year. We continue to see promising results out of the transition zone, which has been an additional target area for us that could add 600 million to 700 million barrels of original oil in place to the SACROC field. The production at our smaller fields, Katz, Goldsmith, and Tall Cotton is up 18% year-over-year with Tall Cotton by itself being up 58% year-over-year. On Tall Cotton, we have grown production there, but mechanical and operational issues have kept the volumes below our expectations for that development. We're working on that, and we'll be working on it in the coming months, and we will want to be convinced that we have solutions before we commit further capital or commit capital to the Phase III development efforts there. In our Products segment, we saw refined products volumes increase about 0.5% year-over-year, which in contrast to the fourth quarter, is a little less than the 1.9% EIA estimate for the broader industry. We had strong deliveries in the fourth quarter of last year, particularly in December, particularly in Arizona and that likely had a carryover impact on the first quarter of this year, and meaning inventories built during December and therefore to press draws or sort of throughput on the pipeline. We were on plan - we're on plan for the quarter in the segment, earnings before DD&A basis so we're up about 1% year-over-year. We also placed our Utopia pipeline in service in January of this year. The Terminals segment was down about 2% year-over-year in part attributable to the impact of divestitures as John and the team continued to orient our business board toward up position and have gradually shed non-core positions. We're making good progress on our Base Line Terminal project in Edmonton where we are on time and on budget, as we bring tanks into service over the course of the year. There's one other topic I'll cover on KMI, and it's this. We've seen some nice emergence of some good tailwinds in the gas segment, certainly observed those in the first quarter. But we also saw a longer-term headwind emerge as FERC has initiated a notice of proposed rulemaking and other actions designed to flow through the benefit of tax law changes through pipeline rates. Given the settlements and moratoria that we have in place and including one settlement we have pending before their commission right now, we do not expect to see an incremental negative impact in 2018 or '19 to our outlook. And as we said in the January call before the FERC came out, we expect the impact of FERC's action to be mitigated and spread over time. That is still our expectation and here's why. Only about a third of our interstate natural gas pipeline revenue is collected under max rate tariffs. We have negotiated rate arrangements in place to achieve and the commission acknowledges should not be disturbed and we also sell a significant share of our capacity under discounted rate arrangements. Second, we have rate case moratoria in place in several of our systems, which inhibits the reopening of existing rates. Third, rate cases under Sections 4, and particularly under Section 5 of the Natural Gas Act are prospective in effect, with impacts on the Section 4 case being no earlier than 30 days or five months following the date of filing and on Section 5 prospecting from a final order. In recent years, the commission has initiated on the Section 5 front, the most they have initiated is four in a year. Other years have been zero or one or two. That compares to over 130 regulated entities in the gas sector. Fourth, an observation. We believe the 501G filings that we’ll all be making will not be as useful as assumed by the commission in terms of determining so-called over-earning, separate and apart from the impact of tax law changes. We believe this for a number of reasons. The 501G ignores important commission principles, including the recognition of the status of negotiated arrangements before mostly using an outdated ROE decision that is applied on a one size fits all basis. We believe the forms will overstate matters and will have limited utility. We intend to use everything at our disposal to mitigate the negative effects of the actions and to spread their effects over time. We have quantified the impact of the tax rate change in isolation and believe that the incremental impact of that change is about to our outlook is about $100 million a year if fully implemented, which again, we would expect would be delayed. It's incremental meaning that's on top of what we already assumed. We had already taken this into account on SNPP and our outlook and in our pending settlement on SNG, for example. This does not include other negative impacts from new rate proceedings, which we would – we believe are too uncertain, both in amount and timing to quantify at this point. And one final point here, and this is not about ratemaking, but it's about fundamental justice and reasonableness, which is something we will urge the commission to take into account as we consider how to exercise its discretion to pursue Section 5 cases. We're over 30 years now, the commission has methodically created a competitive market in the interstate natural gas pipelines industry. That policy has been steadily implemented through Republican and Democratic administrations. It has delivered enormous benefits to producers and consumers. Pipelines are open access, shippers can sell the capacity they hold in competition with the pipeline who provides it and pipelines can build new pipelines in competition with incumbents. Pipelines are not analogous to traditional regulated utilities. The traditional regulatory compact bounces exclusive franchise service territories, which are insulated from competition on the one hand, with rate regulation on the other hand, that caps rates but enables a reasonable return on capital. Pipelines do not have protected franchises; most rates are set in the competitive market and many systems under recover a regulated cost of service with no effective opportunity to raise rates given the competitive market environment and the commission policy that is created. It's either just or not reasonable to ignore the industry's competitive structure and selectively apply the other half of the regulatory compact rate regulation to some systems without enabling other systems that under recover to recover their cost of service. We expect to continue pressing these arguments as we expect other people in the industry will as well, with the commission as they work through what we expect to be a time-consuming implementation process. Now with that, I'll turn it over to our President, Kim Dang.

Thanks, Steve. Okay, today, we're declaring a dividend of $0.20 per share, as Rick said that the 60% increase over last quarter consistent with our budget, as well as the plan we laid out for everyone last July. Based on our current stock price, the $0.20 per quarter or $0.80 to annualized results have a very attractive dividend yield of over 5% with significant coverage. As Steve said, we had an outstanding first quarter, well above our budgets and nicely above last year. For the full year, we expect to meet or exceed our DCF and EBITDA budget. First, today, let me start with the GAAP numbers, and then I'll move to Bcf, which is the way that we look at and judge our performance. Net income attributable to common stockholders for the quarter was $485 million or $0.22 a share, which is an increase of $84 million in total or $0.04 per share, respectively, with both increases being over a 20% increase versus the first quarter of last year. As you can see from looking at the income tax expense line item on our GAAP income statement, almost all of this increase results from lower income tax expense, primarily due to the reduction in the tax rate associated with the new change - the new tax law. But if you adjust for certain items, which are for this quarter, the first quarter of 2018, an immaterial $4 million expense, but were a benefit of about $30 million in the first quarter of 2017. The change in income tax expense accounts for a little less than 60% of the change, as opposed to the entire change, with the remaining change generated by stronger operating contribution. Adjusted earnings, which excludes these certain items changes are up $118 million or 29%. Adjusted earnings per share of $0.22 is the same as the unadjusted number because as I mentioned, certain items for the quarter had a minimal impact. DCF per share, which is the primary way we judge our performance is $56 per share, up $0.02, which is 4% higher versus the first quarter of 2017. Total DCF of almost $1.25 billion is up approximately $32 million or 3%. The nice increase in DCF was driven primarily by greater contributions from natural gas and CO2, partially offset by higher sustaining CapEx, cash taxes, and the impact of the KML IPO. DCF per share was up 4% versus the 3% on total DCF due to $21 million fewer shares outstanding. We repurchased approximately $250 million worth of shares in the fourth quarter of last year and approximately $250 million in the first quarter of this year. Overall, the segments were up 4% or $78 million with natural gas up 6% contributing $63 million or over 80% of the improvement. Natural gas benefited from nice performance on the Texas Intrastate and SNG driven by winter weather, on Hiland driven by increased drilling activity, on NGPL as a result of lower interest expense, EPNG due to greater capacity sales, primarily driven by the Permian, and on FGT due to lower taxes. The CO2 segment was up $15 million or 7% driven by a 5% increase in net oil volume, primarily at SACROC and Tall Cotton, as Steve mentioned, as well as increases in oil and NGL prices. Non-controlling interest is higher by approximately $13 million due to the IPO of our Canadian assets last May. Cash taxes were $16 million higher than the first quarter of 2017, but are actually lower than our budget for the quarter and expected to be significantly lower than our budget for the full year. Sustaining CapEx was approximately $10 million higher in the first quarter of '18 versus 2017. As you may remember, our 2018 budget for sustaining CapEx was higher than our 2017 actual and I went through that various explanation at our Analyst conference. For the first quarter, we're actually running a favorable variance to budget but that's going to be timing for the full year. So the segments are up $78 million, less the $26 million combined increase in sustaining CapEx and cash taxes and the $13 million increase in non-controlling interest, that totals a $39 million increase in DCF versus a $32 million increase shown on the page. There are obviously more moving pieces but that gives you a big picture of what's going on. We're off to a great start this year and as I previously mentioned, we expect DCF for the full year to meet or exceed our budget, driven by better performance from our natural gas and CO2 segment, lower cash taxes offset by higher interest expense due to higher LIBOR rates. Certain items for the quarter were an expense of $4 million, so as I mentioned immaterial in total. There were however, a few offsetting items. There is a $37 million expense primarily related to an SFPP rate case reserve, which relates to prior periods. The 2018 impact of this is included in our results for the first quarter and taken into account in our forecast for the full year. There are a $40 million expense related to hedge ineffectiveness on our oil hedges primarily related to an increase in the mid differential, and these two expenses were largely offset by two tax benefits items, first, the release of the tax reserve on a sales and use tax, and secondly, the impact of tax reform on a couple of our joint ventures. Our expansion CapEx budget for the year was $2.2 billion. Our current forecast is $2.3 billion as we've identified some incremental projects to meet our return requirements. Let me once again remind you that the $2.2 billion does not include any KML CapEx. With that, let me move to the balance sheet. There is one change in the balance sheet that I want to point out. You'll see a new caption between liabilities and shareholders' equity entitled Redeemable Noncontrolling Interest, which for GAAP purposes, is considered mezzanine equity. Due to a change in the accounting rules starting in 2018, an amount related to our Elba JV, which we previously classified as a long-term liability is now reflected as mezzanine equity. This is an item that we disclosed in our financials for those of you who enjoy reading our 10-K and 10-Qs as we enter into the Elba JV, which reflects the fact that in certain limited circumstances, which we do not expect to occur, our JV partner has the right to redeem its capital account. The outlook project is well underway with the first units expected to be delivered in the third quarter of this year. We ended the quarter at 5.1 times debt-to-EBITDA, flat to last quarter, and as calculation we used net debt, including 50% of the KML preferred shares in the denominator - actually in the numerator, which is consistent with how the rating agencies treat those shares. Currently, we expect to end the year at or below our budget of 5.1 times debt-to-EBITDA. Net debt ended the quarter at $36.7 billion, that's an increase of $331 million in the quarter, which I will reconcile for you. Of the $331 million, about $100 million is associated with increased debt in Canada and $231 million is associated with KMI standalone. We had DCF in the quarter, as I mentioned earlier, $1.247 billion. We had a little less than $650 million of expansion, capital, and contributions to equity investments. Now that's $600 - it's actually about $645 million, includes expenditures at Trans Mountain because it's consolidated. If you exclude the Trans Mountain, the capital spending is a little bit over $510 million. We had dividends of $277 million. We've made share repurchases of $250 million, and then we have working capital and other items of a little over $400 million. On the working capital and other items, accrued interest was a use of cash of about $195 million as we make interest payments - our significant interest payments were made in the first and third quarters, but the accruals that's in DCF is constant throughout the year. We also had a use of cash associated with accrued liabilities of about $125 million, and that's because we make bonus payments in the first quarter and also significant property tax payments made in the first quarter. And then we also had a use of cash associated with our DCF - the DCF being reflected, being slightly greater than the distributions that we received from our equity investments. And so with that, I'll turn it back to Steve.

Okay. Now we're going to switch to KML. Last week, we announced that KML had a decision point on the Trans Mountain expansion project. We announced the suspension of non-essential spending and that under current conditions we would not put additional KML capital at risk. We also said there's no readthrough from this in terms of our willingness to invest in Canada. We have invested in Canada, British Columbia, as well as Alberta, and we expect to continue investing. But as we said then, it's become clear this particular investment may be untenable for a private party to undertake. The events of the last 10 days have confirmed those views. We pointed out there are significant differences between governments, those differences are outside of our ability to resolve. We are continuing our stakeholder discussions between now and May 31 and we're looking for a way forward on this project. All of that is the same as what we said on the call last week, nothing new there. However, discussions are underway, and as the Prime Minister said on Sunday, we're not going to undertake those discussions in public and we do not intend to provide additional updates on the status of those until we reached a sufficiently definitive agreement or the discussions have terminated. So again, not much update, but discussions have commenced. With that, I'll turn it over to Kim to talk about financial performance at KML during the quarter.

Thanks, Steve. Let me process my comments as Dax has, in prior quarters with the caveat, while we are offering quarter-over-quarter comparisons. Those comparisons are of limited value given that we're reporting a quarter where KML was owned by the public versus a quarter where it was wholly owned by KMI. During those periods, prior to the IPO, there were significant shareholder loans in place that generated FX, most of which was unrealized and intercompany interest with KMI that are not reflective of the true earnings power of KML. Therefore, we would ask you to focus on the actual results for 2018 and how they compare to our published budget. Quarter-over-quarter will be more starting in the third and fourth quarters of this year when we have comparable quarters all post IPO. Now moving to the results. Today, the KML board declared a dividend for the third quarter of $0.1625 per restricted voting share, or $0.65 annualized, which is consistent with our budget and previous guidance. Earnings per restricted voting share for the first quarter of 2018 are $0.10, derived from $44 million of net income, which is down approximately $2 million or 5% versus the same quarter in 2017. In the first quarter of 2017, we recognized a foreign exchange gain associated with the intercompany loans. These loans were settled at the time of the IPO, and therefore, that gain does not recur in 2018. Adjusted earnings, which include certain items, the most significant of which is the FX gain I just mentioned, were approximately $44 million compared to approximately $40 million for the same quarter in 2017. This increase is largely associated with a decrease in interest expense given the extinguishment of the intercompany loans and increased AEDC associated with the spending on the Trans Mountain expansion project. Total DCF for the quarter is approximately $77 million, which is down $6.4 million from the comparable period in 2017, but favorable to our budget. That DCF provides coverage approximately $5.5 million and reflects a DCF payout ratio of approximately 76%. Looking at the components of the DCF variance, segment EBITDA before certain items is up $6.8 million compared to Q1 2017 with the pipeline segment up $7.3 million and the terminal segment down very slightly. The pipeline segment was higher primarily due to the AEDC associated with the spending on the project. The terminals segment was lower due to the termination of the contract in Q1 2017 for which we received the net termination benefit, and lower volumes at our Vancouver Wharves terminal. Offset by the Base Line Terminal coming into service. On the Baseline Terminal project, we placed six of the 12 tanks into service during the quarter. The first four tanks went into service on schedule in January, which we talked to you about on our January investor conference. The next two which were scheduled to be placed in service in the first couple of weeks of June were actually placed in service early in mid-March and the beginning of April. G&A is higher by about $2.4 million primarily associated with the higher cost of being a public company. Lower interest expense and higher preferred share dividends largely offset each other. Sustaining CapEx was favorable about $3.4 million compared to 2017, but we expect sustaining CapEx to be slightly favorable to the budget for the year. Cash taxes increased by $6.5 million to $6.6 million over the same quarter in 2018. In 2017, we were not required to make estimated cash tax payments, but do need to make them in Q1 of 2018. Now moving on to the specifics for the full year. Currently, we expect EBITDA and DCF, excluding AEDC for the full year to be on plan. AEDC and capitalized interest will be highly dependent on what happens with the project. With that, I'll move to the balance sheet. As you can see there, we did draw on the facility during the quarter for approximately $100 million, but we still ended the quarter with a net cash position of $110 million. If you add 50% of our preferred equity to our net debt balance, which is again, the way the rating agencies generally look at it, our net debt position at March 31 was approximately $165 million. For the quarter, net debt increased by approximately $129 million from December 31. And so let me reconcile that for you. DCF was $77 million, expansion CapEx was $167 million, gross dividends were $58 million, the DRIP, the dividend reinvestment program, generated proceeds of $15 million, and then working capital and other items were a slight positive. Finally, just a couple of things on expansion capital. On Base Line Terminal, which now has approximately $304 million of our share of the $398 million project, so about $94 million less to spend in 2018. On Trans Mountain, we've now spent about $1.1 billion as of 3/31, with approximately $550 million of that spend by KMI in periods prior to the IPO and the balance spent by KMI since the consummation of the IPO. With that, I'll turn it back to Steve.

Okay. Sheila, we're ready to take questions on KMI and KML.

Hi, Jeremy. How are you?

Good. Good afternoon. Thanks. Just want to see, with regards to the FERC matters, if you had talked to the commissioners there? And do you have any sense if there could be any kind of reconsideration of what they've done here? It seems like some of the comments, maybe the employee expects some of the actions to happen in the marketplace given what they did during open market hours?

Yeah. Look, I think even in public testimony statements as recently as yesterday, there was a recognition I think, that a lot of comments are going to have to be reviewed and a lot of input is going to have taken in, in order to make the right decisions here, and so we're encouraged by that. We’re obviously reaching out as our industry is reaching out in every way that it can to make sure that our views and our facts are known to the commission as they're figuring out how to proceed here. And it's really - I mean, it's extremely important, I think, for the commission to take into account the results, the benefits, but also the other implication of a long-standing policy of creating competition in competitive markets, intrastate pipeline transmission, they succeeded, they've succeeded in that. But that is a fundamentally different environment than, say, a traditional regulated utility and that needs to be adequately taken into account as they think about how to use and exercise their discretion. And so we're encouraged by their openness to the input, and we intend to give them plenty of it. I didn't mean that disrespectfully.

Thanks. Just a couple of quick follow-ups and just want to see, when you were talking about the moratorium, was that the FERC is prohibited from reopening where you have moratorium, am I correct in understanding what you said there? And also just as far as how the supplies of liquids pipeline, I was wondering if you might be able to expand a little bit there on the refined products side?

Yes, so the settlements really are applying to the gas pipeline side of the house, wherein ongoing rate case on SMPP has been going on for a very long time. And on the gas taking - talking specifically about gas, settlements don't bind subsequent commissions, but they are generally honored and there's good language in FERC orders about settlements and rate moratoriums or moratoria that are in place where they tend to respect them. The parties sit around and negotiate an outcome and they do so in good faith. The commission, along with the customers and the pipeline and typically those settlements are - typically, those settlements will bind the private parties, if you will, to their terms, but can't legally bind the commission. But again, the practice has been for the commission to honor those.

Great. Thanks. And then just one last one if I could. With regards to the Permian Pipeline, the second one that you're talking about there, that's interesting to hear. Just wondering if you could talk about the competitive dynamic as far as pursuing this project, if you look to bring that to the same market or different path. And just how you think, I guess, Waha basis moves over time here in the effective benefit you know, KMI in the interim, as it seems like even GCX isn't going to be online for a while here in the basis is really kind of an upside, I don't know if there's other smaller brownfield things that you can do in the interim to take advantage of that?

Well, look, you put your finger right on the fundamentals, but I don't want you to leave the call being all too interested in what we said there. This is a very early kind of discussions. But I think it is the view in that market that a second pipe really is needed. And I think it's clear that certain producers with significant production coming online have been holding, if you will, holding commitments back in order to help underwrite a second pipeline. And so it does look likely that something will be built. We have the same advantages that we talked about when we talked about Gulf Coast Express, which is there's some and with the right makeup partners, there's good upstream connectivity, and we have great downstream connectivity to get that gas to the markets that are really booming right now, which is along the Texas Gulf Coast, both for Mexico exports, as well as power and pet-chem demands and LNG. And so we think we've got - that we have some advantages in that, but it's in the very early stages, so don't get too interested just yet, I would say. But I think you're right, the fundamentals are strong and I think they support a second pipeline getting built. The gas is growing rapidly in the Permian, and it is a low cost, if not a negative cost to produce or sure primarily aiming at NGLs and crude out there. And so finding a way to deal with a gas or not to have flare is a very important and people, I think are beginning to - shippers are beginning to - are rapidly catching up to that and thinking about ways to relieve those constraints. In the meantime, the smaller bottleneck, debottlenecking that's kind of what we're doing on the EPNG investments that I mentioned, we're looking at some things on NGPL as well, and we will continue to look for those as well take away from EPNG as these markets – as these suppliers are hunting markets.

That’s all, very helpful. Thank you for taking my questions.

Hi, Shneur.

Hi. Good afternoon, everyone and congratulations to everyone on the promotion. Just a quick follow-up to Jeremy's question there. Could GCX be brought into service you know, given all the demand that everyone is talking about?

No, I think, I mean, we’re certainly trying to do everything we can to get it online as soon as possible. But I think our fourth quarter of '19 to the Gulf Coast is really the most realistic timeline.

Okay, great. Just a couple of questions. First, starting at a high level, I think we've all beaten the FERC to death at this point. I was just wondering if you can talk about returns on capital deployment as you sort of think about your business over the last couple of years and kind of you've upped your CapEx a little bit, and you're looking at another project. When one looks at capital returns, are you achieving the returns that you've outlined in the past? Has the erosion in commodity prices at CO2 kind of masked some of those returns? I was wondering if you can sort of talk about that a little bit?

Yes, good question. We have done well on our project execution and Kim actually went through that, and you'll see it look back from 2015 through 2017 on capital projects and how they came out as a multiple of the year two EBITDA, meaning once the project is fully up and running. And we've done very well, and we've done similar backward looks at our gathering and processing investments, et cetera. The new investments that we talked about this quarter are at about six times rate. And so I think we're doing quite well there. And you're right, there's been some deterioration. If you look over that whole period, 2015 to 2017, there's been deterioration in the underlying CO2 business because of lower commodity prices primarily. There have also been some contract rollouts. There is also been some JVs and asset divestitures that we've undertaken in order to improve the balance sheet. So we've retired over $5.8 billion of debt since late in 2015, and we've improved our multiple from 5.6 to 5.1 times. So we are, as Rich said, we're using our cash, deploying it effectively on projects, and we're using our cash to deleverage, as well as return value to shareholders and I think we've done that effectively over the last two to three years.

And kind of two quick follow-ups. One, you were just talking about the return of capital and so forth. You've bought back some shares during the quarter. At the same time, you've upped your CapEx estimate for this year. How should we think about your discretionary cash flow that you outlined, I believe it was about $565 million at the Analyst Day in terms of its ability to continue buying back stock. And I guess, compare with the fact that you're suggesting that you can beat your guidance or projected plans for this year?

Well, if you look at the situation, of course, we're very clear that we have that number that we showed you, that $550 plus million of free cash flow after funding all of our capital expenditures for the year and obviously, after paying the dividend. Since that time, we have bought back $250 million worth of stock, and so you could deduct that. And then as the capital moves around, the total expansion CapEx, which as Kim said, now rose to 2.3 instead of 2.2, you would also deduct that. Our projections which show we will still, after everything we've done, all the capital we have in the plan and all the stock buybacks we've done thus far, we are still nicely positive in terms of actual cash generated after we pay for all these things internally.

And so in terms of how to use that cash is the same things we talked about at the beginning of the year and Rich talked about earlier in the call, which is we'll look at what's of the best use, whether it's an incremental project or the return of additional value to shareholders through a share buyback or further delevering, and it's nice to be in this position.

Great. And one final question. During, I think, it was the last quarter or two quarters ago, there was a lot of talk about Double H and the potential for NGL repurposing. But at the same time, the production level for crude in the Bakken has continued to grow and other takeaway pipelines have been filling towards capacity. Do you see a trend of improving crude production and heading towards Double H and therefore there's no real need to really think about an NGL repurposing or is that still on the table?

Yes, we don't have put together an NGL repurposing project, but the second part of what you said is also true, which is production is rising in the Bakken. And so some of our discussions around that pipeline have turned toward how do we get more of that production into Double H, and we've been able to successfully buy and attract some volumes, including truck volumes over to Double H, and so that's been a positive There's still a bit of capacity overhead to work through in the Bakken, but the production there has been very promising from a gas NGL and oil standpoint. So prospects, I'd say, are improving there.

Great. Thank you very much, guys.

Good afternoon.

Good afternoon. Congrats to everyone who received the promotions today. My first question is on the buybacks. You've done $500 million thus far, you have $1.5 billion still left. Are you done for this year? Or should we expect you to continue buying back more shares this year?

I mean, as we just went through the free cash flow, we have a little bit of free cash flow still remaining. I think at this point, we're going to look and probably wait a little bit to see what the capital projects look like and see if there's any more of those. But depending on what happens with CapEx, there may be the opportunity to buy back more shares and or pay down debt.

Thanks for that. And given where the stock is sort of trading right now, have you thought through at all about maybe deploying that elsewhere perhaps just paying down debt, instead of buying back shares?

Well, I think we will look at that on an opportunistic basis. I think the important thing here, and I hate to keep beating the same drum, but we're in a unique and very positive situation in funding all of our expansion CapEx with internally generated funds, paying the dividend and still having sizable excess cash to use, and we're going to consider that very carefully. And as I said in my opening remarks, we want to be fiscally responsible in how we handle that capital. So we will look at it, just amplifying what Kim said, we would look at it on an ongoing basis to figure out what makes the most sense. And look, we've improved - since we scatter out, as we’ve improved our balance sheet considerably. As Steve said, we've paid down well over $5 billion worth of debt. We are now target 5.1 times debt to EBITDA ratio at the end of 2018. We will meet or beat that, we think, and so we're moving in the right direction, but we would like to get it lower obviously. And so that's a weighing process between delevering and buying back shares.

Thanks for the color Rich. Moving on to the backlog. I noticed in the release that you're now deploying organic growth ex Trans Mountain at 6 times. I know that previously, you said that, that number was 7.5 times and 6.7 I think, is this improvement that you've made a function of you just being able to deploy capital more efficiently, can we get some color into that dynamic?

We look at every project individually, and so we want to get the highest return we can get that the market will pay. And the - and so we will look at, we'll look at the underlying risk on the project and will demand a higher return or we'll get as much as the market will bear. We have, I think, the numbers you were talking about is more like 6.5 and 6.7 times. It's kind of toggled around that. I wouldn't read anything different into the fact that this slate - particular slate of projects that we're talking about is at 6 times. We're applying the same criteria we've been applying for several years now, which a couple of years now, which is elevated return criteria well above any reasonable calculated cost of capital and we'll try to get absolutely as much as we can from the market. And so long as we are clearing by a substantial margin our cost of capital, we'll deploy that capital if it's the best use of that cash. We've targeted at 15% unlevered after-tax return, but we don't reject anything we come in and discuss it, right? Some things are better than the 15% unlevered after-tax return have too much risk associated with them, and they don't make the cut. Some things that are below 15% but have risks with long-term reservation-based contracts, we relax that 15% and we just continued - we have continued on that path.

Thanks for that. Last one for me. What was the CO2 CapEx number…

$91 million.

Hi, Jean.

Hi, good afternoon. I had a few questions about the Permian. So one more on gas. On your existing gas pipeline out of the Permian, is there any room at all for expansion through compression or is this it?

Yes, I mean, certainly some of the projects that we're doing on EPNG are those types of projects, very minor CapEx, squeezing out additional capacity from our existing network intrastate, I think were largely fairly filled out and that has a lot to do with why we're involved in GCX. So I would say those are really the two main areas. We've also balanced some opportunities off NGPL, and some of that has been executed on, and we are pursuing a bit more as well. So I think all of those are very low cost, high-return opportunities, and we're pursuing every bit that we can.

And then we've seen - and it's been in small chunks so far. But people looking for any outlet out of the Permian, including our Trans Colorado system, even giant have seen some of the effects from the growth in the Permian basin. So that's not expansions, that's existing capacity. So filling up kind of all the nooks and crannies coming out of the Permian to get to a different market.

Okay. And can you put any numbers at all, I guess, in terms Bcfd on how much more you can actually get out on El Paso and NGPLs? Or it’s too early to say?

Yes, that's hard to say. It's kind of - as you can tell from the map, it's kind of a network out there. So it depends just on what installations you could put where, whether it's back pressure regulators, which are very cheap or compression, which is more expensive and other connections or things like that. It's a network.

Sure. And then I believe you and operate or maybe used to operate a rail terminal in the Permian? Can you confirm if you still have that and what's the crude by rail loading capacity available is if you do?

Ask any longer and I think generally speaking in the Permian, there's not significant current crude by rail unit train capacity. So there's manifest capability, but a manifest cargo capability but not unit train capability, is that right? Okay.

And then one last one. I think you touched on this when you discussed the hedges. But you hedged your EOR production with WTI, but do you have crude transport out of the Permian? Or do you mostly receive a Midland price for your barrels and are kind of exposed to that spread?

We do have transport out of the Permian, including with our wind pipeline assets, which takes a significant amount of our production to Western Refining in El Paso. But we also, as part of our hedging program, we hedge quality and locational differentials. So we've hedged for 2018, we're at about 68%, I think, of mid-cush hedged?

71.

71% of mid-cush hedged and we're continuing to add to that position as we go through 2018.

That’s very helpful. That’s all from me. Thank you.

Hi, Darren. How are you doing?

Hi, Rich. Good afternoon. And congrats to everybody on the promotions. Steve, my first question is on CO2. Do you guys have a rough estimate of the cost or attune profile per barrel in order to monetize this incremental transition zone barrels versus in smaller fields? Because I know you talked and you guys had put out some slides on the after-tax internal rate of return, but on a risk-adjusted basis, I'm just wondering how to think about return on investment going forward with how you allocate those additional dollars?

I'll start, and Jesse will finish. So the - one of the great things about the transition zone development is that we can - it is sitting below the area that we are already developing with CO2. So that when we develop a project, we go hit the traditional CO2 flood zone and exploit that, but with a little bit of deepening and sometimes we can even use existing wellheads, wellbores, for that deepening. We can access transition zone barrels. And so what happens Darren is we get both. We get - we get it from our traditional harvest area, as well as we pick out incremental barrels from the transition zone in those places where we found that. And so far, we found it in a number of places. And so I think roughly speaking, it's like 28%, 72%, 72%, 70-30 call it of traditional CO2 flood recovery with another 30% transition zone coming from that deepening. Is that about right, Jesse?

That's right.

That makes it capital-efficient, that's the bottom line.

And how much of that, if any, is built on the $1.6 billion growth backlog forecasts from 2018 out to 2022? Because I know that you guys have already experimented on what five transition zone wells in the budget this year is two, is that correct?

That in terms of development.

There is very little of that associated with the backlog. So this is very early, and we're still delineating the field so there's - it's a very little of that $1.7 billion.

And coming out in CO2, in particular, and also gathering of processing, that capital moves around to chase the best opportunities.

So, Steve, as this evolves theoretically more focused on the transition zone going forward, based on those rate of returns that you guys have discussed, how do you expect the aggregate segment return on investment to evolve over the forecast period within which you're going to spend that $1.6 billion?

You're beyond any update that we try to do, Darren, we're not there yet.

Okay. If I could just one final question for me on Elba. What's the expected timing of the liquefaction capacity between initial and service in the third quarter of this year and when you guys reached 10 liquefaction units by the middle of 2019? And also how do we think about the timing of the remaining capital spend over those four quarters?

You want to speak?

So, yes. I mean, you have the timeline correct. The first unit will be online in the third quarter and it's approximately 30 to 45 days sequentially from that point. So that gets us kind of end of the late second quarter or late third quarter of 2019.

And as you probably recall, the return on that or the economics on the liquefaction development are heavily weighted to Unit 1. And so Unit 1, we expect will be coming on and followed within roughly the sequence time laid out by Units 2 and 3 starting in the third quarter. We'll not get into the third quarter, but Unit 1 is expected to get in, in the third quarter.

Okay. Thank you.

Good afternoon, Keith.

Hi, good afternoon. Just wanted to clarify on the growth backlog. The $900 million addition in Q1, that does not include Gulf Coast Express that was already in the backlog, is that correct?

You are correct. We put that in, in the fourth quarter update that we shared in January. But that's just on top of that.

Can you just give color on maybe one or two of the largest additions to the backlog in terms of the projects and the timing of them coming into service? I think some of the other opportunities you've mentioned around the Permian are a little smaller in terms of capital?

CNP gets about $500 million, and then the interstate projects across, I guess, really three different regions, so another 300.

Got it. Okay…

Again, of the 900, 820 is natural gas. So that's overwhelming in the Natural Gas segment.

Got it. Okay. One, just on Trans Mountain. One of the principles you laid out pretty clearly is the need for certainty to construct across British Columbia. When you think about some of the discussions on potential financial arrangements with the federal government, can that help address that criteria that one criteria or do you also need some type of specific action or change separate from financial support to give you more confidence you can build across BC?

Yes, there are really two separate things. I mean, there needs to be a way, most of the project and most of the investment is in British Columbia where the government is in opposition to the project and has looked for and found ways to incrementally regulate it. And that is an issue that, in our view, needs to be resolved or addressed in order to be able to successfully construct in the province. And so we think of this two separate or related things.

Thank you.

Good afternoon, Dennis.

Good afternoon to you Rich. Thanks. And my congrats to everyone there on the promotions. A couple for me please. Steve, I wonder if the - back to the FERC issue, I guess, one comment I want to just dig a little bit into. You talked about is this being a time-consuming process sort of at the end of your statement there. And my recollection is the commission, when they were making these decisions, sort of were thinking that these would be a fairly quick process. I want to say they talked about it being done by as early as the fall of 2018. I wonder, maybe if you can just talk about the differences or compare those two views and maybe give some scale of how you think about the timing and how long this will take?

Right, so the FERC has laid out a specific schedule in three or four tranches of filing of these 501G forms, right, and so that's pretty well defined. But that's just the beginning. There's a lot more and for reasons I said earlier, I mean, these forms, I think, are going to be less informative, particularly on the issue of over earning and people are expecting because there are some assumptions built into those instructions that we believe conflict with frankly, what we think a commission is ultimately likely to do. So there is a process of information gathering that's on a very firm timeframe. There is still the whole note for itself, which is a proposed rule and a separate but related notice of inquiry, which is an earlier step even in the process that has to be worked out, and that's the process within which we'll be filing comments and making our case known and seeking some modifications to the rule, the proposed rule. And then there are those processes themselves, rate proceedings themselves, and those are expensive, they're time-consuming, and that's why we have some confidence around the idea that this is going to ultimately play itself out over time.

Okay, so the idea of a 130 pipelines all getting done by the fall is not realistic? In terms of the 501G filing themselves, they have to be filed, and I thought it was a 30 day process. Is that seems like you're indicating that there's some variance there?

No, there's a phased-in and they've listed specific entities and what wave they're in so there are specific dates for filing a 501G for each individual regulated system.

Okay…

Four separate ways.

Okay. Thanks for that. One quick question on the leverage number. You say, Kim, that you'll be 5.1 times or potentially below and I just - I want to just clarify that a little bit if I can in terms that's on the existing budget, that doesn't include any assumptions about Trans Mountain going forward or not? I think when you may be announced a couple of weeks ago if there was some indication that it would be two times lower if that doesn't proceed?

Right. So what we've assumed in the 5.1 times or better is a similar but updated assumption that we had in our budget, which is we spend it at a reduced rate through May, and then the spending would ramp up. If Trans Mountain were terminated then we think longer term, not this year, but longer term, because you have incremental spending and would have incremental spending in future years if you pursue the project longer term, there will be a 20-basis point reduction versus what we would have thought if the project went forward in 2019.

Got it. Okay. Thanks for that. Just one last one for me. In the KML release, there was some discussion about lower rail loadings in the quarter from Canada. I wonder if you just might talk a little bit about that with the wide bps that surprised me a little bit.

Its rail service related. The service has been - vary a bit more in that area and the Imperial has been negotiating directly with the CN and the CP for improvements in that. And we have seen an uptick as the quarter progress, but it was down significantly throughout the quarter. We hope that, that will improve as we go forward here.

It's not because the barrels don't want to move.

Right. That's what surprised me. Anyway, that's weather-related or any particular reason or just poor service?

It was all poor service-related. And remember, that facility was all 100% take or pay related, so it didn't have as big a financial impact, but we would like to see the barrels delivered.

Okay. That’s it from me. Thanks, everyone.