Kinder Morgan Inc - Class P (KMI) — Q3 2019 Earnings Call Transcript

Thank you, Britney. And 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. In my opening statements on these calls before turning it over to Kim, Steve, Dax, and the rest of the team, I always try to share with you our vision for the future and our financial strategy. On the financial front, I believe we continue to execute on our plans and our decision to sell our 70% interest in Kinder Morgan Canada and our 100% interest in the U.S. portion of the Cochin Pipeline is indicative of that execution. As you know, we are receiving a 13x multiple of EBITDA on our Cochin asset, which is well above the multiple at which KMI is trading as a whole on the New York Stock Exchange. Now, we're able to use the proceeds from these sales, and Steve will talk more about this later, in a manner consistent with what we have previously indicated to maintain a strong balance sheet, expand our core assets, pay a healthy and growing dividend, and opportunistically buy back our stock; all these uses we believe benefit our shareholders. I should add that we received expressions of interest in other assets at similar or higher multiples of EBITDA. And let me say, there is absolutely no certainty as to whether these expressions of interest will result in transactions. That said, we will evaluate such interest as a matter of good governance and capital discipline. All this just indicates a substantial difference between the valuation of individual assets and that of the company as a whole when expressed as a multiple of EBITDA. Turning to our vision for the future, on last quarter's call, I described our positive outlook on the future of natural gas, which is very important to us as we move about 40% of all the natural gas in America through our pipelines. Incidentally, that positive outlook was reinforced in the September report of the U.S. Energy Information Administration, which projects that natural gas consumption will increase by 40% between now and 2050, even in a case where renewable energy rises dramatically. Today though, I'd like to talk about the environmental impact of this growing natural gas utilization. First, the positive side of the story. The EPA has reported that from 2007 to 2017, total CO2 emissions in the U.S. have dropped about 14%. Even more impressive, CO2 emissions from the electric power sector have dropped approximately 26% during the same period of time notwithstanding an increase in the absolute amount of electricity generated. This is largely the result of new natural gas-fired power plants replacing older and dirtier coal plants, since natural gas emits approximately half as much CO2 compared to coal when burned to produce power. This is a huge accomplishment and demonstrates that the answer to minimizing our impact on the environment isn't simply banning fossil fuels but rather utilizing them responsibly. The tremendous growth in natural gas production in America has also led to its shipment as LNG to developing countries around the world to replace coal-fired electricity generation with cleaner natural gas. These positive developments are pretty consistently accepted across the political landscape, but the naysayers on natural gas emphasize that its production and transportation emit too much methane into the atmosphere. There's some disagreement over the extent of these emissions, but it's clear that they are low and continue to drop, due primarily to industry-led initiatives. Let me share some numbers. U.S. methane emissions from natural gas systems declined more than 14% between 1990 and 2017, despite a 53% increase in natural gas production over the same period. U.S. methane emissions as a whole, across all industries also decreased by 16% during that timeframe. You might be interested to know that methane emissions from enteric fermentation, which has to do with the digestive tract of farm animals and manure management, actually rose by 18% during that same time. If you excluded those two categories, total U.S. methane emissions were actually down 27% during that time frame. Now all that said, our industry still needs to continue to address this issue, and we are. KMI is a founding member of ONE Future, a voluntary industry initiative committed to achieving a methane leakage rate of 1% or less along the entire natural gas supply chain by 2025. In fact, our members' rate is now well below that 1% target. More specific to us, the group's target for emissions in the transportation and storage segment is 0.31%. KMI has already substantially outperformed that goal with emissions from that segment of 0.04% in 2017 improving to 0.02% in 2018. In summary, our view is that the methane emissions issue is solvable, will continue to improve, and the environmental positives of natural gas far outweigh the negatives. And now, I'll turn it over to Steve.

Thanks, Rich. I'm going to start with KMI, then turn it over to our President, Kim Dang, to give an update on our segment performance. Our CFO, David Michels, will take you through the numbers; and Dax Sanders will update you on KML, and then we'll take your questions. So, summary on KMI is this: we are adhering to the principles that we've laid out previously for you. We have a strong balance sheet having met our approximately 4.5 times debt-to-EBITDA target and with ratings upgrades now from all three ratings agencies. We are maintaining our capital discipline through our return criteria, a good track record of execution, and by self-funding our investments. We are returning value to shareholders as evidenced by the 25% year-over-year dividend increase, and we continue to find attractive growth and/or divestiture opportunities. Again, strong balance sheet, capital discipline, returning value to shareholders, and finding additional opportunities, those are the principles we operate by. During the quarter, we announced that KML had reached an agreement with Pembina Pipeline Corporation where Pembina would acquire all of the common equity of KML including KMI's 70% interest, and that KMI would sell the U.S. portion of the Cochin pipeline to Pembina for $1.546 billion. The closing of the transactions is conditioned, and closing remains on track for late Q4 this year or first quarter 2020. Consistent with the principles I just stated, KMI expects to use its proceeds to reduce debt to maintain our net debt-to-adjusted EBITDA ratio of approximately 4.5 times and use remaining proceeds to invest in attractive projects and/or to opportunistically repurchase KMI shares. And as we said when we announced the transaction, initially the proceeds will be used to reduce net debt before being put toward these investments or repurchases. Other milestones for the quarter: we placed the first unit of our Elba Island Liquefaction Facility in service on September 30. We were delayed here, obviously, and that has been a drag on our financial performance as you'll hear from Kim and David; but Unit One is in service along with the balance of plant, meaning that we are now earning 70% of the project revenues. And when you count also the facilities that we own at the 100% level to KMI's share specifically, it's about 80% of the total project revenues, both the joint venture as well as the facilities that we own 100%. The remaining nine units are on the island and we expect to place three more in service this year with the remaining six coming online next year in the first half. We also placed Gulf Coast Express or GCX in service in September. This project was a few days early. It's full. We need another one; the market needs another one. And that brings me to our 2 BCF a day Permian Highway Pipeline Project. That project is progressing well. We have about 85% of the right-of-way acquired and currently expect that we're going to timely acquire the easements we need. We've also made good progress on the permitting front. However, we are still obtaining some of the regulatory authorizations that we need, and that has progressed a little more slowly than what we put in our plan. That means in order to do efficient construction, we'll kick off the construction a little bit later and that means that instead of a fourth quarter 2020 in service, we currently anticipate early 2021. Both of our Permian Gas Pipeline projects are fully subscribed under long-term contracts that generate attractive returns and both projects bring us additional opportunities in our downstream pipelines, as on a combined basis they bring 4 BCF a day incrementally to a system that moves about 5 BCF a day today. Those projects bring opportunities for downstream expansion. In fact, two LNG facilities are projected to drive demand growth, and our backlog includes about $325 million to expand and improve connectivity along our Texas Intrastate pipeline network in order to enable us to place the incremental volumes that will be hitting our system and are now hitting our system. We are still working with customers on a third 2 BCF a day pipeline called Permian Pass. This is a work in progress. It's not in the backlog at this point, and since we reported on this on the second quarter call, the commercial activity has slowed, but it continues. It slowed as a result of some producer retrenchment in their Permian activities. We believe the pipeline is needed, but it may not be needed quite as soon as we were expecting three months ago. With a total of three new 2 BCF a day projects coming online over the 2019 to 2021 period, both of ours as well as the third-party pipeline, the Permian Pass Pipeline may not be needed in 2022. In the meantime, we're continuing to work with customers and potential partners and believe the long-term dynamics of needed gas takeaway capacity out of the Permian Basin and our extensive pipeline network in Texas put us in a good position. These Permian projects demonstrate us taking advantage of a very positive situation for our business. There's large supply growth in Texas and large demand growth in Texas. We can bridge the two and connect to our Premier Texas Intrastate pipeline network on the Gulf Coast and stay entirely within the state of Texas, where we have more commercial flexibility. As we pointed out at the conference, 70% of natural gas demand growth between now and 2030 is projected to be in Louisiana and Texas, and our systems are well-positioned to benefit from that. As we said last quarter, we believe we have FERC's 501-G process largely behind us with the settlements we did on TGP and EPNG and several other of our systems. The outcomes were hard to predict when we were putting our budget together for 2019; so we did not project them in the 2019 budget. However, as we said when we announced— or when we came out in January, if we got these things done, it would be a positive to the long-term value of our networks as it would help us resolve rate risk. We feel even more strongly about it, or I feel even more strongly about that statement sitting here today. The last two Kinder Morgan pipelines with pending 501-G filings are on tomorrow's FERC meeting agenda; both of those systems are currently under rate moratoria, which the commission has been honoring. Again notwithstanding the headwind to 2019, we are delighted to have the 501-G risk largely behind us. Finally, on our backlog, the backlog fell quarter-to-quarter and now stands at $4.1 billion. That's primarily because we placed Elba Unit One and GCX—two of our largest products—in service at the end of the quarter. We will remain disciplined here. We seek returns that are well above our cost of capital in order to deploy capital. We believe based on our historical experience and on the size of our network and the market dynamics at play, particularly in natural gas, that we'll continue to provide the opportunity to invest in $2 billion to $3 billion a year in attractive return expansion projects. But importantly, if we don't find that much in new opportunities, we are not going to force it. We have other opportunities to deliver value to our shareholders, and we expect to maintain our discipline. We will maintain our discipline. With that, I'll turn it over to Kim.

Thanks, Steve. I sound like a broken record, but natural gas had another outstanding quarter; it was up 8% this quarter. Natural gas demand this year is expected to increase by approximately 4 BCF a day over 2018. And so it's been the case all year, this growth is driving volume increases on our pipes. Transport volumes in our transmission pipes, which is how we refer to our large diameter pipes, increased by approximately 4.15 BCF a day or 13%. This marks the seventh quarter in a row on which volume exceeded the comparable prior period by 10% or more. So, if you look on our system to see where these volumes showed up: EPNG volumes were up just under 1.2 Bcf a day, primarily due to increased Permian volumes and California storage refill. TGP volumes were up 700 a day due to expansion projects. Kinder Morgan Louisiana volumes were up approximately 680 million cubic feet a day due to LNG exports. So, overall, for Kinder Morgan, deliveries for LNG exports were approximately 2.5 Bcf a day. That's an increase of almost 2 Bcf over the third quarter of 2018. CIG volumes were up 585 million cubic feet a day due to increased DJ production and coal to gas switching. GCX started flowing volumes in August and went into service at the end of September, so it averaged about 325 million cubic feet a day over the quarter. GCX is currently full, flowing 2 Bcf a day. Rig volumes were up approximately 250 million cubic feet a day due to increased DJ and Powder River Basin production. On the gathering assets, volumes were up 12% or 350 million cubic feet a day, primarily driven by higher volumes in the Haynesville and in the Eagle Ford. Overall, natural gas wellhead volumes out of the key basins we serve continue to increase: Permian Natural Gas Wellhead volumes increased by 22% in the third quarter versus the third quarter of 2018; Haynesville increased 22%; Bakken increased 20%; and the Eagle Ford increased 30%. Our product segment was also up nicely in the quarter. Here we saw nice increases in our refined products business, primarily on SFPP due to higher average tariff and lower expenses. Refined product volumes were up just under 1% across our pipes versus the EIA numbers, which were down approximately 1.3%. Our crude and condensate business was essentially flat. Contributions from our Bakken asset were offset by reduced contributions from KMCC. As has been the case all year, increased volumes on KMCC were more than offset by lower rates. Overall, crude and condensate volumes were up about 4% in the quarter. Terminals business was down about 1% in the quarter. The liquids business accounts for about 80% of that segment. It had nice increases coming from expansion projects. The largest was from our baseline terminal expansion project in Edmonton. However, these increases were more than offset by the increased lease expense at our Edmonton South terminal, which became a third-party obligation post the Trans Mountain sale and a variety of smaller items. We added about 400,000 barrels of tankage versus the third quarter of 2018. Our baseline project in Canada was the largest addition. Total leasable capacity is now over 89 million barrels. I'd also point out that we have taken Staten Island out of service and removed those barrels from all periods in our volume highlights. Gasoline and distillate volumes, which don't have a material impact on our business given our contract structure but do give some insight into the underlying fundamentals of our business, were up nicely in Houston and the New York Harbor. Our bulk business was up modestly and bulk volumes were down approximately 6% due to lower coal and pet coke volumes. Finally, our CO2 segment was down in the quarter, primarily due to lower commodity prices, but also due to lower crude and NGL volumes and higher power prices. Our net realized crude oil price was down $8.50 per barrel approximately. NGL prices were down approximately $15 per barrel. Net crude oil production was down approximately 7%, primarily due to lower production across all of our fields. However, at Yates, timing on the sales of the crude produced during the period is skewing the numbers. And at SACROC, we did have some field-wide maintenance which impacted performance. We adjusted for these items. Production was down approximately 4.5%. We expect free cash flow from the segment, that's DCF plus expansion CapEx to be approximately $350 million for 2019, which is approximately $30 million better than our budget. This improvement versus budget is due to lower capital expenditures primarily because we elected not to proceed with Phase 3 at Tall Cotton as it did not meet our return requirements. With that, I'll turn it over to Dave Michels.

All right. Thanks, Kim. Today we're declaring a dividend of $0.25 per share, the same as last quarter and in line with our budget to declare $1 per share for the full year of 2019, which is a 25% increase over the $0.80 per share that we declared for 2018. KMI's adjusted earnings per share and DCF per share both grew from last year's third quarter. We generated DCF per share of $0.50, which is two times or approximately $570 million in excess of the declared dividend. In addition to the quarterly performance, our press release provides an update to our 2019 outlook. We are now expecting to end the year with adjusted EBITDA of about 3% below our budget and DCF slightly below our budget. Two discrete items that contributed to the variance were: one, the delay we experienced in placing our Elba Island facility in service; and the 501-G settlements. The Elba delay while disappointing is largely behind us now. Now that we're recognizing majority of the revenues for that project just as Steve mentioned. The 501-G resolution, while it wasn't in our budget was a positive outcome for Kinder Morgan. So, moving on to our quarterly results. As you can see, we are using our updated format for earnings, so we hope you find this to be an improved presentation of our financials. I'll start with our GAAP performance then I'll move on to our non-GAAP performance. Revenues were down 9% from the third quarter of 2018, but the decline in cost of sales more than offset that lower revenue amount, meaning gross margin actually improved from the prior period. Some of that gross margin benefit came from non-cash losses that we experienced in the third quarter of 2018, which we treat as certain items and exclude from our non-GAAP metrics. Excluding certain items, gross margin was in line period-over-period. Net income available to common stockholders was down $187 million or 27% due largely to a gain on the sale of our Trans Mountain Pipeline, which we took during the third quarter of 2018 and is also treated as a certain item. In our materials, we call net income available to common shareholders adjusted for certain items, adjusted earnings. Our adjusted earnings were up $39 million or 8% compared to the third quarter of 2018 and adjusted earnings per share was $0.22 for the quarter, up $0.01 or 5% from the prior period. That includes the additional shares that resulted from the conversion of our preferred equity securities to common shares in October of last year. Moving on to our DCF performance. Natural gas was up $85 million or 8% for the quarter. We saw greater performance versus last year across multiple assets. Excess interest rates benefited from the GCX commissioning and in-service; EPNG was up, driven by Permian supply growth, which more than offset the unfavorable impact that it experienced from the 501-G rate case impacts. TGP had increased contributions from multiple expansion projects placed in service. Cochin had increased contributions from higher volume and rate. Kinder Morgan, Louisiana pipeline was up due to the Sabine Pass expansion. For our products terminals and CO2 segments, Kim touched on the main drivers behind our financial performance there. Kinder Morgan Canada was down $32 million, as a result of the sale of Trans Mountain Pipeline last year. G&A expense was higher by $14 million due to higher non-cash pension expenses, as well as lower overhead capitalized to our projects. And those are partially offset in G&A by lower G&A resulting from our Trans Mountain sale. So that explains the main changes and adjusted EBITDA, which was $23 million, or 1% below Q3 2018. Moving below EBITDA, interest expense was $21 million lower, driven by our lower debt balance. Sustaining capital was $21 million lower versus Q3 2018, mainly due to the timing of pipeline integrity work. We budgeted to spend more in sustaining capital for the year, this year full year versus last year, and we're still forecasted to do that, though we are trending to come in favorable to our budget for the full year. Preferred stock dividends were down $39 million as a result of the conversion of our mandatory convertible securities last year. Other items, our unfavorable $22 million driven by a larger cash contribution to our pension plan this year versus last, so total DCF of $1.140 billion, is up $47 million or 4%. To summarize the main drivers, greater contributions from our natural gas and product segments, lower preferred stock dividends, lower interest expense in sustaining capital, partially offset by lower contributions from our CO2 segment, driven by lower commodity prices, the sale of Trans Mountain Pipeline and a higher cash pension contribution. DCF per share of $0.50 was up $0.01 or 2% from last year. The same drivers as DCF, but that includes the impact from the incremental shares issued as a result of our preferred stock conversion. For the full year versus our budget, EBITDA as I mentioned is expected to be 3% below and the back the drivers of that variance include lower oil and NGL prices as well as lower volumes impacting our CO2 segment, the Elba delay in the 501-G settlements, partially offset by greater contributions from EPNG, resulting from strong Permian supply growth. Full year DCF is expected to be slightly below budget, due to the same items impacting EBITDA as well as the benefit of favorable interest expense and an add back of non-cash pension expenses. Moving on to the balance sheet, we ended the quarter at 4.7 times debt-to-EBITDA, slightly higher than the 4.5 times at the beginning of the year 2019 and we forecast to end the year with leverage at 4.6 times, which is the same year-end level we announced last quarter. Adjusted net debt ended the quarter at $35.2 billion, up about $380 million from last quarter, and an increase of $1.073 billion from year-end 2018. To reconcile the change in the quarter, we generated DCF of $1.14 billion. We spent about $700 million on growth capital and contributions to our joint ventures. We paid out $570 million of dividends and we had a working capital use of approximately $250 million, mainly interest expense payments in the quarter, so that gets you to close to the $380 million increase in debt for the quarter. For the full year, we generated DCF of $3.639 billion. We spent $2.2 billion on growth capital and joint venture contributions. We paid out dividends of $1.59 billion. We paid taxes on the Trans Mountain sale of $340 million and we had a working capital use of about $550 million largely interest payments also being the largest use. And that gets you to the main pieces of the $1.073 billion increase in adjusted net debt for the year. I'll now turn it back to Steve.

Okay. And we're going to update you on KML, progress on the transaction, as well as the financial results stats.

Thanks, Steve. Before a few brief comments on the numbers, I'll update you on where we stand on the pending sale of KML to Pembina. Consistent with previous comments, we still expect the deal will close either late in the current quarter or in the first quarter of next year. At this point, we have received early termination of the U.S. Hart-Scott-Rodino review period, which is a condition to close. The remaining conditions to close include KML shareholder and related court approvals and other regulatory approvals including approval by the Canadian Competition Bureau, which we expect will be the longest lead item. With respect to shareholder approval, the common and preferred shareholder meetings are scheduled for December 10th. As a reminder, while there will be a vote of the preferred shareholders on a proposal to exchange KML preferred for Pembina preferred as part of the transaction, closing of the transaction itself is not dependent upon that vote or any approval of the preferred shareholders. With respect to approval by the Canadian Competition Bureau, we are proactively engaged with Pembina and the Competition Bureau to respond to requests for information in order to facilitate the bureau's review. Now moving toward 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 previous guidance. Earnings per restricted voting share from continuing operations for the third quarter are $0.08 and that is derived from approximately $16.6 million of income from continuing operations, which is the same as net income. Income from continuing operations is down approximately $5.6 million versus the same quarter in 2018. Looking at the largest drivers of that variance, revenue increased across most of KML's assets and was led by the contribution from the Base Line Tank and Terminal assets, being fully online in increased contributions from Cochin due to the indexing of rates and the timing of incremental volumes in 2019. However, the increase in revenue was more than offset by higher G&A, mostly associated with the cost of selling KML and lower interest income due to the non-recurrence of income on the Trans Mountain sale proceeds received in 2018. There were several other smaller moving pieces including slightly higher O&M and DD&A and lower income tax expense. Total DCF from continuing operations for the quarter is $47.8 million, which is up approximately $8.8 million from the comparable period in 2018. Beyond the items I've already mentioned, cash taxes were favorable by $9.8 million. That $9.8 million is driven by a refund received in the third quarter of 14.7, representing the overpayment of cash taxes for 2018 netted against $5 million of installments made for 2019. Looking forward, as we said in the release, we expect our results for the year to be consistent with our budget of approximately $213 million in EBITDA and approximately $109 million in DCF. Finally, as we said in our release, due to the transaction and the lead up to it following the announcement of our normal course issuer bid buyback, we will not utilize any of that program at this point. And with that, I'll turn it back to Steve.

Okay. We're ready to answer questions on both entities. And as we've been doing here recently, we're going to ask that you limit your questions per person to one question with a follow-up. But if you have additional unanswered questions, get back in the queue and we will get back to you. All right, Brittany, if you could open it up.

Good afternoon.

Good afternoon. So, just given the backlog that you all have in place today, is there a scenario where operating cash flow is sufficient to fund both the dividend and the capital program in 2020? I guess, as a follow on, when would you expect to make decisions regarding proceeds from Cochin and PBL shares?

Okay. So, we haven't started our 2020 budget process yet. We were taking that up here right quick, but we — so we won't know the final answer to that question. I mean this year with the dividend at the level that it was, we had what we call a self-funding gap of what's projected to be about $100 million, which means we've almost entirely funded our capital program and our JV contributions of around $2.7 billion, $2.8 billion and the dividend out of the cash that we generate. Obviously, with the dividend going up next year, that could be a little tighter. But until we know exactly what we’ve got in the capital plan for next year, we don't have a specific answer. I think it's safe to say we will be largely self-funding our CapEx along with paying the increased dividend next year. On the timing, so we'll have the Cochin — well, when the Cochin proceeds come in, we should — one of us should probably mention, as we said when we announced the transaction, the Cochin proceeds by themselves would take our projected net debt-to-EBITDA to 4.4 times versus the 4.6 times that we talked about earlier. We'd expect that — again as I've said, we would hold that on the balance sheet if you will and wait for the right opportunity. And when it comes to the right opportunity, we'll be looking at capital projects that we have very attractive returns at well above our cost of capital or at share repurchases. The share repurchases we will do opportunistically and not programmatically. And so, we're not talking about specific prices at which we would transact or anything like that, but we'll have the proceeds available. When it comes to the Pembina shares in particular, of course, we would expect to convert those to cash at some point. We represent — the proceeds represent less than 5% of Pembina's trading outstanding stock. So, we think that we can convert those shares into cash in a very non-disruptive way, and we don't have to be in a hurry to do so. And then we'll deploy the capital in share repurchases as I said opportunistically.

Got it, that's helpful. And then just a quick follow-on. And so, understanding that there were impacts from field maintenance in the quarter for the EOR business, should we expect any impact at base decline rates from the reductions in the capital program?

I think that at current — we believe that at current prices, if you think about the smaller fields, Goldsmith, Katz, and Tall Cotton, we would probably — we're going to be managing those for free cash flow not expecting to invest considerable capital in them. That can change if oil prices change. But for right now that would be our plan on those, and we will focus our attention on SACROC and Yates. And that's where most of the oil is anyway, having most of the production in any case. And so, I would expect to see declines in the smaller fields and then we'll see what projects are available to us at the return thresholds that we've set in the two larger fields.

Hi, good afternoon, everyone.

Good afternoon.

Steve, you had previously indicated a CapEx range of $2 billion to $3 billion as the run rate number you've discussed. I understand that you're still in the process of evaluating your capital program for 2020. However, could you share insights on the factors that would lead you to the lower end versus the upper end as you consider the backlog? You mentioned discipline earlier. Does the slowdown in commercial discussions regarding the third Permian pipeline potentially result in CapEx leaning towards the lower end? I would appreciate any additional context on how both aspects might influence the boundaries of your previously provided CapEx range.

Yeah and the short answer to your question on the Permian Pass is that yeah that would bring it toward the lower end until it ultimately gets sanctioned. So, if you think about where these projects are likely to come from, clearly we've got some in terminals and refined products. But the lion's share of the project opportunities as we look down the road are the things that aren't in the backlog right now but in the natural gas sector. And they relate to additional Permian takeaway capacity as well as feeding LNG facilities in the second wave of LNG. And as I said, mostly concentrated on — in Texas and Louisiana and so it's the timing of those project sanctions or sanctioning FIDs that will drive our capital — our backlog and our capital budgets in the years ahead.

Great. I would like clarification on your earlier statement regarding the KML-Cochin sale. On a pro forma basis, you mentioned that you would end the year at 4.4 times compared to 4.6 times. Does this figure not account for the sale of the Pembina shares? Is it based solely on the cash coming in, and would the 4.4 times figure be lower if those shares were also sold?

Yeah. That's just on the Cochin cash proceeds, and it does assume an end of the year close, which is not a certainty. As we've said, we may be able to close as soon as the end of this quarter or early 2020, but if you make that assumption of a close in this year and the use of — and the receipt of the $1.546 billion of U.S. Cochin proceeds alone that's where you get that number.

Hi. Good afternoon. Just wanted to pick up on the CO2 side, that was a bit low, our estimates there. I was just wondering how much CapEx does it take to keep the production flat there or the 4.5% decline rate should we expect that to continue? Any thoughts you can provide there?

Yeah. So, we don't invest in our CO2 business based on what investment level would be required to keep production flat or to grow production in aggregate. The way we invest the capital is if the capital that we're investing and the oil that we expect to free up and sell as a result of it produces a return that clears our return criteria, then we invest. And so, we've had times when SACROC's been up year-over-year. We've had times certainly when it's been down. But we continue to find things to do at SACROC. It's just that we don't invest specifically to maintain production. As I said earlier, I mean, I think you can expect that without capital investment in the smaller fields, you would tend to see a decline there. And as I said, we're going to maintain capital discipline there and we will continue to look for the opportunities to make sense at SACROC and Yates.

Good afternoon. Thanks for taking my question. First one on me, just in terms of thinking about your credit rating and the leverage target, given that you have a clear line of sight here into the actual proceeds and growing free cash flow, do you see any potential to lower your leverage target and maybe aim for a high BBB rating and maybe have a higher age accretion? And how your conversations have been with rating agencies in this regard? And then I have a follow-up.

Okay. Well, I'll start and then ask David or Anthony to fill – or Kim to fill in. But I think we feel good being a BBB class and getting the upgrade from BBB minus. We do evaluate whether it makes sense to improve on that target and that evaluation has so far shown that we really get very, very little cost of capital benefit and in fact, the extra deleveraging that we would do would forestall opportunities to create shareholder value to an extent that we don't think is warranted. But David?

Well, I'll just add that in terms of our – I wouldn't add anything more to that part of your answer to what Steve just said — provided. But I would say, in terms of recent rating agency conversations that we've had. We just got upgraded by all three just within the last year. They went to a thorough analysis on upgrading us. It's very difficult to get upgraded. So they take a very cautious approach. So I think we're in real good standing with them — with our current leverage target and our current leverage.

Got you. And Rich in your introductory comments, you talked about the environmental positives of your business especially on the natural gas side. But one area, I think was missing was your CO2 business and their related EOR although a smaller scale versus your other business. Given that you are trapping carbon dioxide underground in the process, do you think your operation qualifies for ESG eligibility and any governmental incentives? And we have seen one of your competitors in the business talk about it at length, so just wanted to get some of your thoughts there?

So, you're right. We capture CO2 and we put it in the ground and it stays there. And we get valuable oil out as a consequence of that. That has been primarily geologically sourced CO2 really exclusively geologically sourced CO2. There are opportunities to potentially capture man-made CO2, and there are some tax credits to help support that activity. So far in any sizable way, we have not found it to be economic and have not found the sources of available CO2 from large ethanol plants, for example, to be of sufficient — to be numerous and often of a high enough quantity for us to take full advantage of that opportunity. But if you think about the long term and you think that at some point, CO2 sequestration capacity is going to be valuable due to a carbon tax or something else, certainly it's something that we know how to do.

Good evening, everyone. So I wanted to start on, I guess, follow-up on the capital allocation. When we think about what you could potentially do in stock buybacks, should we assume that leverage stays at your targeted 4.5 times? So, like for next year, that it looks like maybe your CapEx shakes out light and your net debt falls below that, that we should think that you would likely buy back stock? And what are the puts and takes to why you would maybe want to take leverage lower or higher than that? Do you think higher with potential M&A opportunities?

We don't anticipate increasing leverage in order to repurchase shares when that's — when it’s above our target. So, we expect to maintain our target as we use our share repurchase program. And as I've said before, we — the share repurchases would come opportunistically. And as I've said on that KML proceeds, we’d likely initially let those be on the balance sheet and then we'll look for the right opportunities to use it. But we're not telegraphing specific metrics or pricing that we're looking for. But let me just say that, obviously, it took us a good amount of time and a lot of work to get where we are now. And we would certainly — that's a fundamental part of our philosophy is to maintain a strong balance sheet. And we can speculate all you want about what might happen in M&A, but let me just say that the Board is very committed to maintaining a strong balance sheet, and that will certainly be a really big factor in any decision we make. And to amplify what Steve said, again as we've said so many times over the last three years, there are four things we can do with the money and all of them benefit our shareholders. I think, we've shown by increasing the dividend, we're returning real value to the shareholders. If you take $1.25 dividend on the stock price, its turning the bar 20, its equivalent return if you look one year out. We have the ability to, as Steve said, substantially fund our own capital projects. We have the ability to maintain a strong balance sheet and we have the ability, at some point, opportunistically, to buy back shares. So, I can assure you that the Board is going to make decisions that are in the best interest of shareholders here. We have a large amount of insider ownership on the Board. So, we're certainly going to look out for what's best for our shareholders.

Okay. Thank you very much. Have a good evening.