Kinder Morgan, Inc. (NYSE:KMI) Q4 2023 Earnings Call Transcript

Kinder Morgan, Inc. (NYSE:KMI) Q4 2023 Earnings Call Transcript January 17, 2024

Kinder Morgan, Inc. misses on earnings expectations. Reported EPS is $0.28 EPS, expectations were $0.31. KMI isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode until the question-and-answer session of today’s conference. [Operator Instructions] I would like to inform all parties that today’s conference is being recorded. If you have any objections, you may disconnect at this time. I would now like to turn the conference over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.

Rich Kinder: Thank you, Sheila. Before we begin, as usual, I’d like to remind you that KMI’s earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, and the Securities and Exchange Act of 1934, 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 statements and use of non-GAAP financial measures set forth at the end of our earnings release, as well as review our latest filings with the SEC, for important material assumptions, expectations, and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

As we look at our financial outlook for 2024, we are projecting very healthy growth in EBITDA, EPS, and DCF per share. While there are always headwinds and tailwinds for a company as sizable as Kinder Morgan, it appears that our strategy of expanding our assets through expansion CapEx and acquisitions, primarily in our Natural Gas segment, is delivering real benefits to the bottom-line. Kim and the management team will be taking you through our ’24 budget in great detail at the Investment Conference next week. In my remarks on these calls over the last few quarters, I’ve tried to outline the tremendous growth that we and most energy experts expect in natural gas production and demand over the coming years, driven primarily by LNG exports and exports to Mexico.

To the obvious relief of all of you on this call, I won’t be repeating the details supporting our outlook, but that growth is leading to extensive opportunities to grow our system, which already delivers about 40% of the nation’s natural gas throughput. Through selective expansion and extension of our enormous system, we can benefit from this expansion. Thankfully, most of these opportunities are concentrated along the Gulf Coast, where permitting and construction usually moves more quickly than elsewhere. Let me conclude with a bit of humor. Someone has recently said in comparing our growth to that of high-tech companies, that we were like the tortoise in Aesop’s Fable compared to the hare represented by high-tech. And that’s probably true.

But I like to think that looking at 2024, the tortoise is moving a little faster and then I would remind you of who won that race in the end. And with that, I’ll turn it over to Kim.

Kim Dang: Thanks, Rich. I’ll make a few overall points and then turn it over to Tom and David to give you the details. We ended 2023 slightly below budget, with about 1% on DCF per share and about 2% on EBITDA. There are several different moving pieces, but more than all of it can be attributed to lower commodity prices. Just before year-end, we closed the roughly $1.8 billion NextEra South Texas acquisition. This asset — these assets fit nicely into our existing Texas system serving the Gulf Coast and Mexico demand markets. We were excited to be able to get that transaction done a little more quickly than we expected. Looking forward to 2024, as Rich said, we expect really nice growth over ’23, with every business unit expected to contribute incremental earnings.

We’ve updated the preliminary budget guidance we released in early December of last year to incorporate the South Texas acquisition. As a result, our final 2024 budget now projects 15% growth in earnings per share versus 2023, and 8% growth in DCF per share. Our commodity assumptions in the final budget are unchanged versus the preliminary budget. We assumed WTI of $82 a barrel and $3.50 for Henry Hub natural gas, which was consistent with the forward curve during our annual budget process. While current prices are lower, we did not update prices in our final guidance given their potential to change over the year. However, based on our commodity sensitivities, even at current prices, we would still expect strong growth over 2023, given our relatively modest commodity exposure.

For example, at a WTI price of $72 per barrel and Henry Hub of $2.80, earnings per share would grow at 12% versus ’23, and DCF per share would grow at 6%. During the fourth quarter, we put $965 million of projects in service and added $344 million to the backlog, which currently stands at approximately $3 billion. Despite the decline versus last quarter, we’re still confident in our ability to spend at the high end of the $1 billion to $2 billion per year discretionary CapEx range for the next few years. Our confidence is supported by the roughly 20% expected growth in the natural gas market between now and 2030, driven by LNG exports, exports to Mexico, and industrial demand. We’re looking at multiple expansion projects, some of them significant in size, to supply LNG exports from the Texas Coast, the Louisiana Coast, and the West Coast, to supply Mexico through exports from both Texas and Arizona, to bring incremental supply to the Southeast markets for Permian egress, as well as expansion of the storage, and for incremental power and industrial demand.

We’re in a strong position as we exit 2023 and move into 2024. Our balance sheet is the strongest it has been in about a decade. We’re projecting nice growth for 2024. And the natural gas business, which is greater than 60% of KMI’s EBDA, is underpinned by 20% growth in that market, leading to nice expansion opportunities. We will continue to return significant capital to our investors through dividends and opportunistic share repurchase. Next week, at our annual Investor Conference, we will review in much more detail our ’24 budget, industry fundamentals, and our future opportunity set and answer all your questions. And with that, I’ll turn it over to Tom to give you details on the performance for the quarter.

Tom Martin: Thanks, Kim. Starting with the natural gas business unit, transport volumes increased by 5% or 1.9 million dekatherms per day for the quarter versus the fourth quarter of 2022, driven primarily from EPNG’s Line 2000 return to service and the Texas intrastate increased LNG feedgas demand and increased power demand. These increases were partially offset by decreased deliveries to local distribution companies. Our natural gas gathering volumes were up 27% in the quarter compared to the fourth quarter of ’22, driven by Haynesville volumes which were up 59%, Bakken volumes which were up 14%, and Eagle Ford volumes up 18%. Gathering volumes grew 14% compared to Q3 2023. For the full year, gathering volumes were up nicely at 19% over 2022 and just slightly below our 2023 plan.

We continue to see high demand for and utilization of our natural gas assets, which is driving in many instances, longer-term contracts, higher rates, and increased project opportunities in a growing US market. In our Products Pipeline segment, refined product volumes were up slightly about 1% for the quarter versus the fourth quarter of 2022, driven by an increase in jet fuel, partially offset by a slight reduction in diesel volumes. Gasoline volumes were flat for the comparable quarter of last year. We continue to see a considerable ramp in renewable diesel volumes flowing in our pipelines serving California. The pipeline volumes from the RD hub projects we placed into service earlier this year have grown from 700 a day in Q1 to 27,000 a day in Q4, and we’re currently expecting well above 30,000 a day in January.

As we stated previously, these RD hub projects are largely underpinned with take or pay contracts associated with our terminals facilities, so we get paid most of our revenue even if those volumes do not flow. However, when RD volumes actually flow on our pipelines, we collect the additional tariff on those barrels as well. Crude and condensate volumes were up 7% in the quarter versus fourth quarter of 2022, driven by higher Hiland wellhead volumes and favorable Double H transportation fundamentals from the Bakken. In our Terminals business segment, our liquids lease capacity remains high at 93%. Excluding tanks out-of-service for required inspections, approximately 97% of our capacity is leased. Utilization at our key hubs in the Houston Ship Channel and New York Harbor strengthened in the quarter versus fourth quarter of 2022.

We continue to see nice rate increases in those markets and leasing remains near all-time record levels. Our Jones Act tankers are 100% leased through 2024, assuming likely options are exercised. On the bulk side, overall volumes were up 3% from the fourth quarter of 2022, primarily from metals, pet coke, and soda ash tonnage, partially offset by decrease — decreases in grain and aggregate volumes. Grain volumes are minimum — have minimal impact on our financial results. Excluding grain, bulk volumes were up 5%. The CO2 segment experienced lower overall volumes on NGLs, CO2, and oil production, and lower prices on NGLs and CO2 versus the fourth quarter 2022. Overall, oil production decreased by 7% from the fourth quarter last year, but was above our plan for this quarter.

For the year, net oil volumes slightly exceeded our plan, largely due to better-than-expected performance from projects at Yates and SACROC, as well as strong base volumes post the February outage at SACROC. These favorable volumes relative to the 2023 plan, helped to offset some of the price weakness that we have experienced. With that, I will turn it over to David Michels.

David Michels: Thank you, Tom. So, for the fourth quarter of 2023, we’re declaring a dividend of $0.2825 per share or $1.13 per share annualized, which is 2% up from the 2022 dividend. We continued with our opportunistic share repurchase program in the fourth quarter, bringing our total year-to-date repurchases to over 31 million shares at an average price of $16.56 per share, creating a good value for our shareholders. We ended 2023 with net debt to adjusted EBITDA of 4.2 times, and that includes $522 million of repurchased shares and the $1.8 billion closing of our acquisition of the South Texas Midstream assets before year-end. Our leverage would have been 4.1 times if we had included a full year adjusted EBITDA contribution from those acquired assets.

We ended 2023 just slightly below budget for the full year. And more than all of that underperformance can be explained by lower-than-budgeted commodity prices. We saw better than budgeted performance in both our natural gas and terminals businesses. And for the quarterly performance, we generated revenues of $4 billion, which was down $541 million from the fourth quarter of 2022. Cost of sales were down a bit more than that, at a reduction of $614 million. Both of those declines were due to a decline in commodity price year-over-year. As you’ll recall, we enter offsetting purchase and sales positions in our Texas Intrastate business, which is primarily why our revenue and cost of sales are exposed to price fluctuations, but our margin is generally not impacted by price.

Interest expense was higher versus 2022 as expected, driven by short-term interest rates impacting our floating rate interest swaps. We generated net income attributable to KMI of $594 million, down 11% from the fourth quarter of 2022. Our EPS was $0.27, down $0.03 from 2022. Our average share count reduced by 27 million shares or 1% due to the repurchased shares. For our business segment performance, Terminals and Products segments were up, Natural Gas and CO2 segments were down versus the fourth quarter of 2022. The Natural Gas segment was down mostly due to mild winter weather in 2023 versus 2022. The Product Pipeline segment was up due to higher rates on existing assets as well as contributions from new expansion projects, including our renewable diesel assets.

Terminals was up due to improved rates on our Jones Act business, contractual rate escalations across multiple assets, and improved tank lease rates in the Northeast region. Our CO2 segment was down due to lower oil and CO2 volumes. Our DCF per share was $0.52, down $0.02 from last year. Excluding interest expense, we were favorable to last year. For the balance sheet, we ended the year with $31.8 billion of net debt, which was an increase from year-end of $901 million — year-end 2022 that is. So, a high-level of reconciliation for the year-to-date or the full-year 2023 change in net debt is as follows. We generated $6.5 billion of cash flow from operations. We spent $2.5 billion in dividends. We spent $2.5 billion of total CapEx. That includes our growth, sustaining, and contributions to JVs. We repurchased $500 million of stock and we spent $1.8 billion on the South Texas Midstream acquisition, which gets you close to the $901 million increase in net debt for the year.

As Kim mentioned, we updated our 2024 budget for the South Texas acquisition from the December guidance that we released. As you can see, the acquisition was quite accretive on both EPS and DCF per share. We’re very pleased with the resulting growth projected for 2024 with EPS growth of 15%, DCF per share and EBITDA growth of 8%, and a nice improvement in our leverage ratio to 3.9 times by year-end 2024. And as Rich said, we’ll be providing all the details behind those at our annual Investor Day meeting one week from today. With that, back to Kim.

Kim Dang: Okay. Sheila, we’d like now to open it up for questions. We would request that those asking questions, if you’d please limit it to one question and one follow-up. And if you have additional questions, please get back in the queue, and we will stay here until we get to everyone.

See also 30 Smallest Countries In The World By Population and Land Area and 10 Dividend Aristocrats That Slashed Their Dividends.

Q&A Session

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question will come from Jeremy Tonet with JPMorgan. Your line is open.

Jeremy Tonet: Hi. Good afternoon.

Kim Dang: Good afternoon, Jeremy.

Jeremy Tonet: Maybe just starting off here, wanted to start off with the recent weather. It’s been a cold snap that we’ve seen across a lot of the country, in Texas as well. And last time we saw a cold snap with Uri, it led to notable opportunities for the Midstream and KMI, and granted, it’s probably not the same order of magnitude here by any means, but just wondering if you could shed any color on if you are seeing kind of increased opportunities in this environment or how we should think about that in general.

Kim Dang: Sure, Jeremy. Yeah, I mean, the cold weather, you’re right, does lead to incremental opportunities for us. You’re also right that this is not the same order of magnitude as a Uri. When we do our budget, we do budget for some cold weather and I think coming into the year, we are a little bit nervous about that given the — a warmer than expected weather. With this cold front I think we have made good progress on achieving — on our way to achieving some of those cold weather budget assumptions. So, very happy with the progress to date.

Jeremy Tonet: Got it. That’s helpful there, thanks. And then, just wanted to come back to capital allocation, as maybe you talked about in the past and we’ve seen Kinder execute on repurchases this year and also some sizable M&A, and just wondering on a go-forward basis here, if you could walk us through, I guess, how those two specific opportunities could stack up in your mind? Clearly, there is still room on the Kinder balance sheet given leverage targets and where leverage sits today, and just wondering, how those two stack up? And as it relates to buybacks, is there a certain kind of cap and pace or any other thoughts that we should think about there?

Kim Dang: No. I mean, I think we like the flexibility that we have on our balance sheet. We’ve been around 4-ish times for the last three years. I think in end of ’21, we were at 3.9. Last year, we were at 4.1. And right now, we’re at 4.2. But if you adjusted for the EBITDA on the acquisition, you would be at 4.1. And so that gives us flexibility to do acquisitions. That gives us flexibility to do share repurchases. And so, last year we were able to do share repurchase, we did $522 million, as you heard David say. We made a $1.8 billion acquisition and our balance sheet ended essentially in the same place that we started the year. So, when — especially when we’re doing attractive acquisitions, it’s not that dilutive to our debt metric and so we acquired the NextEra acquisition at about 8.6 times.

And so, relative to our debt metrics, even though we are 100% debt-funded, it wasn’t that dilutive. So, I think where our balance sheet is, it gives us lots of flexibility and we were able to execute on multiple opportunistic transactions during 2023. And that’s quite frankly what we would look to do going forward as well.

Jeremy Tonet: Got it. Makes sense. See you at the Analyst Day. Thank you.

Operator: Thank you. Next, we will hear from Brian Reynolds with UBS. You may proceed.

Kim Dang: Hey, Brian.

Brian Reynolds: Hi. Good afternoon, everyone. Maybe to start off on just the quarterly performance and the ’24 guidance, kind of as it relates specifically to the Natural Gas segment. Jeremy touched on it a little bit, but we saw the year-over-year decline in Nat Gas segment driven by some winter storms in 4Q ’22, but I’d be great if you could just refresh us on maybe some of the marketing exposure in the business. Previously, we kind of view it as mostly contracted at this point, but just given the year-over-year earnings decline and maybe looking forward, just given significant amount of Nat Gas price volatility expected ahead and Kinder’s strategic positioning in natural gas storage, just kind of curious how we should think about maybe the marketing side of this business on a go-forward basis versus kind of Kinder over the last five years? Thanks.

Kim Dang: Well, let’s start on the interstate transmission side. And so, when you have a winter storm, people are going to need more balancing services, they’re going to need more storage services, you’re going to have more usage because you have more molecules flowing. And so what happens around a lot of times in these winter storms is, we are providing ancillary services to our customers that they need and they want in order to serve their customers. So — and so you see some incremental business on the interstate side in and around those services. On the intrastate side, there we actually — we do hold some storage in our own name and then our customers have storage as well. So, we make money from time to time on the small amount of storage that we do hold in our name.

We also have a little bit of transport capacity that we hold in our own name. It’s not significant overall, but we can make money on that where we haven’t already hedged it. And then some of the same types of services that the interstate customers need, the intrastate customers also need. So, they will over-pull on our system above their rights, and those services come at premium rates. And so, those are the types of things that you see when we have winter weather that leads to some incremental margins — on the margins.

Brian Reynolds: Great. Thanks. Appreciate that. Maybe as a follow-up to Permian Natural Gas egress looking forward. It seemed to be — appear to be short natural gas in the Agua Dulce market going forward with LNG demand coming online in the back half of the decade. So, kind of just curious if you could talk about potential new projects including GCX expansion, what are the updates there and/or the potential for a new-build longer-term? Thanks.

Kim Dang: Sure. I can talk about both of those, and then I’ll ask people to add. And so, yes, we think there is going to be a need for further Permian egress in the back half of the decade. I think that’s consistent with the — with what we have been saying. We think we are well-positioned for that. We’ve got — we’ve built multiple pipelines successfully. They’ve been generally very close to being on time. We also have an existing system that we can interconnect with, and so we can offer the shippers on a Permian egress pipeline storage services and other downstream services that I think some of our competitors can’t. So, I think it’s a project we are very interested in, but we will be disciplined in how we approach it and make sure that the returns are attractive to our shareholders.

I think GCX, some of the same dynamics around GCX. GCX obviously because it’s a compression and expansion of an existing system, we’ll get to market with it much quicker. We’ve continued to have conversations with shippers on that capacity. Not quite there yet. But some — yeah, I mean, if we did one, if we participated in the new-build on the GCX expansion, there also could be further downstream expansions of our existing systems. And so, that’s something that we’re also looking at as part of this.

Brian Reynolds: Great. Makes sense. I’ll leave it there. See you next week.

David Michels: Yeah. Just — I’ll follow up there, just so you get a little sense. When we think about the need for the capacity, we say back half of the decade, but what we’re hearing from our customers is probably late ’26, early ’27, so clearly we’re in a competitive environment here, so I won’t go through a lot of details, but, something probably needs to be actioned here in the next couple of quarters to be able to meet that timeline and the question is, really is it just one pipe or two, when you think about the incremental demand that’s coming on.

Brian Reynolds: Great. Makes sense. Appreciate that extra color. Have a great rest of your day.

Operator: Thank you. Our next question will come from Jean Ann Salisbury with Bernstein. Your line is open.

Jean Ann Salisbury: Hi. There is a lot of differing reports around Haynesville production trajectory and whether it’s in decline and kind of has been in decline for a couple of months. It seems like your fourth quarter was up quite a lot from your third quarter Haynesville volumes, but I was wondering if you could just talk about what you’ve been seeing on your acreage there over the last month or two, I guess towards the end of the fourth quarter?

Kim Dang: Yeah. So, if you look at our Haynesville volumes, they were I think, Tom didn’t say this, but in the 14% quarter-over quarter, Haynesville was up over 30%. So, we’ve continued to see increase in our Haynesville volumes. And so, David, will you comment?

David Michels: Yeah. I mean, so, look, we — the team has done a wonderful job with our acreage. We’re — look, our acreage is positioned in prime Tier 1 acreage. Our largest customer there is planning for the upcoming LNG wave. And so, while we have seen some of the smaller producers kind of pull back, I think everyone is getting ready for the upcoming demand that’s coming our way. And so, if you ask me, I think some of the pullback has helped us. We’ve had a little bit — we’re trying to keep up with the demand in terms of physical capacity. And so, this year, hopefully, we’ll get the rest of that capacity on and be primed and ready to support our customers when they are ready to take. It’s been a good ride. We’ve pretty much doubled our volumes over the last couple of years.

Jean Ann Salisbury: Great. That’s helpful. Thank you. And then, I have a follow-up. Do you see any risk this year that gas infrastructure out of the Bakken might limit your growth out of that basin this year?

David Michels: Well, no. I think — look, I think we’ve got — I think we talked about the last quarter. We had our — we have two projects that we’re looking at bringing incremental gas out of the Bakken, one which was, we just put into service this past November. We call it our Bakken Express. We had a Phase 1 and Phase 2. That first wave is already in service and flowing full, 92,000 a day coming into the Cheyenne hub out of the Bakken. So, we don’t think gas will be the limiting factor anymore, especially once we get the second phase out. I think we’re in pretty good shape there.

Jean Ann Salisbury: Great. That’s all for me. Thank you.

Operator: Thank you. Our next question will come from John Mackay with Goldman Sachs. Your line is open.

John Mackay: Hey all. Thanks for the time. I’m going to start on a pretty simplistic one. You might have a straightforward answer. But just in terms of the 2024 guidance increase going from $8.0 billion to $8.16 billion, is that all on STX? Is there any other change in there that you can frame up? And maybe just how do we think about that increase versus kind of what you were guiding for the EBITDA on those assets this year?

Kim Dang: The $8.0 billion when we published, that was slightly below $8.0 billion, but it rounded up to $8.0 billion and so — and then the $8.16 billion, the only difference between those two numbers is the EBITDA on NextEra. And the EBITDA on NextEra for 2024 is consistent with what we were expecting.

John Mackay: That’s — that is clear, and thanks for that. And then maybe just shifting gears, talk about RNG contributions in the quarter a little bit, kind of where that ended up trending for the year, how much of the kind of ’23 softness versus budget was driven by that and how much could it bounce back in ’24?

Kim Dang: Yeah. I mean, I would say the contribution from the RNG plants in the fourth quarter was relatively small. And we do have three plants in service now. They are not running as consistently as we would like them to run. And so, I think that’s what we’re focused on now. We recently took over operations from Waste Management and we think that once we really get our arms around this, we will be able to run these — get these to run very consistently. That may take a couple of months into 2024, but we think we’ll get them running consistently.

John Mackay: All right. Appreciate that. Thank you. See you next week.

Operator: Next, we will hear from Tristan Richardson with Scotiabank. You may proceed.

Tristan Richardson: Hey, good evening, guys. Just maybe a question on the STX. Could you just talk a little bit about what’s driving the growth in ’24 versus ’23? And then, with respect to integration of those assets, are there obvious sort of near-term low-hanging fruit type of projects as part of the integration that could drive further or even sort of similar type of growth in ’25 and beyond?

Kim Dang: Sure. So, between ’23 and ’24, there is an expansion project, contracted expansion project that came online, it came online late last — late — very late last year. And so, that incremental EBITDA between ’23 and ’24 is locked-in with customer contracts. With respect to ’24 and ’25, we don’t see anything as significant as that driving the growth. We talked about longer-term multiple being between 7 times and 7.5 times, coming down from the 8.6 times that we bought it. And that was driven a lot by — a small amount by cost-savings, but really by some commercial synergies and some incremental business that we think we can bring to those pipes, but that really occur three to four years out.

Tristan Richardson: Appreciate the color, Kim. And then maybe just following on a previous question around leverage. I mean, can you talk a little bit about where you sort of see the high end of where you’re comfortable should something sizable, whether it be M&A or organic, come across? Where you see yourself sort of the high-end in terms of comfortable on leverage?

Kim Dang: Yeah. So, our leverage targets are 4.5 times and there’s no change in that. And so, I think we feel like that’s appropriate given the size, scope of our assets, the stability of our contracts that are underpinned by take or pay contracts with good customer credit quality. We run, as I said earlier, around 4 times at the end of the last three years. And we see value in having some cushion for opportunities and/or risk if they should arise. And so that gives us plenty of capacity to execute on some opportunity if we found it attractive. Now this isn’t burning a hole in our pocket. We don’t have to go out and spend this money today. I mean, you’ve seen us, as I talked earlier, acquire those NextEra assets. Not much impact to our debt to EBITDA multiple.

We purchased 500 million in shares, not much impact. And so we’ve been able to do a lot of these things without huge impacts, but we’ve got a lot of capacity there if we find something that is a good strategic set, and that has attractive economics for our shareholders.

Tristan Richardson: That’s helpful. Appreciate it, Kim. Thank you.

Operator: Our next question will come from Neal Dingmann with Truist. Your line is open.

Unidentified Analyst: Hi, guys. Thanks for the time here. This is [JP Vachon] (ph) for Neal. I had one clarification question just kind of, what we were talking about earlier. The Permian nat gas egress that you guys were referring to, the 2026, I guess late ‘26, ‘27, what you’ve been hearing from customers, has that changed at all, I guess, maybe from last quarter or two quarters ago? Has the tone changed from customers there or has that kind of been the expectation for some time there?

David Michels: Yeah. I don’t think it’s changed much. I think it’s been the expectation. I think as the market — both the market side is coming together from the LNG standpoint and the producing side, I think it’s probably a perfect match in terms of timing. But I do sense that there is more of a need to ensure that there’s a solution in place, probably a little more urgent than maybe we had on the last couple of calls.

Unidentified Analyst: Sure. Sure. Got it. Thank you. And then just one follow-up for me. The RD projects that you guys have anchored here, just going through the release, you guys note that you have potential capacity to expand in subsequent phases, I guess, in California. Do you mind elaborating on that? I guess, to the extent that you guys can, I guess, what would timing look like there? And I guess, what level of capacity could we expect to see ramping in that time frame?

Dax Sanders: Yeah. This is Dax. Good question. I would just reiterate kind of what we’ve got now. Between the two hubs, we’ve got about 60,000 barrels a day just under capacity. And then in Los Angeles harbor, our Carson Terminal, we’ve got 750,000 barrels of storage that will be fully in by the end of the year, 20,000 barrels a day of rack throughput. In Los Angeles Harbor, I think we could easily double that, double both the storage as well as the throughput — rack throughput capacity. On the hubs, we can double those as well. If we did, off of 60,000, that would get us up to a rate — throughput rate that would be somewhat consistent with what we’ve historically supplied in the State of California, call it, roughly around 120,000.

Now California uses about 250,000 barrels a day of diesel. And so theoretically, I think we could convert even above that because I think we’ll see — we’ve got our first facility now, Bradshaw, which is just outside of Sacramento which we’ve converted 100% to renewable diesel, no hydrocarbon diesel going through there. So — but whether we do that, it will all be determined by the market. I mean we’ll be continuously engaged with our customers and watching the ramp-up of these two Northern California refineries, and we’ll do whatever our customers ask us to.

Unidentified Analyst: Perfect. Thank you very much guys. Appreciate it.

Operator: Our next question comes from Neel Mitra with Bank of America. Your line is open.

Neel Mitra: Hi. Good afternoon. I was wondering what volume assumptions you’re using on the gas side for the STX acquisition in the Eagle Ford? And maybe just the dynamics that you’re seeing there with GOR ratios and activity?

Kim Dang: Yeah. Hey, Neal, on — with respect to the 2024 budget assumptions, we’re going to go through all of those at the conference next week. So, if you can hold your question and we’ll make sure we address it next week at the Investor Conference when we go through the ’24 budget in detail.

Neel Mitra: Okay, fair enough. And then maybe asking the same question a different way. All else equal, if you don’t make an acquisition, you’re trending towards I guess 3.8 times leverage in ’24. Do you see value in lowering the leverage ratio and staying under 4 times? Or do you still see kind of 4.5 times is the proper leverage ratio given your asset base?

Kim Dang: Yeah. I think we’re comfortable at 4.5 times, as I said earlier, given the size, scope — size and scope of our assets and stability of our cash flow. And so, that being said, we see value in having some cushion and we’ve been operating with a cushion for the last couple of years.

Neel Mitra: Okay. Can I ask one additional one since the first one is going to go to the Analyst Day?

Kim Dang: Sure. Yes.

Neel Mitra: When you said that GCX can support the downstream assets maybe with an expansion, can you explain what you meant by that comment?

Sital Mody: This is Sital. I think what Kim was talking about is what — one, we have the ability to expand GCX. I think as the intrastate industrial market and power market evolve, there is an opportunity to probably do some downstream expansions to carry those volumes into that corridor. I think that’s what Kim was referring to.

Rich Kinder: And I think just to add something, this just demonstrates the tremendous ability we have to expand and extend our system. I think it’s hard for people to realize exactly how extensive this is in Texas, Louisiana, but every time we put more gas into the system, it brings the opportunity to expand further downstream and that’s a big reason why Kim has said repeatedly that, on our expansion CapEx target, we think we’ll be at the upper-end of that range from $1 billion to $2 billion, we’ll be at the upper-end of that range. And that’s the kind of opportunities we’re seeing. They don’t necessarily make it into a backlog, but they’re out there and things we can take advantage of as more and more gas flows through the system.

Neel Mitra: Got it. I appreciate all the color.

Operator: Thank you. Next, we will hear from Theresa Chen with Barclays. You may proceed.

Theresa Chen: Good afternoon. Thank you for taking my questions. First, just a quick follow-up related to the longer-term guidance on the STX acquisition. In order to get to the 7 times and 7.5 times multiple over multiple years, is there any CapEx associated with that, and how much?

Kim Dang: There may be a little bit, but it is not — it’s not material.

Theresa Chen: Got it. And on the product side in California, given the ample supply of diesel into the state, with renewable diesel being produced in state, as well as entering into the state from other areas, it looks like the state may be short on gasoline over time as in-state refineries convert. With this backdrop, if there is incremental bid for gasoline imports, are there opportunities for your waterborne terminals there?

Tom Martin: Yeah. I think, at the end of the day, whether the barrels are supplied by the [PAD 5] (ph) refiners are imported, I think they’ll move on our pipelines. I think as long as the demand is there, the inland demand is there, and as well as the demand in the Bay areas and the LA areas that move across our racks, whether it’s produced in California or it comes in, I think it will find its way into our assets.

Theresa Chen: Thank you.

Operator: Our next question comes from Zack Van Everen with TPH & Company. Your line is open.

Zack Van Everen: Hey. Thanks, guys, for taking my question. Just following back up on the Permian pipeline, is there a market that you guys are looking more towards, whether it’s Agua Dulce, or Carthage, or Houston, that would make more sense at the time for a new pipe?

David Michels: So, look, we like them all. But, as I said, it’s in a very competitive environment that we’re in. I think ultimately, there is a need in probably both locations, right? And so, really that’s all I’ll say. And we’re trying — like I said, we like them all. I’m not sure we’re going to get them all. So, not sure if I answered your question. But, I think there is a pipe — there is probably a pipe that needs to get to the Eastern Louisiana Coast, ultimately across to kind of the Louisiana Gulf Coast corridor and there is probably a pipe that needs to get to South Texas.

Kim Dang: And ultimately the customer — the customers and the customer contracts will drive that.

David Michels: That’s right.

Zack Van Everen: Okay. That makes sense. And then, turning to M&A, I know you all don’t rule it out. And one of your peers this year will have some assets on the market. Curious if you guys would ever step out of the US for assets or mostly focused on just US assets for M&A?

Kim Dang: Sure. I mean, we will look at the opportunity, that’s what I would say. I would say, in general, what we have found outside of the US is that it’s hard to get the types of risk-adjusted returns that we would like to get. And so, because you’ve got different tax issues associated with repatriating the cash and generally returns, depending on which market you’re talking about, but returns have been lower in most of those international markets. So, I think, what I’m saying is, I doubt that happens, but we will look at those opportunities. We don’t pass up looking at things and evaluating whether that could make sense and whether that has — if there are synergies with our existing assets. So, I’ll just leave it at that.

Zack Van Everen: Alright. Perfect. That’s all I had. Thanks, guys.

Operator: Thank you. Our next question comes from Harry Mateer with Barclays. Your line is open.

Harry Mateer: Hi, good afternoon. First one, for the past couple of quarters you’ve been disclosing your 10-Q, some potential financial effects on the EPA’s Good Neighbor Act, with the high-end of the range fairly material. I was wondering if you can update us on where you stand in that process and things we can keep an eye out for in terms of whether the ultimate effect winds up being towards the higher or lower end of the range?

Kim Dang: And I’ll repeat some of the stuff that we’ve said in the past. But I mean, we think this is a flawed rule and it was a flawed process. It’s heavily challenged and it’s legitimately challenged. Every state that has requested a stay on their state plans has prevailed. So, this has stayed in the fourth, fifth, sixth, eighth, and ninth Circuit Courts. And with respect to the Federal plans, that has been appealed to the Supreme Court and what we think is a very positive sign, the Supreme Court has requested a hearing that will happen later in February. So, where that leaves us is, there are only three states right now where KMI — where the rule is not stayed and KMI is impacted. And so, that the impacts that we disclosed in the 10-K are much smaller and I think we discussed that in there as well. The potential impacts, I should say.

Harry Mateer: Got it. All right. Thank you.

Operator: Thank you. We are showing no further questions at this time.

Kim Dang: Thank you, Sheila.

Rich Kinder: Thank you. Appreciate it. Have a good day.

Operator: That does conclude today’s conference. Thank you for participating. You may disconnect at this time.