Kinder Morgan (KMI) Q4 2023 Earnings Call Transcript

adminJanuary 18, 2024

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Kinder Morgan (KMI -1.46%)
Q4 2023 Earnings Call
Jan 17, 2024, 4:30 p.m. ET

Prepared Remarks:

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 — Executive Chairman

Thank you, Sheila. Before we begin, as usual, I’d like to remind you that KMI’s earnings release today and this call includes 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 investor 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.

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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 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. Now, 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 — President

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, is 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 market. 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 assume 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 — relatively modest commodity closure. 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 Texas — 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 expansions of 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 — President, CO2 and Energy Transition Ventures

Thanks, Kim. Starting with the natural gas business unit, transport volumes increased by 5%, or 1.9 million decatherms 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 feed gas 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 are 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 U.S. 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 last year. We continue to see a considerable ramp in renewable diesel volumes slowing in our pipeline 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 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 east and Ship Channel in New York Harbor strengthened in the quarter versus fourth quarter 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, petcoke, and soda ash tonnage, partially offset by decrease — decreases in grain and aggregate volumes. Grain volumes are minimal — have minimal impact on our financial results.

Excluding grain, bulk volumes were up 5%. The CO2 segment experienced lower overall volumes on NGL, 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 volume 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 outages at SACROC.

These favorable volumes relative to the 2023 plan helped offset some of the price weaknesses that we have experienced. With that, I’ll turn it over to David Michels.

David Michels — Chief Financial Officer

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 — 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. Now, 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 counts reduced by 27 million shares, or 1%, due to the repurchased shares. For a 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 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 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 — 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 the 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 — President

OK, 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.

Questions & Answers:

Operator

Thank you. We will now begin the question-and-answer session. (Operator instructions) Our first question will come from Jeremy Tonet with J.P. Morgan.

Your line is open.

Jeremy Tonet — JPMorgan Chase and Company — Analyst

Hi, good afternoon.

Kim Dang — President

Good afternoon, Jeremy.

Jeremy Tonet — JPMorgan Chase and Company — Analyst

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 — for the midstream and KMI. And, well, 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 — President

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 — as — a Uri. You know, when we do our budget, we do budget for — for some cold weather.

And I think, you know, coming into the year, we were a little bit nervous about that given the — the – the — a warmer-than-expected weather. With this cold front, I think we have made good progress on — on achieving on — on our way to achieving some of those cold weather budget assumptions. So, I’m very happy with the progress today.

Jeremy Tonet — JPMorgan Chase and Company — Analyst

Got it. That’s helpful there. Thanks. And then, just wanted to come back to capital allocation as maybe we 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’s still room on the kind of 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 — President

No, I mean I think we — we like the flexibility that we’ve — that we have on our balance sheet. You know, we’ve been around four a time. At — for the last three years, I think in the ’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’d be — you’d be at 4.1. And so, that gives us flexibility to do acquisitions. That gives us flexibility to do share repurchases. And so, you know, 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, you know, essentially in the same place that we started the year. So, you know, when — especially when we’re doing attractive acquisitions, you know, it’s not that dilutive to our debt metric. And so, you know, we — we acquired the next acquisition at about 8.6 times. And so, you know, relative to our debt metric, even though we are 100% debt funded, it wasn’t that dilutive.

So, I think where our balance sheet is gives us lots of flexibility, and we were able to execute on multiple opportunistic transactions during — during 2023. And that’s, quite frankly, what we would look to do going forward as well.

Jeremy Tonet — JPMorgan Chase and Company — Analyst

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 — President

Hey, Brian.

Brian Reynolds — UBS — Analyst

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, you know, Jeremy touched on it a little bit, but we saw the year-over-year decline in that gas segment, you know, driven by some winter storms in 4Q ’22. But it’d be great if you could just refresh us on — on maybe some of the marketing exposure in the business. You know, previously, we kind of view it as — as mostly contracted at this point, but just given the year-over-year earnings decline and maybe looking forward, just given, you know, a significant amount of net gas price volatility expected ahead and Kinder’s strategic positioning in natural gas storage, just kind of curious of how we should think about maybe the marketing side of this business on a go-forward basis versus kind of over the last five years. Thanks.

Kim Dang — President

Well, let’s start on the — the interstate transmission side. And so, you know, when you have a winter storm, you know, people are going to need more balancing services, they’re going to need more storage services, you’re going to have more usage, but you — because you have more molecules flowing. And so, what happens around a lot of times these winter storms is we’re 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 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 own 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 — that the interstate customers need, the intrastate customers also need. So, you know, they will over-pull on our system above their rights, and those — 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 margin on the margin.

Brian Reynolds — UBS — Analyst

Great, thanks. Appreciate that. Maybe as a follow-up to — to pivot to the Permian natural gas egress, looking forward, you know, seem 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, you know, potential new projects including GCX expansion, what are the updates there, and/or the potential for a new build longer term.

Thanks.

Kim Dang — President

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.

You know, we’ve got — we’ve built multiple pipelines successfully. They’ve been generally very close to — 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, you know, storage services and other downstream services that I think some of our competitors can’t. So, I think it’s — it’s a project we’re very interested in, but we will be disciplined in — in how we approach it and make sure that the returns are attractive to our shareholders. You know, I think GCX — you know, some of the same dynamics around GCX.

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

Brian Reynolds — UBS — Analyst

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

Kim Dang — President

(Inaudible) follow-up.

Tom Martin — President, CO2 and Energy Transition Ventures

Yeah, Brian, just I’ll follow-up there just so you get a little sense. You know, when we think about the need for the capacity, you know, we say back half of the decade, but what we’re hearing from our customers is probably late ’26, early ’27. So, you know, clearly, we’re in a competitive environment here. So, I won’t go through a lot of details, but you know, 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 — UBS — Analyst

Great. Makes sense. I 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 Salisbury — AllianceBernstein — Analyst

Hi. There’s 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 the last month or two, I guess, toward the end of the fourth quarter.

Kim Dang — President

Yeah, so if you look at our Haynesville volumes, they were, I think, and 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 — in our Haynesville volumes. And so, over to you, Tom.

Tom Martin — President, CO2 and Energy Transition Ventures

Yeah, I mean, so look, the team’s done a wonderful job with our acreage. You know, we’re — we’re — our acreage is positioned in prime tier 1 acreage. You know, our largest customer there is planning for the upcoming LNG wave. And so, you know, 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, you know, if you ask me, I think some of the pullback has helped us.

We’ve had a little bit — you know, 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’re ready to take. So, it’s been a — it’s a pretty good ride. We’ve — we’ve pretty much doubled our volumes over the last couple of years.

Jean Salisbury — AllianceBernstein — Analyst

Great. That’s helpful. Thank you. And then, as a follow-up, do you see any risks this year that gas infrastructure out of the Bakken might limit your growth out of that basin this year?

Tom Martin — President, CO2 and Energy Transition Ventures

Well, no. I think — look, I think we’ve got — you know, I think we talked about this at the last quarter, we had our — you know, 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. And we had a phase 1 and a 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 Salisbury — AllianceBernstein — Analyst

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 — Goldman Sachs — Analyst

Hey, all. Thanks for the time. I’m — I’m going to start on a pretty simplistic one. I might have a straightforward answer, but just in terms of the 2024 guidance increase going from 8.0 to 8.16, is that — 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 — President

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

John Mackay — Goldman Sachs — Analyst

OK, that’s — that is clear then. 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 bounce back in ’24.

Kim Dang — President

Yeah, I mean I would say that the contribution from the RNG plants in the fourth quarter was relatively small. And, you know, we do have three plants in service now. They’re not running as consistently as we would like them to run. And so, I think — I think that’s what we’re focused on now. We recently took over operations from waste management, and we think that, you know, once we really get our arms around this, we will be able to — to run these — get these to run very consistently.

You know, that may take a couple of months into 2024, but we think we’ll get them running consistently.

John Mackay — Goldman Sachs — Analyst

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 — Scotiabank — Analyst

Hey, good evening, guys. Just maybe a question on the STX. Can you 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 — President

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 — that incremental EBITDA between ’23 and ’24 is locked in with — with customer contracts.

You know, with respect to ’24 and ’25, you know, we don’t see anything as significant as that driving the growth. You know, we talked about longer-term multiple being between 7 and 7.5 coming down from the 8.6 times that we bought it. And that was driven a lot by — a small amount by some cost savings but really by some commercial synergies and some incremental business that — that we think we can bring to those pipes. But that really occurred three to four years out.

Tristan Richardson — Scotiabank — Analyst

Appreciate the color, Kim. And then, maybe just following on a previous question around leverage, I mean, could 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, you know, come across where you see yourself sort of the high end in terms of comfortable and leverage?

Kim Dang — President

Yeah. So, you know, our leverage targets are 4.5 times, and there’s no change in that. And so, you know, I think we feel like that’s appropriate, you know, 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. So, we’ve run, as I said earlier, around four times at the end of the last three years, and we see value in having some cushion for, you know — for opportunities and/or risks if they — if they should arise. And so, that gives us plenty of capacity to execute on some opportunity if we found it attractive. Now, this is burning a hole in our pocket.

You know, 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’ve purchased 500 million 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 fit, you know, and that’s — that has attractive economics for our shareholders.

Tristan Richardson — Scotiabank — Analyst

That’s helpful. Appreciate it, Kim. Thank you.

Operator

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

Unknown speaker

Hi, guys. Thanks for the time here. This is JP Basham for Neal. I had one clarification question, just kind of, you know, what we were talking about earlier.

The — the — the Permian nat gas egress that we’re — that you guys were referring to, the 2026 — I guess late ’26, ’27, you know, what you’ve been hearing from customers, has that — has that changed at all? I guess, you know, maybe some last quarter or two quarters ago, has the tone changed from customers, though, or is that, you know, kind of been the expectation for some time there?

Tom Martin — President, CO2 and Energy Transition Ventures

Yeah, I don’t think it’s changed much. I think it’s been the expectation. I think, you know, as the market — you know, 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 — I do sense that there is more of a need to — to ensure that there’s a solution in place, probably a little more urgent than maybe we had on the last couple of calls.

Unknown speaker

Sure, sure, got it. Thank you. And then, yeah, just one follow-up for me. The — you know, the RD, you know, projects that you guys have anchored here, I was just — you know, just going through the release, you know, and 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 — what would timing look like there? And I guess, you know, what level of capacity, you know, could we expect to see ramping in that time frame?

Dax Sanders — Executive Vice President, Chief Strategy Officer

Yeah, this is Dax. You know, good question. I would just — just to 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’ll be fully in by — 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 the storage, as well as the through — the rack throughput capacity. On the hubs, we can double those as well. If we did off the 60,000, that would get us up to a rate — a throughput rate that would be somewhat consistent with what we’ve historically supplied in the state of California, you know, call it roughly around 120,000 now.

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

Unknown speaker

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 — Bank of America Merrill Lynch — Analyst

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 — President

Yeah, hey, Neel, 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 — in detail.

Neel Mitra — Bank of America Merrill Lynch — Analyst

OK, 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 toward, I guess, 3.8 times leverage in ’24. Do you see value in lowering the leverage ratio and staying under four times, or do you — do you still see kind of 4.5 times is the proper leverage ratio given your asset base?

Kim Dang — President

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

Neel Mitra — Bank of America Merrill Lynch — Analyst

OK, can I ask one additional one since the first one is going to go to the Analyst Day?

Kim Dang — President

Yeah.

Neel Mitra — Bank of America Merrill Lynch — Analyst

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

Sital Mody — President, Natural Gas

This is Sital. I think what Kim was talking about is what — you know, one, we have the ability to expand GCX. I think, you know, as — as the intrastate industrial market and power market evolve, there’s 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 — Executive Chairman

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 and 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 — Bank of America Merrill Lynch — Analyst

Got it. I appreciate all the color.

Operator

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

Theresa Chen — Barclays — Analyst

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 and 7.5 times multiple over multiple years, is there any capex associated with that, and how much?

Kim Dang — President

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

Theresa Chen — Barclays — Analyst

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, you know, the state may be short in gasoline over time as in-state refineries convert. With this backdrop, is there an incremental bid for gasoline imports? Are there opportunities for your waterborne terminals there?

Tom Martin — President, CO2 and Energy Transition Ventures

Yeah, I think, you know, at the end of the day, whether the barrels are supplied by the PADD 5 refiners or imported, I think they’ll move on our pipelines. You know, 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, you know, whether it’s produced in California or it comes — comes in, I think it’ll — I think it’ll find its way into our assets.

Theresa Chen — Barclays — Analyst

Thank you.

Operator

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

Zack Van Everen — Tudor, Pickering, Holt and Company — Analyst

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 toward, whether it’s Agua Dulce, or Carthage, or Houston, that would make more sense at the time for a new pipe?

Tom Martin — President, CO2 and Energy Transition Ventures

So, look, we — we like them all. But, you know, as I said, we’re in a very competitive environment that we’re in. I think, you know, ultimately, there’s a need and — and probably both locations, right? And so, really, that’s all I say. And we’re trying — like I said, we’d like them all, I’m not sure we’re going to get them all. So, I’m not sure if I answered your question, but I think there’s a — there’s probably a pipe that needs to get to the eastern Louisiana coast, you know, ultimately across to serve kind of the — the Louisiana Gulf Coast corridor.

And there’s probably a pipe that needs to get to South Texas.

Kim Dang — President

And ultimately, the customers and the customer contracts will drive that.

Tom Martin — President, CO2 and Energy Transition Ventures

That’s right.

Zack Van Everen — Tudor, Pickering, Holt and Company — Analyst

OK, that makes sense. And then, turning to, you know, 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 U.S.

for assets or mostly focused on just U.S. assets for M&A.

Kim Dang — President

Sure, I mean we will look at the opportunity, that’s what I was saying. I would say, in general, what we have found outside of the U.S., is that it’s hard to get the types of risk-adjusted returns that we would like to get. And so, you know, because you’ve got different tax issues associated with repatriating the cash, and you know, 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 — we don’t pass up, you know, looking at things and evaluating whether that could make sense and whether that has — there are synergies with our existing assets. So, you know, I’ll just leave it at that.

Zack Van Everen — Tudor, Pickering, Holt and Company — Analyst

All right, 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 — Barclays — Analyst

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

Kim Dang — President

Yeah, and I’ll — 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. You know, it’s heavily challenged and is legitimately challenged. Every state that has requested a stay on their state plans has prevailed, so this has stayed in the 4th, 5th, 6th, 8th, and 9th Circuit courts. And with respect to the — the federal plan, that has been appealed to the Supreme Court.

And — and what we think is a very positive sign, the Supreme Court has requested a hearing that will happen later in February. So, you know, where that leaves us is, you know, there are only three states right now, where KMI — where the rule is not stayed and KMI is — is impacted. And so, that — the impacts that we disclose in the 10-K are much smaller, and I think we — we discussed that in there as well, the potential impacts I should say.

Harry Mateer — Barclays — Analyst

Got it. All right. Thank you.

Operator

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

Kim Dang — President

OK. Thank you, Sheila.

Rich Kinder — Executive Chairman

Thank you. Appreciate it. Have a good day.

Operator

(Operator signoff)

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