Enterprise Products Partners L.P. (NYSE:EPD) Q3 2024 Earnings Call Transcript

Enterprise Products Partners L.P. (NYSE:EPD) Q3 2024 Earnings Call Transcript October 29, 2024

Enterprise Products Partners L.P. misses on earnings expectations. Reported EPS is $0.65 EPS, expectations were $0.665.

Operator: Thank you for standing by and welcome to Enterprise Products Partners L.P.’s Third Quarter 2024 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] I would now like to hand the call over to Libby Strait, Senior Director of Investor Relations. Please go ahead.

Libby Strait: Good morning and welcome to the Enterprise Product Partners’ conference call to discuss third quarter 2024 earnings. Our speakers today will be Co-Chief Executive Officers of Enterprise’s General Partner, Jim Teague; and Randy Fowler. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I will turn it over to Jim.

Jim Teague: Thank you, Libby. We reported adjusted EBITDA of $2.4 billion for the third quarter compared to $2.3 billion for last year third quarter. We generated $2 billion of distributable cash flow, providing 1.7x coverage. In addition, we retained $808 million of DCP — DCF. Our retained DCF totals $2.3 billion year-to-date. Operationally, we set 5 volumetric records, including 7.5 billion cubic feet per day of inlet natural gas processing volumes and 12.8 million barrels a day of crude oil equivalent pipeline volumes. We’ve benefited from contributions from the 3 new natural gas processing plants and wide natural gas price spreads between Waha and other market hubs. We’re on track to complete construction of two additional processing plants in the Permian, our Bahia pipeline, frac 14, Phase 1 of our Neches River NGL export terminal, and the last phase of our Morgan’s Point Terminal Flex Expansion in 2025.

And we’ll have one additional process plant coming online into Delaware in 2026. These projects provide visibility to new sources of cash flow for our company and enhance and expand the NGL value chain at the core of our business. We also announced yesterday that we completed the acquisition of Piñon Midstream. These assets are highly complementary to our Permian processing footprint by providing treating services to a prolific area of the basin that generally has been infrastructure limited to the lack of sour natural gas treating and acid gas injection capacity. The Piñon assets are also a very strategic addition to our NGL value chain that touches everything from the wellhead to the water. I’d be remiss if we didn’t recognize the tireless efforts of over 200 of our employees at Mont Belvieu who rolled from our most comprehensive turnaround for the PDH 1 plant right into a turnaround for our PDH 2 plant.

Our employees completed these 24/7 turnarounds with extreme diligence and without any lost time accidents. We believe this time and investment will result in higher utilization rates and performance for both of these facilities going forward, and we look forward to their contributions in 2025. We’re excited about the number of inbounds that we’re getting related to new natural gas demand in Texas from both datacenters and new gas-fired power plants that would be built under the Texas Energy Fund. There are a lot of people talking about exposure to datacenters. It seems that it’s a very sexy thing to say, and everybody who has a piece of pipe in Texas is talking it up. The reality is there’s a very small list of companies with pipeline and storage assets best positioned to benefit from this build-out, and the Enterprise is one of them.

It is difficult to quantify the ultimate demand and timing at this point, not knowing which projects will go forward. That being said, it is one of the most promising signals we’ve seen in natural gas in a long time, and we’re looking forward to serving this new influx of demand. In Enterprise, we take pride in the fact that our organization is not siloed. Everyone is important. We all pull in the same direction every day. The dedication, commitment and creativity of all our employees has always been the key to our success. We always strive to get better. We operate an integrated value chain, providing a wide range of services from the wellhead to the water. Our systems are highly automated and provide us with billions of data points. Each link in that chain presents an opportunity to provide a service, earn a fee, or enhance profitability by enhancing our margins or reducing our costs.

Over the last 5 years, we have developed a very talented big data and data science team that works closely with all areas of our company. We’re now using big data for everything from predictive maintenance, to market analytics, to asset optimization. One of the many examples is our pipeline controllers now use real-time profit optimizer programs to help determine when and how they run compressors and pumps based on real-time power and fuel cost. Data and the insights it can provide in many respects is the new currency. And our proprietary data will forever be an opportunity for Enterprise. As we sit in the final quarter of ’24 and head into ’25, our work is not done. Each year presents new opportunities and new headwinds. We built a network of assets and a culture that delivers strong results throughout business cycles, administrations and market conditions.

Our company is built for the long run. As always, we have never been more excited for what the future will bring for our company. With that, Randy.

Randy Fowler: Thank you, Jim, and good morning. Starting with income statement items, net income attributable to common unit holders was $1.4 billion or $0.65 per unit for the third quarter of 2024. This is an 8% increase over the third quarter of 2023. Our adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital, increased 4% to $2.1 billion for the third quarter of 2024 compared to $2 billion for the third quarter of last year. We declared a distribution of $0.525 per common unit for the third quarter of 2024, which is a 5% increase over the distribution declared for the third quarter of last year. This distribution will be paid November 14th to common unitholders of record as the close of the business on October 31st.

In the third quarter, the partnership purchased approximately 2.6 million common units off the open market for $76 million. Total repurchases for the trailing 12 months were $252 million, or approximately 9.1 million Enterprise common units, bringing total purchases under our buyback program to approximately 1.1 billion. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 6.5 million common units on the open market for $181 million during the last 12 months, and this includes 1.6 million common units on the open market for $47 million during the third quarter of 2024. Of note, 48% of our employees participate in the unit purchase plan. At Enterprise, we really do eat our own cooking.

For the 12 months ending September 30, 2024, Enterprise paid out approximately $4.5 billion in distributions to limited partners. Combined with the $252 million of common unit repurchases over the same period, our total capital return was $4.8 billion, resulting in a payout ratio of adjusted cash flow from operations of 56%. We returned roughly $1 billion more than our growth capital expenditures were for the same period. Total capital investments in the third quarter of 2024 were $1.2 billion, which included $1.1 billion for growth capital projects and $129 million of sustaining capital expenditures. Our expected range of growth capital expenditures for 2024 remains unchanged at $3.5 billion to $3.75 billion. We have received overwhelming interest from our producer customers following our recent acquisition of Piñon Midstream.

As Jim noted, these assets not only enhance our processing footprint, but allow us to attract more acreage in the Delaware Basin. Additionally, yesterday we announced a contract with Oxy to potentially build a CO2 pipeline that would serve the Houston Industrial Corridor. We are updating our 2025 estimated growth capital expenditure range to $3.5 billion to $4 billion to encompass potential growth opportunities in connection with these announcements. Sustaining capital expenditures are expected to be approximately $640 million in 2024, which is higher than our original estimates, primarily due to costs associated with the turnaround of the two PDH facilities. As of September 30, 2024, our total debt principal outstanding was approximately $32.2 billion.

Assuming the final maturity of our hybrids, the weighted average life of our portfolio was approximately 19 years. Our weighted average cost of debt is 4.7%, and approximately 98% of our debt was fixed rate. Our consolidated liquidity was approximately $5.6 billion at the end of the quarter. This includes availability under our credit facilities and unrestricted cash on hand. Our adjusted EBITDA was $2.4 billion for the third quarter and $9.8 billion for the 12 months ended September 30, 2024. As of that date, our consolidated leverage ratio is 3.0x on a net basis when adjusted for the partial equity treatment of our hybrids and reduced by the partnership’s unrestricted cash on hand. Our leverage target remains — our range remains 2.75 to 3.25, and at 3.0x, we’re in the middle of that range.

Libby with that, we can open it up for questions.

Libby Strait: Thank you, Randy. Operator, we are ready to open the call for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Theresa Chen of Barclays. Your question, please, Theresa.

Theresa Chen: Good morning. I wanted to follow-up on Jim’s comments about the datacenter and power demand theme. Just how do you see enterprise participating in this? And if you have any color details on commercial discussion to date.

Natalie Gayden: Hi, Teresa, this is Natalie. As Jim said, we’ve been unindated [ph] with datacenter demand infrastructure players that have likely exceeded the Bcf a day of demand in the next several years. [Indiscernible] tell you a couple of different, for a couple of different reasons, some of them have shared with us that no longer bringing power to datacenters, rather datacenters going to power sources. And as you know, we’ve got several pipelines in the Dallas, Fort Worth area and San Antonio. And just a couple of facts that I think you are interested in, if you think about it, Dallas area datacenters ranked fourth in power today, but they’re second in the most planned power [ph]. And then San Antonio is even more impressive. It’s 17th in power, but ninth in most planned power. So if you think about it that way, there’s some regions that are probably losing market share to San Antonio and Dallas, and we stand in a good spot to be able to serve those centers.

Theresa Chen: Thank you. And then related to the recent Piñon acquisition, can you provide some details on how you plan to integrate it across your NGL assets and the ability you have to roll out treating services beyond the immediate to midstream acreage and just the long-term value creation you see from these assets, please?

Jim Teague: Natalie, you’re still up.

Natalie Gayden: Yes. I think you can think of it this way. We won’t treat Piñon any differently than our integrated GMP assets. There won’t be many treating deals behind Piñon that don’t come with processing deals to serve the integrated value chain.

Jim Teague: So it leads to more organic growth through processing.

Natalie Gayden: Yes.

Theresa Chen: Thank you.

Operator: Thank you. Our next question comes from the line of Jean Ann Salisbury of BofA. Your question, please, Jean.

Jean Ann Salisbury: Hi, good morning. Ethane storage is full. There’s no new demand until you and ET’s export facilities come online next year. Can you kind of talk about how you see this resolving? Do you see a big step down in ethane recovery? Would that change your growth rate the next few quarters, and is there kind of a positive offset to that for Enterprise in your portfolio?

Tug Hanley: Hi, Jean. This is Tug Hanley. Yes, as far as recoveries and rejection, that will balance the market. Regionally, there’s other places other than the Permian Basin where the gas base, it doesn’t make sense to recover necessarily or further to transport to market. As far as opportunity set for us, it’s going to lead to some positive storage opportunities on collecting contango.

Jean Ann Salisbury: Okay. That makes sense. And then my follow-up is about the TW Product slide. Is this the final state of the TW Products System? I think you said in the release that it’s 20,000 barrels a day of truck loading capacity in Utah. Can the pipe do more than that if you add truck loading capacity, or should we think about this as being the end state of the system?

Justin Kleiderer: Hey, Jean Ann, it’s Justin. No, we have more capability to add truck [indiscernible]. In fact, we’re doing that right now in our Permian terminal because our terminal is full. So, as we identify additional demand and our demand further up system continues to ramp, we’ll look for those deep bottlenecking opportunities to take advantage of it.

Jean Ann Salisbury: Okay, great. Very clear. I’ll leave it there. Thanks.

Operator: Thank you. Our next question comes from the line of Spiro Dounis of Citi. Your question, please, Spiro.

Spiro Dounis: Thanks, Operator. Good morning, everybody. I wanted to go back to Piñon really quickly. Maybe can you just walk us through your decision to buy versus build there. Just curious if that was in any way reflective of some sort of bottleneck on the treating side in the basin.

Jim Teague: I guess I’ll start, Natalie. First of all, if we had built Greenfield, we were looking at 3 years, if I’m not mistaken. We’ve missed some opportunities because we didn’t have this service. So we needed the platform, and it was the easiest, quickest way to get it.

Natalie Gayden: Yes, that’s good.

Jim Teague: Does that answer it, Spiro?

Spiro Dounis: It does. I appreciate that. Second question, just maybe sticking with New Mexico. I guess last week there was some news headlines just around a new setback rule that could come into play. I know this can pop up from time-to-time and it sounds like at least for now there’s not much to do around it. But just curious maybe to get your all’s view on how you think about the potential impact there if something like that comes into play.

Jim Teague: I don’t — I didn’t hear the question, Anthony. Did you …

Natalie Gayden: Setbacks in New Mexico.

Anthony Chovanec: Yes, setbacks in New Mexico. I’ll speak for myself and then — yes, I’ll speak for myself from a fundamental standpoint and then, Nat, will you address it? I think the industry is very firm and, as I always said, tell us what the rules are and we’ll know, we’ll figure out how to adjust to them. Natalie, I haven’t heard, maybe you have, or have not, anybody say that they’re doing anything other than studying these rules. It’s certainly from the meetings I’ve been and it hasn’t changed people’s plans at this point. I think the other thing to add to that is remember that we drill horizontally laterals that may be at 3 or 4 miles. So I’m confident from a fundamental standpoint that the industry is going to be able to adjust once they know what the rules are. Are you hearing anything different?

Natalie Gayden: Nothing different. I think it’s too early to speculate on what impacts it will have and nothing more than commentary from a few New Mexico producers.

Spiro Dounis: Great. I appreciate the color. Leave it there. Thanks, team.

Operator: Thank you. Our next question comes from the line of Jeremy Tonet of JPMorgan. Your question, please, Jeremy.

Jeremy Tonet: Hi, good morning.

Libby Strait: Good morning.

Jeremy Tonet: Just wanted to touch base with Tony here on I guess more on the macro outlook and I guess producer-customer conversations as well as what the macro team sees as far as production trends at this point in time, given the volatility we’ve seen in commodity prices.

Anthony Chovanec: Yes, this is Tony. I’ll start with it. I think as long as we’ve been publishing forecasts, this is maybe the second or third time that we’ve actually republished midyear. And that’s because what we’re seeing both in traditional benches and new targets to gassier benches. When you look at EIA numbers, I’ll kind of go ahead and go there. I understand that’s a very hard thing to set your watch to, that’s not what we use. They’re trying to get better at it, but it’s — they’re making slow progress. What we said in the Permian Basin, there’s been a lot of noise also relative to weather in the Bakken and in the Gulf of Mexico relative to [indiscernible]. So, let’s go to what’s stable and what’s the large thing that moves the number, and that’s the Permian Basin.

We said that over a 3-year period, just looking at black oil, that we would have about 1.5 million barrels a day of growth over that 3-year period. For 2023, we’re at about 750,000 barrels. We think that number for 2024 will be 350,000 to 400,000 barrels and from what we’re seeing as far as turn in line from our producers, it’s [indiscernible] it’s also then — that number is going to be very heavily weighted towards the second half of the year. So it’s not a long put, as a matter of fact, it’s what we expect that we will still — the Permian will meet that goal of probably a 1.5 million barrels in 2025. That said, you can look at our forecast and the one thing that is changing, and likely to change, is the commitments that producers are making to gassier basins.

And Natalie, I’ll let you take it from there.

Natalie Gayden: I agree. I think we often, we see it in our production plans from our producers. And they either, PDP isn’t coming off as expected, or let’s just say some of the B plans are holding a little bit longer. But definitely gassier, even if they’re on the order of 10%, sometimes they miss it by that order of magnitude, we see it time and time again. Not large numbers, but definitely something to keep up with.

Jeremy Tonet: Got it. That’s helpful there. Thank you for that. And maybe shifting gears a little bit here with Bahia. It looks like the timeline shifted a little bit there, so just wondering if you could update us on project development there and also just our current thoughts on Permian NGL pipeline egress. How do you see that shift?

Justin Kleiderer: Hey Jeremy, this is a Justin Kleiderer. So just minor delays in our expected timing on permit to construct, causing the delay from the first half into this — into the third quarter. On the commercial development front, I would say, as you saw in our latest deck, Tony’s updated NGL forecast paints a very different picture for overall industry utilization. I think by 2028 now, the updated supply numbers have us upwards of 90% utilized as an industry. So, we’re still working the same playbook as we talked about in prior quarters around how we’re developing commercially there. But it really just comes down to how that incremental supply gets contracted, whether that be a combination of additional GMP assets that Natalie alluded to earlier, or continuing to pursue third-party NGLs.

Jeremy Tonet: Got it. That’s helpful. Thank you.

Operator: Thank you. Our next question comes from the line of Michael Blum of Wells Fargo. Your line is open, Michael.

Michael Blum: Thanks. Good morning, everyone. I wanted to ask about the announcement yesterday on the CO2 pipeline project with Oxy. Once you’ve just confirmed this is new pipe, you’re not repurposing and get a sense for how many miles of pipe are we talking about, and we do expect to get your typical midstream contract structure and typical midstream return on a project like this.

Robert Sanders: Good morning, Michael. This is Bob Sanders. The contract with 1.5 is a fairly straightforward transportation agreement. When 1.5 goes to FID, they will tell us what emitters to connect to so we know what to design for. It is new pipe because it is ANSI 900 pipe. It’s a high-pressure pipeline system. We expect 1.5 to FID sometime in the first half of 2025, and at that point, we’ll know what the capital is, and the fee will be set accordingly.

Michael Blum: Great. Great. Thanks for that. And then I just wanted to ask about LPG export dock spot rate dynamics. I guess the rates have increased in recent months. I wanted to get a sense how full of the docks, and your docks specifically from that perspective, are you able to capture any of these higher spot rates or are you basically fully contracted?

Tug Hanley: Yes, this is Tug. So, we’ve talked about it in a prior earnings call that we did a debottlenecking project at the ship channel, it provided us higher capacity. So, right now we’re having anywhere between 2 to 3 spot cargos per month, and we are capturing those higher values, call it mid $0.20 per gallon.

Michael Blum: Great. Thank you.

Operator: Thank you. Our next question comes from the line of Neal Dingmann of Truist. Please go ahead, Neil.

Neal Dingmann: Good morning. Thanks for the time. My first question is on your Petrochem specifically. Are you all continuing to expand the ethylene and propylene systems? I’m just wondering, do you guys, do you continue to believe more export capacity will be needed there.

Christopher D’Anna: Hey, Neal, it’s Chris D’Anna. We are continuing to grow, particularly our ethylene pipeline system. So if you remember, that pipeline system didn’t exist before 2019. And we’ve built a pretty substantial system, and we plan to continue to grow that. And then in terms of our exports, we have an expansion underway. It’s the — I don’t know, at our Morgan’s Point dock, and that’ll come online, the first phase of that will be online at the end of this year.

Neal Dingmann: Chris, perfect. [Indiscernible].

Jim Teague: Talk about real quick what you’re seeing in Europe and what you think that creates for us.

Christopher D’Anna: Yes, I think one of the growth opportunities that we see for ethylene exports in particular is Europe. With the economics that those crackers have, one, they’re quite a bit smaller, so they don’t have the economies of scale that we have here in the U.S. And then secondly, just the overall feedstock, it’s a whole ethane versus naphtha, or natural gas versus crude kind of fundamentals there. So we expect to see, and we’ve heard from a lot of the chemical companies that they’re doing strategic reviews of their European assets. So we expect to see some closures, and we expect that to lead to additional ethylene exports going that way.

Neal Dingmann: Great details. [Indiscernible]. And then my second is just on marketing specifically. It seems like Waha continues to be quite volatile, so I’m just wondering, based on that, can we assume the marketing business continues to remain strong for you all?

Randy Fowler: Yes, we have roughly 370 million a day open on that West to East Waha spread, so we do expect that to continue to contribute.

Neal Dingmann: Great to hear. Thank you.

Operator: Thank you. Our next question comes from the line of Keith Stanley of Wolfe Research. Your question, please, Keith.

Keith Stanley: Hi. Thank you. Good morning. First, just curious for an update on commercial conversations on the spot project. I think there was a quote a week or two ago from a conference of, trying to get a first customer to sign up for that project. Just an update on any momentum you’re having there.

Jim Teague: You want to take it, Jay?

James Bany: Hey, Keith. This is Jay Bany. Yes, just related around commercial conversations, they’re quite extensive and in various degrees of conversation, anywhere ranging from we’re working through definitive agreements, changing term sheets. I’d say a large portion of our customer base are currently just evaluating the cost inefficiencies related to ship-to-ship transfers and how that affects their business, both their, call it net back as American producer expenses, or ultimately delivered price for international customers. And so we expect to hear some of that feedback here, call it, the end of this quarter, early first quarter.

Keith Stanley: Thanks for that. Second question, I’m admittedly not sure this is a great answer to this necessarily, but the valuation gap between the C-Corps in the space and the MLPs is at a record high above anything I can recall. Are there any potential ways the company could capitalize on that? I don’t know if it’s selling assets at higher valuations or other ways to respond to the market seemingly valuing C-Corps much more highly than MLPs these days.

Randy Fowler: Hey, Keith, this is Randy. I don’t think there’s any quick solution or answer there. I think coming in and trying to play the game of selling assets at a higher valuation is somewhat short-sighted, especially when you come in and you look at the depreciation recapture that comes and it gets pushed down to all your limited partner. All it becomes is a tax event for your limited partners, and I don’t know what actually you’ve accomplished. So, we’ve seen 2 or 3 years ago, I think it was near these levels and then we saw the two compressed, but generally when there’s this big of a difference in asset classes, normally the market solves it one way or the other.

Keith Stanley: Thank you.

Operator: Thank you. Our next question comes from the line of John McKay of Goldman Sachs. Please go ahead, John.

John McKay: Hey all. Thanks for the time. I just want to maybe do two quick clarifications. First one is, Rand, this is to you, I guess, just on that last comment, is the up-fee idea still out there? Is there any reason you guys have permanently put that to the side at this point?

Randy Fowler: I appreciate the thought there. Again, I think that’s another — sort of the devil’s in the detail there. Number one, now you’ve got — you would have two securities outstanding. You need to build liquidity up in that second security. And by the way, then what do you do with use of proceeds? So I think — and if I come in and look over time, there’s not really been and there’s been examples whether it’s the upseas [ph] or whether it’s been the, oh, gee whiz, the [indiscernible] units that were done way back 20 years ago. And you really never saw that much differentiation, whether it was the institute, the [indiscernible] units, the institutional class units of a partnership that was more institutional investor friendly, or whether it was the UPSI and the underlying MLP. So to us, that adds a lot of complexity, and really you don’t get that much bang for your buck.

John McKay: That’s clear. I appreciate that. Second quick follow-up. I appreciate the comments and all the work done on the PDHs. I just want to clarify, are both up and running fully now? Is this a fourth quarter run rate going forward? Is this a first quarter ’25? Then maybe if you could just remind us maybe what those two assets in aggregate could add from an ongoing cash flow basis, that’d be great.

Jim Teague: They’re up and running, both of them, running at full rates if not higher. And Chris, I’d say it’s in the neighborhood of $200 million.

Christopher D’Anna: That’s right.

John McKay: That’s clear. Congrats on getting that done, and thanks for the time.

Operator: Thank you. Our next question comes from the line of AJ O’Donnell of TPH. Your question, please, AJ.

AJ O’Donnell: Hey, good morning. Thanks for taking my question. Just a quick one on Matterhorn [ph], with that pipeline now running about a Bcf, or over a Bcf a day. Curious if you guys have seen a jump in flush production into your system in Q4, or if the majority of the pipeline volumes are just flows shifting around the basin or redirected gas.

Jim Teague: I don’t think we’ve seen a flush production yet, have we, Natalie?

Natalie Gayden: Yes.

AJ O’Donnell: Okay. Maybe just going back to the capital budget then, just trying to understand on the increase in the ’25 budget, I was hoping maybe you could bribe just a little bit of a discolor on the types of the projects you’re seeing with Piñon. I’m just curious if there’s any more of that to potentially be announced in the ’25 budget or does that seem a little bit further off?

Jim Teague: I believe you’re going to have Piñon projects next year.

Natalie Gayden: Yes. We’ll do our job as well.

Jim Teague: Natalie says yes.

AJ O’Donnell: Okay. Thanks guys.

Operator: Thank you. Our next question comes from the line of Manav Gupta of UBS. Your question please, Manav.

Manav Gupta: Hi, good morning. You guys did a very good job of explaining some of the 2025 growth projects. Help us understand the product pipeline is pretty strong, whether it’s Mentone West 2, or Neches River. How should we think about the key growth projects for 2026 at this stage?

Randy Fowler: Yes, Manav, thanks for the question. I think we’re still at the point where, and we try to point this out in our supplemental slides for earnings, and you come in and you look at the projects that have been FID’d. I want to say that the runoff in 2026, what we have remaining to spend on currently FID projects is probably about $1 billion, $1.2 billion. If you would, in 2026 we have room that we put in there that we think will probably be in the range of $2 billion, maybe it’s upward to $2.5 billion, but we have room for development of other growth-oriented projects between now and then. And that’s where we think 2024 and 2025 is really a period of elevated CapEx, and that will come back in more on a longer term basis. See that come back down to around 2, 2.5.

Manav Gupta: Perfect. Thank you.

Randy Fowler: And you saw this, and again, I’ll come back in, I’m sorry. You sort of saw the same thing in 2018, 2019. In those years, we were about $4 billion in growth CapEx, and again, those had some large projects and some step changes in capacity. And then you saw our growth CapEx moderate back down, and we think the same thing will happen once you get out to 2026.

Manav Gupta: Perfect. My quick follow-up is there was a little bit of a step-up in buybacks in 3Q versus 2Q. Again, as you’re going through this build-out, how should we think about shareholder returns for the rest of 2024 or even 2025?

Randy Fowler: I think, again, with 2024 and 2025 CapEx being at elevated levels, you’ll probably continue to see buybacks in that $200 million, $300 million range. I think once we get out to 2026, we’ll need to reassess what the opportunities are at that time, and we’ll go from there.

Manav Gupta: Thank you for taking my questions.

Operator: Thank you. I would now like to turn the conference back to Libby Strait for closing remarks. Madam?

Libby Strait: Thank you, and thank you to our participants for joining us today. That concludes our remarks. Have a good day.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.