Enterprise Products Partners L.P. (NYSE:EPD) Q4 2023 Earnings Call Transcript

Enterprise Products Partners L.P. (NYSE:EPD) Q4 2023 Earnings Call Transcript February 1, 2024

Enterprise Products Partners L.P. beats earnings expectations. Reported EPS is $0.72, expectations were $0.66. Enterprise Products Partners L.P. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day and thank you for standing by. Welcome to the Q4 2023 Enterprise Products Partners LP Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your speaker today, Randy Burkhalter, Vice President of Investor Relations.

Randy Burkhalter: Thank you, Josh. Good morning everyone and welcome to the Enterprise Products Partners conference call to discuss fourth quarter 2023 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 and 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. And with that, I will turn it over to you Jim.

Jim Teague: Thank you, Randy. We generated $7.6 billion of distributable cash flow in 2023, providing 1.7 times coverage, and we retained $3.2 billion. We set nine financial records and 13 operating records in 2013. Our 2023 operating results included records in NGL pipeline transportation, ethane exports, total NGL marine terminal volumes, NGL fractionation volumes, fee based natural gas processing volumes and crude pipeline and natural gas transportation volumes barrels of oil equivalent per day enterprise transported a record 12.2 million barrels a day in 2023, compared to 11.2 million barrels a day in 2022. During the fourth quarter, we transported 12.7 million barrels a day, compared to 11.5 million barrels a day in the fourth quarter of 2022.

We exported a record 2.3 million barrels a day of liquid hydrocarbons. That includes everything from crude oil to LPGs to ethane, refined products and basic petrochemicals, ethane and propylene. When you look at our exports, it’s clear that enterprise is not a one trick pony. It’s quite remarkable that volumes across all our pipes and facilities increased sequentially each quarter in 2023, supported by the strong supply and demand fundamentals for hydrocarbons from the Permian and other basins we serve integrated with the midstream services we have, including exports that we just discussed. Relative to commodity markets, 2023 was a relatively weak year, especially for natural gas and natural gas liquids. Nonetheless, Enterprise proved once again that we don’t need really high prices to make substantial returns.

The financial records and 13 operating records summarized were achieved in a commodity price environment where natural gas prices were down almost 60% from 2022, crude was down nearly 20%, propane was down 36%, ethane was down almost 50%, and the NGL processing basket was down 35%. Relative to the several 2023 records at our marine terminals, we have long said that hydrocarbons would price to export proven once again in 2023. In growth capital during 2023, we completed construction of $3.5 billion of projects. Significant assets put into service include two new natural gas processing plants in the Permian Basin and our 12th NGO fractionator in Chambers County. All of these assets were essentially full after operations began. While production of our PDH 2 facility was completed in the third quarter of 2023, we spent much of the remainder of the year addressing startup issues.

As a result, this plant did not meet our expectations and earnings in 2023. We believe most of these issues have been resolved and we anticipate much higher utilization rates this year. We began 2024 with 6.8 billion of major organic projects under construction, with three projects representing approximately $1.1 billion in capital investment expected to be completed this year. Major 2024 projects include our Texas Western Products pipeline system and two additional processing plants in the Permian. We have considerable amount of growth capital underway. All of these projects provide strategic growth to our system and can add considerable disability to new sources of cash flow. I wanted to take a minute to talk about project 9.3. We started this project in 2022 as an incentive for all employees to find innovative ways to improve the bottom line.

This was especially important as we in the industry were re-engaged This was especially important as we in the industry were reengaging after COVID and faced the challenges of a slower global economy in 2023. We achieved the goals we set for ourselves both in 2022 and 2023. We are very proud of our employees for that accomplishment. That said, we will not have a Project 9 type program for 2024. You’ve always heard me say, if you want to know where we’re going, look at what we’re doing. The Permian Basin has been the cornerstone for much of our growth capital. As we look at 2024 and beyond, we see supply and demand opportunities as the Permian continues to grow and the world continues to have an ever-increasing appetite for U.S. hydrocarbons.

We noted in the press release that these may be the most geopolitically challenging times since World War II, but it’s abundantly clear that all of this chaos is leading itself to a growing appetite for the most stable hydrocarbon supplies in the world, the USA, in spite of government and regulatory challenges. Without a doubt, relative to energy, our nation’s biggest geopolitical challenges continue to be self-inflicted. Enterprise has one of the world’s leading natural gas liquids franchise, and we have the liquids hydrocarbon storage and export franchise. On top of all of that, we have a dedicated employee base that creates value, regardless of the environment. 2023 marked our 25th anniversary as a public company. It’s been a great quarter century.

It has been for the U.S. energy industry. It included the downfall of the energy merchants, the great financial crisis, the innovation of the E&P and oil field service industries to unlock the potential of the Shell plays, which is still continuing. It included the near-debt and remarkable renaissance of the U.S. petrochemical industry, from having the highest cost feedstock pre-Shell to now the lowest cost. It included two OPEC price wars, a once-in-a-century pandemic, and the re-emergence of geopolitical upheaval. During this time, we stuck to our objectives of investing capital at reasonable returns, providing reliable value-added services to customers, consistently returning capital to our partners, and increasing the value of the partnership for the long-term.

During this time, the enterprise value of the partnership has grown from $1.2 billion to almost $90 billion. The value of our partnership units has increased almost 400%. We increased our distribution 25 consecutive years at an approximately 7% compound annual growth rate. We’ve returned $52 billion of capital to investors through distributions and buybacks. We have high-quality employees, and we thank our employees, we thank our customers, our service providers, our banks, and our investors for their contributions to this success. We’re looking forward to the exciting opportunities and challenges for the next 25 years as the world’s population, quality of life, and demand for energy reaches new heights. Put frankly, based on what I see in the future for energy, I’d give anything if I could turn the clock back and be 50 years old.

With that, I’ll turn it over to Randy.

Randy Fowler: All right. Thank you, Jim. Good morning, everyone. Starting off with the income statement, the net income attributable to common unit holders for the fourth quarter of 2023 was $1.6 billion or $0.72 per common unit on a fully diluted basis. This compares to $1.4 billion or $0.65 per common unit for the fourth quarter of 2022. Adjusted cash flow from operations, which is cash flow from operating activities before changes in working capital, was $2.2 billion for the fourth quarter of 2023 compared to $2.1 billion for the fourth quarter of 2022. We declared a distribution of $0.515 per common unit for the fourth quarter of 2023, which is a 5.1% increase over the distribution declared for the fourth quarter of 2022.

The distribution will be paid February 14th to common unit holders of record as of the close of business on January 31st. In the fourth quarter, the partnership purchased 3.7 million common units off the open market for $96 million. Total purchases for 2023 were $187 million or 7.2 million common units, bringing total purchases under our buyback program to over $900 million. I mentioned it on the last call, looking at our five largest midstream peers by market cap. Since 2019, Enterprise is the only midstream energy company to reduce absolute outstanding units outstanding without significant asset sales. In addition to buybacks, our distribution reinvestment plan and employee unit purchase plan purchased a combined 6.6 million common units on the open market for $172 million during 2023.

For 2023, Enterprise paid out approximately $4.3 billion in distributions to limited partners. These distributions combined with the buybacks for the year, resulting in our having a payout ratio of adjusted cash flow from operations of 56% and a payout ratio of adjusted free cash flow of 94%. Total capital investments in the fourth quarter of 2023 were $1 billion, which included $823 million for growth capital projects, $65 million for the acquisition of a small natural gas storage facility that we have historically leased, and $129 million of sustaining capital expenditures. Capital investments for the year of 2023 were $3.3 billion, which includes $2.75 billion of organic growth capital projects, $100 million in asset acquisitions, and $413 million of sustaining capital expenditures.

During the third quarter call, we estimated $3 billion of organic growth capital expenditures in 2023 and a range of $3 billion to $3.5 billion in 2024. Due to the timing of expenditures, we had approximately $250 million of CapEx shift from 2023 into 2024. Therefore, we now expect our 2024 growth capital expenditures to total $3.25 billion to $3.75 billion. We expect 2024 sustaining CapEx will be approximately $550 million, which includes dollars for planned turnarounds at PDH-1, our IBDH, and our high-purity isobutylene facility. These scheduled turnarounds typically occur every three-to-four years for these type plants. Our total debt principal outstanding was approximately $29 billion as of December 31, 2023. Assuming the final maturity date of our hybrids, the weighted average life of our debt portfolio was approximately 19 years.

Our weighted average cost of debt is 4.6%. At December 31, approximately 96% of our debt was fixed rate. Our consolidated liquidity was approximately $3.9 billion at the end of the fourth quarter, which includes availability of our credit facilities and unrestricted cash. Adjusted EBITDA, as Jim mentioned earlier, was $9.3 billion for 2023. We ended the year with a consolidated leverage ratio of 3.0 times on a net basis after adjusting debt for the partial equity treatment of our hybrid debt and reduced by partnerships unrestricted cash on hand. Our leverage target remains three times, plus or minus a quarter term, so 2.75 times to 3.25 times. In January, we issued $2 billion of senior notes comprised of $1 billion of three-year notes at a coupon of 4.6% and $1 billion of 10-year notes at a 4.85% coupon.

The proceeds from this offering will go toward an upcoming $850 million debt maturity in February, I guess this month, and funding our capital expenditure program. We appreciate the continued support of our debt investors. Moving on to future events, Enterprise will host an analyst and investor call on Wednesday, April 3. This will be in lieu of our in-person analyst day. This call will include overviews on our current outlook, near-term objectives, allocation of capital, as well as fundamentals updates from Tony. Q&A will follow our prepared remarks. More information will be provided in the coming weeks. Before we open the call up to questions, Jim and I would like to take a moment to recognize Randy Burkhalter, our Vice President of Investor Relations.

After a 46-year career in the energy industry, Randy has announced his retirement for April of this year. Randy has led our investor relations effort for the past 21 years, when he joined us shortly after our acquisition of the Mid-America and Seminole pipelines. Through the annual Institutional Investor Magazine, all American team surveys, Enterprise and our investor relations team have been consistently recognized by the sell side and buy side community as one of the best in the midstream sector. Randy has been integral to leading this effort. We are grateful for Randy’s service, his integrity, his attention to customer service, and his industry-renowned social prowess. Please join us in congratulating Randy on his 46-year career and a job well done.

Most of you have met Libby Strait. Libby will succeed Randy in leading our IR effort. Libby is one of our young All-Stars who joined the company in 2013 and worked in commercial roles of increasing responsibility across several of our business units before joining the IR team 2019. She and Michael Cisarik, another one of our All-Stars, will comprise our IR team.

Jim Teague: Randy, as it relates to Randy Burkhalter, I think it’s fair to say we have already scheduled a quarterly visit by Randy to the building to have a couple of scotches back of our downtown at least once a quarter.

Randy Fowler: With that, I think we’re now ready to open the call-up to questions.

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Q&A Session

Operator: Thank you. [Operator Instructions] Our first question comes from Michael Blum with Wells Fargo. You may proceed.

Michael Blum: Thanks. Good morning, everyone, and congrats, Randy. And Jim, please send me the invite for the scotch. Get together. I wanted to start with maybe your latest views on Permian growth in 2024, both for oil and for gas. And then kind of a related topic. Clearly, there seems like there will be need for another Permian gas takeaway. You had talked about a Brownfield project a little while back. It’s been kind of quiet lately. So I wanted to get your latest thoughts on Permian gas takeaway solution in light of your growth outlook.

Tony Chovanec: Hey, Michael, this is Tony. In our last analyst meeting, which was March of 2023, we talked about growth in the United States of, call it, 1.8 million barrels. I’ll just go to oil right now. We gave you some basic metrics as to what happens with the oil. But 1.8 million barrels in the 23, 24, 25 time frame. Obviously, there was a lot of pushback when we published that forecast from all sides, including producers that hadn’t looked at the number like we had. And what I’ll say about that number now, of that 1.8, we said 1.5 in the Permian basin. Certainly, given the performance of producers during 2023, the producer community is on track to meet and likely beat those numbers. And I don’t know how that changes at this pace.

And then the combined growing wedge of PDP that a lot of people forget about in key basins, coupled with the continuous improvement in efficiency and productivity that we see from the producer community. So we’ll talk about it more in early April, but I’ll — I think the clip notes now, what we know is, it’s really going to be hard not to at least meet and likely beat that number as we look at the three year period, very much Permian dominated. Relative to gas pipelines we’ve talked about a simple metrics before for every million barrels incremental that you have with oil, you have somewhere in the neighborhood of available 400,000 to 500,000 barrels of NGLs. And for rich gas, call that anywhere from 3.25 to 3.5 Bcf. Okay. So you do the math, you look at what we have today and incremental capacity over the next two years is coming on is appreciable.

Will there need to be more between now and 2030? Yes, the answer that yes, in some form or fashion. Whether it be brownfield, on existing pipes or another Greenfield pipe.

Michael Blum: Okay, great. Thanks for all that, Tony, maybe we’ll just stand gas. My second question just wanted to ask about the pause in LNG permitting and I know you’re not, you don’t have an LNG asset per se. Curious how if at all this would impact your business in 2024 and beyond. Thanks.

Jim Teague: Okay, Michael, this is Jim. And I guess I wonder, is it truly a pause? Or is it something more? And with those will those projects that are not under construction, but going through the regulatory process be allowed to continue to go through that process during this quote, temporary pause, or will all work stop. Our fundamentals group says we’ll have 75 years of reserves at current production with current technology. Our own — you look at it, our LNG has had a huge difference to our allies. In 2019, we averaged 1.85 Bcf a day to Europe. And 2023, we exported on average 7.5 Bcf a day with a winter peak of over nine Bcf a day. We went from less than 10% market share LNG into Europe, 50% market share. Now Rusty Braziel in his RBN blog this morning has an excellent write up on this issue. So really, you have to sit back and wonder, is this a temporary pause? Or is it a political pause?

Operator: Thank you. One moment for questions. Our next question comes from Neel Mitra with Bank of America. You may proceed.

Neel Mitra: Hi, good morning. Congratulations, Randy. First question was on the NGL exports and hitting a quarterly record. Could you maybe comment on the export dynamics right now? Just with weaker PDH demand and the plants coming up slower than normal, but also lower NGL prices in the U.S. and how that probably is trending to 2024.

Tug Hanley: Yes, this is this is Tug Hanley. So we’ve had strong operational performance on our EHT asset, which has led to healthy volumes going across the dock. There’s also been a decrease in freight values we’ve seen, which is continuing to support stronger FOB values. With respect to the weaker PDH margins on an international level, the PDH margins have improved, but there’s still a lot of overcapacity. So necessarily weak, weak margins don’t lead to decreased NGL demand, because it’s still the demand is still ultimately there.

Neel Mitra: Got it. And then my second question is related to Bahia. And I was just wondering if you could maybe give some puts and takes as to where you can see additional volumes picked up. Believe Navitas isn’t going through your system right now, maybe the lucid volumes come up for, for re-contracting and in kind of later in the decade, and where you could see some additional opportunities to pick up volumes that aren’t contracted onto your system right now.

Justin Kleiderer: And you know, it’s Justin Kleiderer. Yes, so kind of like three buckets of Bahia that we think about first and foremost is our growing GMP footprint. So you think about a metric of every new gas plant we put on, we yield about 40,000 barrels to 45,000 barrels a day of NGLs into Bahia. So we’re growing our footprint both in the Delaware and the Midland. So that’s always the base load as we think about Bahia. And then on top of that, we have a robust set of third-party agreements. We’ve got 40 connections on our wide-grade system that gives us a lot of diversity to go capture incremental third-party volumes as that market ebbs and flows. And we’ve got a good runway of contracts on those that get us to the back end of the decade without having to really worry about any contract roll-off.

And then third, kind of our expectation is that Seminole won’t be an NGL service once Bahia comes online. You add all those up and that’s kind of how we land on the capacity that we created out of the gate at 600 a day.

Neel Mitra: And Natalie, do you think we’re through building processing plants up there?

Natalie Gayden: I don’t think we’re through.

Neel Mitra: Okay, great. Thank you very much.

Operator: Thank you. One moment for questions. Our next question comes from Theresa Chen with Barclays. You may proceed.

Theresa Chen: Good morning. I’d like to echo the congratulations to Randy on his retirement after a stellar career. We wish you continued social progress and also congratulations to Libby and Michael. When we look at your organic projects backlog, it’s a robust set of opportunities. And as we look beyond 2025, just trying to think about what a run rate should be, knowing that you still do have some projects under development and some of them sizable. Is that three or three plus billion dollar number a good run rate or how should we think about that?

Randy Fowler: Yes, Theresa, I’ll start off. We’re $6.8 billion worth of projects under construction. And again, this year, it’ll range from three, three and a quarter to $3.75 billion. 2025 is $3 billion. And then there’s a little bit of roll off with that $6.8 billion that creeps over into 2026. The one thing I would just note is in that $6.8 billion, we’ve got two lumpy projects being Bahia Pipeline and also the export facility that we’re building on the Neches River. And so if I come in and look forward and the expectation will continue to see build out with natural gas processing, with the gas gathering and compression that supports that. I keep coming back that I really think that going forward, absent spot that we’re more in the $2 billion range is where I keep coming out just again, because we’ve had some lumpy projects.

We just put PDH 2 into service in 2023. That was another lumpy project. So just don’t foresee a lot of those lumpy projects coming with the exception of SPOT.

Theresa Chen: Got it. Thank you.

Randy Fowler: I think with SPOT that’s probably a 3-year construction cycle.

Theresa Chen: Understood. And in terms of projects that are coming online near term for your Texas West product system, can you remind us how much of that is underwritten by third party commitments versus open capacity that you hope to market and capture that ARB, especially in light of the fact that, since you announced the project, one of your midstream competitors who also has significant marketing capabilities bought a huge refined product system and is also looking to close PAD 2 and PAD 4 ARBs.

Justin Kleiderer: Hey, Theresa, it’s Justin Kleiderer again. And Tug may chime in on a piece of that as well. But as we develop the project, it’s really it really has developed into really a rack marketing model. We had the first phase of startup really impending and the timing of the rest of it should be lined out in the deck. But we’ve got significant interest. We’ve got 40 third party contracts agreed to across the terminals and we’re signing up more seemingly daily. So people are just itching for it to come on. But we do think similar to Dixie and our legacy propane long haul pipelines being sort of an uncontracted rack-based model, that that’s the model that we’re going to see on TW.

Theresa Chen: Thank you.

Operator: Thank you. One moment for questions. Our next question comes from Jeremy Tonette with JPMorgan Securities. You may proceed.

Jeremy Tonet: Hi, good morning. And Randy, I want to wish you congratulations here. Good luck with everything going forward. You will be missed, and thank you.

Randy Burkhalter: Thank you, Jeremy.

Jeremy Tonet: And I just wanted to start off, I guess, with the recent Houston ship channel enhancements that we’ve seen over time here. I’m wondering if you could comment on how that’s impacted your LPG export capabilities. Have you seen any kind of improvements there given the changes? Just curious how that has developed.

Robert Sanders: Yes, this is Bob Sanders. Late in the fourth quarter last year, the Houston pilots removed the daylight restriction on LPG ships. So we can sail 24 hours a day loaded or empty. And we are incrementally picking up the number of vessels we’re bringing in to try to maximize the utilization of the refrigeration units that we’ve got right now. So we are seeing a direct benefit.

Jeremy Tonet: Got it. Just curious if that’s a minor or maybe, bigger expansion. And also, Tony, I guess I’m curious, I guess, with thoughts on LPG pricing here. I guess there’s a concern in the marketplace that LPG exports might be maxed out and that could dislocate domestic pricing relative to international price markers. So just wondering how you see that playing out.

Tony Chovanec: I’ll answer the first piece a little bit. We’re seeing about a 5% to 7% gain at this point.

Randy Fowler: I think on pricing, you’ve seen NGLs catch a bid here recently. I think some of what Bob mentioned has helped with pricing. As freights come off, there’s been a benefit to certainly to propane and butane on the flat price. But if you look at the growth that Tony mentioned earlier, we have NGLs growing at a faster pace than crude oil. We’re seeing it across our system. Storage is going to become more increasingly valuable. These expansions don’t come on until 25, 26 timeframe. So we expect the docs to remain at capacity. And then ultimately, the flat price of NGLs will be reflective of that.

Tug Hanley: Yes, this is Tug. I’ll just add that we’re actually seeing that already manifest itself on our spot. Doc values are upwards of double digits right now.

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

Operator: Thank you. One moment for questions. Our next question comes from Brian Reynolds with UBS. You may proceed.

Brian Reynolds: Hi, good morning, everyone and Randy. Thanks again for all the time you spent with me and the community over the last 21 years. And thanks for leaving the team in good hands with Libby and Michael.

Randy Burkhalter: Thank you, Brian.

Brian Reynolds: Maybe to start off on the NGL macro. Jim, on the last call, you kind of talked about competitive market dynamics, right now, where EPD seems to be threading the needle of maximizing return while preventing some new entrants into the integrated NGL value chain. While I appreciate some of the opening remarks from Tony to Michael’s question around Permian growth, just kind of curious how we should think about maybe, volume growth is going to be really attractive over the next few years, but kind of curious if we can talk about how transportation fracking export rates, should look relative to, what they’ve been the past decade, just really attractive. Thanks.

Unidentified Company Representative: Hey, Brian, this is Brian. I mean, it kind of varies based on the service. I think everything that you see on a processing side, certainly on the kind of long haul pipeline is a new build economic type number. Fractionation is probably in that group, too. I think when you look across NGL docs, and you look at the entrants that are in that space right now, I think anybody who wants to be in that space is going to have to compete with brownfield economics. And if you look at where FOB values are going for both ethane and LPGs, it is incredibly, incredibly difficult to make a project accretive that’s a new entrant in that space.

Brian Reynolds: So, Brian put directly, while Tug says on our spot deals we have double digit terminaling values, what can you do a five-year deal at?

Tug Hanley: I think when you look at, I don’t want to be totally specific on this, but the fees on LPGs are considerably less than what we’re seeing today. I don’t think anybody’s going to go out there and try to justify a project based on values that we see today, because we have capacity that we’re contracting. I think others have capacity that are contracting. And then on the FA and piece, that’s a very competitive market. I would have a hard time thinking enterprise would be in that market if we hadn’t been one of the first ones in that market.

Brian Reynolds: So you couldn’t build a Greenfield terminal based on what we think the terminating fees are going to be.

Unidentified Company Representative: Absolutely not.

Brian Reynolds: Great. Thanks. Appreciate all that. As my follow up, maybe just an update on the spot license and permit process. You alluded to some comments around the LNG and maybe have some having some impacts on the upcoming U.S. elections. Just kind of curious if we should see any risks to the timeline around the spot licensing and permitting process relative to maybe expectations from last year. Thanks.

Unidentified Company Representative: Hang on Bob. Brian, I didn’t, I didn’t say anything about the elections, by the way. Right now we haven’t, we’ve got a record of decision and I’ll let Bob tell you what else we’ve got. But right now, we don’t see anything that should preclude us getting that license.

Robert Sanders: So where we are with, with, with Mirad [ph] we, we have completed all the requirements to receive the license. We’re in constant contact with Mirad [ph]. As a matter of fact, we have seen a draft of the license, which they asked us to comment on, which we’ve commented on, and they’ve accepted our changes. So everything is basically done. We’re just waiting on knowledge that we’ve got the license.

Brian Reynolds: Great to hear. I’ll leave it there. Enjoy the rest of your day. And thanks again.

Operator: Thank you. One moment for questions. Our next question comes from Neal Dingmann with Truist Securities. He may proceed.

Neal Dingmann: Morning all thanks for the time and Randy, congrats and look forward to hearing what’s next for you. I can only imagine. My first question is on guys on marketing specifically. I just wanted to did you’ll capture some of the commodity price volatility experience with this last, I guess I’d call it the January cold snap, perhaps in Waha or the HSC spreads.

Brent Secrest: Neal, this is Brent. We were able to capture some, there were some kind of puts and takes on that whole, the whole weather event. There were some operational issues that we had in Midland that are, that are getting fixed. But from a marketing perspective, there was, there was some arbitrage capture on our side. And we pulled all our references, what you’re saying.

Neal Dingmann: Great. And then my second question, just on the PDH plan, just wanted to sound like for the second quarter row, you all mentioned a bit of operational challenges, maybe with the reactor and licenses issue. I’m just wondering, I think Randy, or for Graham, you mentioned, I think last quarter, you thought they’d maybe be more one off and just wondering, has something changed here and maybe just talked about your sort of future view of the ops there.

Unidentified Company Representative: This is Graham [ph]. Yes, we did have some operating issues in the fourth quarter with the PDH plan. Some of those are related, some of those related to some construction related startup issues, some design issues. At this point, we think we’ve got, the unit is up and operating. We’re not quite at 100% capacity, but we’ve got line of sight on the fixes that will be taking place here soon. And I think at that point, we can expect we’ll have a good operating unit, all the other parameters of the unit that we look at in terms of robustness and ability to maintain operation are really looking good right now. There’s just one, one issue, one more issue we’ve got to get passed on. I think we’ll be looking at a good unit there.

Neal Dingmann: Very good. Thanks for the details, guys.

Operator: Thank you. One moment for questions. Our next question comes from Tristan Richardson with Scotiabank. You may proceed.

Tristan Richardson: Hi, good morning, guys. Congrats to Randy. We appreciate all the time you spent with us over the years. Mr. Fowler, you guys have framed up the return of capital slide for a long time. And we’ve seen that payout ratio that adjusted payout ratio increase over time. And just curious what the stability you’re seeing in the earnings base and the stability you’re seeing in CapEx sort of as you mentioned over the long-term do you see that payout ratio changing meaningfully over time or is there a way to think about a long-term target for that adjusted cash flow ratio, particularly when you sit in such an advantage position from a leveraged standpoint?

Randy Fowler: Yes. I’m thinking of how to frame that because you had quite a bit in there. Several of our peers in the energy sector have come in with a formulaic approach on returning capital. And I think we’ve just been hesitant to doing that because we live in a very dynamic world and opportunities come up. And so really coming in and locking into a formula of so much distribution and so much buyback, more often than not, when I’ve seen companies come in with those formulas, they’re forever tweaking them or rescinding them. And they really have a short shelf life. I really just come back and look at, Jim went through some of our history of returning capital for our first 25 years. We’re going to continue to come in and do that as far as distribution growth.

I think you’ve seen over the last two or three years, we’re back to mid-single digit distribution growth, which is good to be there. And then we’ve been doing buybacks steadily on this. And I think if obviously if we come into an era where we’re not spending as much CapEx, then we’ll have more flexibility to come in and do buybacks. There’ll still be opportunistic buybacks. And I think you saw that when the third quarter, the unit price was really pretty strong and we just opted not to come in and do any buybacks in the third quarter of 2023. But when we got into year-end tax selling and saw the weakness in 2024, we executed buybacks at a better level, even considering the distribution that we the November distribution, we still executed at a better buyback level in the fourth quarter than what was available in the third quarter.

So I think we’ll continue to be opportunistic going forward. And then I think we just need to see what kind of opportunities that we have in the future. But again, I come back in and I don’t know of another midstream maybe other than what’s the Canadian? Or Canada that has successfully returned capital the way that we have over the last 25 years. So that was long winded, but I hope that helps.

Tristan Richardson: I appreciate it, Randy. And then maybe just on the earlier question to ask it a different way. I think, given the pace of NGO pipeline volumes today, plus Tony’s forecast and Justin’s earlier comments, is there an opportunity for the capacity of the year to expand as you progress through construction as we go into 2025 or are we seeing enough competing pipes in the market where this should be pretty balanced in 2025.

Justin Kleiderer: Yes, Tristan, we this Justin, we picked 600 for the reasons before, but you think of a 30 inch pipeline. If it’s fully horsepower, it could do upwards of a million. But we’re trying to be capital efficient about how we phase into it. So if our forecast are right and we need more than what we have today, we can add pumps on it to upsize it.

Tristan Richardson: Appreciate it. Thank you guys very much.

Operator: Thank you. One moment for questions. Our next question comes from Keith Stanley with Wolfe Research. You may proceed.

Keith Stanley: Hi. Good morning and congrats as well. Randy, you’ve definitely been one of the most helpful and friendly IR people that I’ve gotten a chance to work with. So thank you. Wanted to start just on the outlook, like the outlook for the year. So understanding, you’re not giving the employee goal for EBITDA for 2024. At a high level, though, you had a lot of momentum exiting 2023 in your results. You have a fair amount of capital and during service with PDH-2 and a couple of plants. You’re still constructive on volumes. Is it fair to say 2024 should be a relatively stronger growth year? Or are there any headwinds or things you would point to versus 2023 that could be an offset?

Jim Teague: This is Jim. I think 2024 is shaping up to be a better year than 2023. It’s not just the assets we’ve brought on. We’re seeing, for example, and Brent’s got some information, our processing margins on what is not fee-based is looking better. You might want to address that.

Brent Secrest: Yes, if we just look at the fourth quarter on what — we have floors in our processing contracts, especially around the Midland Basin. So in the fourth quarter, I think those floors were at around, they were all hit at about 97% of those contracts hit the floor. In fact, December was 100%. So as things get more constructive on gas, we’ll see if that happens. Certainly, there were some benefits in January. We’re seeing some benefits in the current month on NGLs. But that number is probably around 62% in January that hit the floor. So I think from a processing standpoint, there’s definitely benefits across the portfolio that we’ll see.

Keith Stanley: Okay, thank you.

Brent Secrest: It seems like each quarter, we transport more and more hydrocarbons.

Keith Stanley: Right, yes, Q4 volumes are definitely strong.

Randy Fowler: And Keith, this is Randy. I think the other thing is, just as you, I think we’ve, again, we’ve got a pretty good track record that if you look out over time, our average return on capital has been, I mean, it’s when you look at the total company has ranged from 10% to 13%. And then when you come in and you look at the CapEx, specifically the projects that we’re putting into service and the level of capital expenditures that we have, I think what that translates to over a three, four year period is probably mid-single digit EBITDA growth. Now, you’re not going to be able to use a ruler on that number, but that’s about what it works out to be. And then, then you may have some variability in and around that kind of number. But I think if you come back in and just look at what we’ve been able to do in the past and look at the amount of capital investment that we’re making, I think that’s where it would take you.

Jim Teague: The other thing is look at our, our people are relentless in visiting customers and getting new deals. I’ve been shocked at the appetite, for example, for our ethane export doc. And so we’re probably going to build new processing plants in the Permian, and I would expect that we’re going to fill up our ethane export docs and our LPG docs. The other thing we’re seeing is more crude flows to Houston. So we’re seeing more crude across our docs.

Keith Stanley: That’s all very helpful. And Jim, if I can kind of follow up on that last point, the NGL export volumes were very strong in Q4, and you noted the removal of the daylight restrictions helping you. Can you give a sense of how close the company is to its capacity based on that Q4 export number? Are you able to keep increasing exports this year before some of the expansions start up in 2025?

Jim Teague: I think if you look at NGLs as a whole and maybe crude oil, yes. If you look at LPG, I think things are going to be tight in terms of doc space on LPG. That gets resolved probably mid next year, but for 2024 and maybe part of 2025, LPG’s going to be pretty tight. You have something?

Keith Stanley: Thank you.

Operator: Thank you. One moment for questions. Our next question comes from Jean Ann Salisbury with Bernstein. You may proceed.

Jean Ann Salisbury: Hi, good morning. Do you forecast Permian processing utilization staying as tight as it is now over the next couple of years? Said another way, is it a stretch to say that the timing of processing coming on will dictate the pace of Permian growth in your view?

Brent Secrest: I think, Jean Ann, and this is Brent, I expect it to stay tight. When we look at our build out and the contracts that come on, there may be a short little window that there’s excess capacity, but it fills up very quickly. We’ll lean on Tony for his forecast, but what Tony has told us in years past has certainly come true. If not, it’s been even more prolific. And then when you look at capacity right now, I think there is gas that’s being held back in the basin. It’s waiting on compression and it’s waiting on processing capacity.

Brent Secrest: That’s exactly what I was going to say. It’s not just processing. Some of it’s gathering compression in the field that’s behind. Once we see that bottleneck kind of get fixed, we’ll see processing get full very quickly.

Jean Ann Salisbury: That’s very helpful. Thank you. And then one more. There’s some discussion of upcoming Haynesville gas pipelines possibly being delayed due to legal issues. Is there any further expansion potential on Acadian or is that maxed out here?

Brent Secrest: We’re maxed out after our last expansion. I’d say we may be a benefactor if that project is late. However, Haynesville is flat to staying flat. Would you say that, Tony?

Tony Chovanec: Yes. Jean Ann, there’s so much discussion about the Haynesville and what’s going to happen. And honestly, I’m somewhat befuddled by it. And I think that’s the right term. We’ve got LNG coming on in the Louisiana area. The call it is 4.5 to 5 Bcf over the next two years. And that’s a big number. And it has — there’s nothing that the whole permitting thing that has recently happened that Jim addressed so well this morning, it impacts that. So we think that — or we talk like Louisiana and the Haynesville has a chance to go to hell in a hand basket. And I’m sorry. I just don’t see it. Unless I’m missing something. The Haynesville, last but not least, is one of the primary basins for a massive amount of long-term storage of gas reserves. No question about it. So we still see it as an ideal and kind of a cornerstone basin for us relative to natural gas.

Jean Ann Salisbury: Great. Thanks for that, Tony. And thank you, Randy, for all of your help over the years. You’ll be missed. That’s all for me.

Operator: Thank you. One moment for questions. Our next question comes from Spiro Dounis with Citi. You may proceed.

Spiro Dounis: Thanks, operator. Good morning, team. Two very quick follow-ups from me. One, Randy, just want to go back to the distribution growth and follow up on Tristan’s question. The cadence the last two years or so has been an increase about every two quarters, tracking around that 5% annual growth. I know you like to keep us guessing. So as we think going forward, how opportunistic is the distribution growth from here? Or is that something we should really kind of expect going forward?

Randy Fowler: Yes. Spiro, again, I just go back to our track record. We don’t like to get out in front and run our board. But again, I think with the CapEx we’re deploying and the return on capital that we’re expecting to get, I think coming in, and we’ve been increasing distribution 25 years in a row. And I feel pretty good about 2026. And we’ve been doing it around mid-single digits.

Spiro Dounis: All right. Fair enough. Second one, just around M&A, you all purchased some natural gas storage assets around the quarter. Pretty small for you, so I don’t want to read into it too much. But just curious, is this sort of the beginning of a bigger push into natural gas storage? Or is it more opportunistic? As you look at the rest of your asset base, are there more opportunities like this to vote on?

Randy Fowler: That’s at Wilson Storage that we’ve leased for years and years. And in the contract, they had the right to put it to us. And they put it to us. And it was a reasonable price. So we weren’t upset. And that was legacy going back to GulfTerra Energy Partners. We sort of inherited that when we acquired GulfTerra.

Spiro Dounis: Okay. Perfect. Thanks, guys. I will save my project 10 questions for the April call. Thanks, everyone.

Randy Burkhalter: Josh, this is Randy. Let me cut in. We have time for one more question.

Operator: Thank you. One moment for questions. And our next question comes from John McKay with Goldman Sachs. You may proceed.

John Mckay: Hey, everyone. Good morning. Thanks for the time. I just wanted to touch one more time on the export side, understand that FOB spreads, FOB premiums are really high right now. But you talked about kind of outer coming down farther. Is it really just, we are going to see these rates stay high until yours and your kind of competitors’ projects come online in 2025? Or would you expect some benefit there once or if the Panama Canal starts to clear up?

Randy Fowler: Yes, we expect the rates to remain elevated until the expansion comes online from us and our competitors. We call that mid-25. But with respect to the Panama Canal issues and even issues in the Red Sea, really I haven’t seen that impact the FOB values too much. The VLGC fleet has done a really good job at repositioning itself. There’s over 380 VLGCs on the water to help mitigate those issues. In fact, as I mentioned earlier, we’ve seen freight come down. So I don’t really see that impacting the FOB values too much from the Canal.

John Mckay: How many VLGCs came on in 2023? How many do we expect in 2024?

Randy Fowler: Yes, I was calling around north of 40 VLGCs came online in 2023. And there’s going to be another 22 or so come online in 2024.

John Mckay: All right. That’s great. I appreciate that. And maybe just one more clarification from earlier. I appreciated the color on the fee floors on processing in the Permian. Just one thing we wanted to try to frame up. I mean, if we look year-over-year, Permian processing volumes are up about half a B, but margins effectively flat. Just curious if you can comment, is that all commodity impact or is there some kind of underlying deflation on the fee side as well?

Randy Fowler: All commodity. All right. Makes sense. That’s it for me. Thanks again.

Operator: Thank you. I would now like to turn the call back over to Randy Burkhalter for any closing remarks.

Randy Burkhalter: Thank you, Josh. Before we close out, I’d like to thank Randy for the kind comments and the offer from EGEMP [ph]. And many thanks to all of you I’ve worked with for the years.

Jim Teague: He’s getting a little emotional. Thank you. Close it out, Libby.

Libby Strait: And I guess with that, we’ll end the call. Thanks to everyone for your participation.

Jim Teague: Thank you. Randy, you’re great.

Operator: Thank you for your participation. You may now disconnect.