Energy Transfer LP (NYSE:ET) Q3 2023 Earnings Call Transcript

Energy Transfer LP (NYSE:ET) Q3 2023 Earnings Call Transcript November 1, 2023

Energy Transfer LP beats earnings expectations. Reported EPS is $0.33, expectations were $0.29.

Operator: Good day, and welcome to the Energy Transfer Third Quarter 2023 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. I would like to turn the call over to Mr. Tom Long, Co-CEO of Energy Transfer. Please go ahead.

Tom Long: Thank you, Operator, and good afternoon everyone. Welcome to the Energy Transfer’s third quarter 2023 earnings call. I’m also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon as well as the slides posted to our Web site. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the quarter ended September 30, 2023, which we expect to file tomorrow November 2.

I’ll also refer to adjusted EBITDA and distributable cash flow or DCF, both of which are non-GAAP financial measures. You’ll find a reconciliation of our non-GAAP financial measures on our Web site. We will start today by going over our financial results for the third quarter of 2023. We generated adjusted EBITDA of $3.5 billion, compared to $3.1 billion for the third quarter of 2022. In our base business, we had strong performance across our operations, including record volumes through our NGL pipelines, fractionators, and NGL and refined products’ terminals, as well as record volumes in our crude segment. In addition, volumes in our intrastate and midstream segments remained near records. DCF attributable to the partners of Energy Transfer as adjusted was $2 billion, compared to $1.6 billion for the third quarter of 2022.

This resulted in excess cash flow after distributions of $1 billion. On October 20, we announced a quarterly cash distribution of $0.3125 per common unit or $1.25 on an annualized basis. This distribution represents an increase from the $0.2650 in the third quarter of 2022. In August, Energy Transfer’s senior unsecured credit rating was upgraded by S&P to BBB with a stable outlook. We are pleased to have this third-party recognition of all the hard work that we have done over the last several years, and as we have placed significant focus on our balance sheet in leverage reduction. As of September 30, 2023, the total available liquidity under our revolving credit facility was approximately $2.12 billion. During the third quarter of 2023, we spent $418 million on organic growth capital.

And in October, we completed the sale of $4 billion of aggregate principal amount of senior notes, and used the proceeds to repay borrowings on our revolving credit facility, and pre-funded 2024 maturities. Now turning to our results by segment for the third quarter, starting with NGL and refined products, adjusted EBITDA was $1.1 billion compared to $634 million for the third quarter of 2022. This was primarily due to strong performances across our transportation, storage, terminal, and fractionation operations. We also saw strong contributions from our optimization of hedged NGL and refined products inventories, where we recorded $107 million in marketing margin compared to a loss of $126 million in the third quarter of last year. NGL transportation volumes on our wholly-owned and joint venture pipelines increased 14% to a record 2.2 million barrels per day, compared to 1.9 million barrels per day for the same period last year.

This increase was primarily due to higher volumes from the Permian region and on our NGL pipelines that delivered into our Nederland Terminal, as well as on the Mariner East pipeline system. Average fractionated volumes increased 9% to a record 1 million barrels per day, compared to 940,000 barrels per day for the same period last year. Total NGL export volumes grew more than 20% over the third quarter of 2022, setting a new partnership record. This was primarily driven by increased international demand for NGLs. Through the first nine months of this year, we loaded more than 47 million barrels of ethane out of Nederland, and approximately 21 million barrels of ethane out of Marcus Hook. In total, we continue to export more NGLs than any other company during the third quarter, and maintained an approximately 20% market share of worldwide NGL exports, as well as nearly 40% of U.S. exports.

For midstream, adjusted EBITDA was $631 million compared to $868 million for the third quarter of 2022. We saw near record throughput again this quarter, which was the result of growth in the majority of our operating regions. The strong volume growth was more than offset by significantly lower natural gas and NGL prices. Gathered gas volumes increased 4% to 19.8 million MMBtus per day, compared to 19.1 MMBtus per day for the same period last year. For our crude oil segment, adjusted EBITDA was $706 million compared to $461 million for the third quarter of 2022. This was primarily due to higher volumes on several of our pipelines, as well as the acquisition of the Lotus assets in May of this year. In addition, G&A expenses decreased $126 million as a result of a one-time charge related to the resolution of a legal matter in the prior period.

Crude oil transportation volumes were a record 5.6 million barrels per day, compared to 4.6 million barrels per day for the same period last year. This was a result of higher volumes on our Texas pipeline systems, the Bakken Pipeline, as well as the acquisition of the Lotus assets in May of this year. In our interstate segment, adjusted EBITDA was $491 million, compared to $409 million in the third quarter of 2022. This increase was primarily due to placing the Gulf Run Pipeline into service in December of 2022, as well as higher contracted volumes and interruptible utilization on several of our wholly-owned and joint venture pipeline. Volumes increased 15% over the same period last year due to the Gulf Run Pipeline being placed into service, as well as higher utilization on many of our interstate pipeline, including Transwestern, Rover, Panhandle and Trunkline.

We continue to fully utilize Zone 1 capacity on Gulf Run, and we are also maximizing deliveries into our Trunkline Pipeline from Zone 2. And for our intrastate segment, adjusted EBITDA was $244 million, compared to $301 million in the third quarter of last year. Benefits from favorable storage optimization and new contracts on our Texas and Haynesville pipelines as well as lower operating expenses were more than offset by decreases resulting from lower spreads across our intrastate pipeline network, and lower natural gas pricing. Now, turning to our acquisition of Crestwood Equity Partners, which we announced in August of this year, as many of you have probably seen, earlier this week, Crestwood unit holders voted to approve the merger between Energy Transfer and Crestwood.

The acquisition is expected to be immediately accretive to DCF per unit upon closing. In addition, this transaction will extend Energy Transfer’s position in the value chain deeper into the Williston and Delaware basins, while also providing entry into the Powder River Basin. These assets are expected to compliment Energy Transfer’s downstream fractionation capacity at Mont Belvieu, as well as its hydrocarbon export capabilities from both our Nederland and Marcus Hook terminals. We also expect benefits within our NGL and refined products and crude oil businesses with the addition of strategically located storage in terminal assets. We now expect the acquisition to close on November 3, and we expect to achieve approximately $40 million in annual cost synergies before additional anticipated benefits from financial and commercial synergies.

Turning to our growth projects and starting with our Nederland and Marcus Hook export terminals, September and October were our best months ever across our NGL export terminals. And these terminals continue to benefit from increased demand, both in the U.S. and as well as from international customers. Earlier this year, we FID’d an expansion to our NGL export capacity at Nederland in order to address the growing demand. We expect this expansion, which is projected to cost approximately $1.25 billion, to add up to 250,000 barrels per day of export capacity. The project is expected to be in service in mid 2025, and will give us flexibility to load various products based upon customer demand. Construction is underway, and we look forward to providing more specifics on this expansion as it progresses.

We also continue to pursue an optimization project at our Marcus Hook Terminal that we project would add incremental ethane refrigeration and storage capacity. At Mont Belvieu, we placed Frac VIII into service in August, which brought our total Mont Belvieu fractionation capacity to over 1.15 million barrels per day. As a result, in October, throughput at our fractionators reached an all-time high. Out in the Delaware Basin, we have placed 200 million cubic foot per day processing plants into service since December of 2022, and we now have a total of eight — 200 million cubic foot per day processing plants operating in the Delaware Basin. Our plant inlet remains near record highs, and we continue to contemplate the necessity and potential timing of adding another processing plant in the Permian Basin while considering any available new capacity that we acquire via the Crestwood acquisition.

Next, an update on our Lake Charles LNG project; we continue to see significant interest in our LNG capacity from U.S. producers and international markets. We are in negotiations with several significant equity partners that are ultimately targeting retaining an interest of approximately 20% for Energy Transfer. These potential equity partners are also interested in substantial volumes of LNG offtake. We are in negotiations to finalize our EPC contract, and we are receiving tremendous support from domestic and international customers, community stakeholders, and other interested constituents who are actively encouraging the Department of Energy to approve our pending export authorization application on an expedited basis. And now for an update on a few other projects on the carbon capture and sequestration front, we are continuing to make progress with CapturePoint.

This project entails the capture of CO2 from our treating plants in north Louisiana and the construction of a pipeline to a sequestration site in central Louisiana. We are continuing to work with Oxy to develop a CCS project in Lake Charles, Louisiana area. This would include the construction of a CO2 pipeline connecting our industrial facilities to Oxy’s proposed sequestration site. On the blue ammonia front, we are working with several companies to evaluate the feasibility of ammonia projects that would include significant natural gas supply opportunities, deep water dock access, and other infrastructure services on existing Energy Transfer property near our Lake Charles and Nederland facilities. Additionally, we are working on CCS projects related to our processing plants and treating facilities in south Texas and west Texas, and we are evaluating other CO2 pipeline projects that would connect CO2 emitters to CO2 sequestration sites in the Houston ship channel corridor.

Finally, we are evaluating the use of some of our existing 250,000 acres of land in Virginia, West Virginia, and Kentucky for wind, solar, forestry, carbon credits, and other uses. The Virginia Department of Energy has spent considerable time and effort evaluating a variety of projects on 65,000 acres located in southwest Virginia. Now, looking at our growth capital spend for the nine months ended September 30, 2023, Energy Transfer spent $1.2 billion on organic growth projects, primarily in the midstream and NGL refined product segments, excluding SUN and USA Compression CapEx. For full-year 2023, we expect growth capital expenditures to come in slightly below our previously announced guidance of $2 billion, including growth capital related to Crestwood.

Looking ahead, we continue to evaluate a number of other potential growth projects that we hope to bring to FID. We expect to provide our 2024 growth capital outlook on our fourth quarter earnings call. However, as we look forward to our potential backlog of high returning growth projects, we continue to expect our long-term annual growth capital run rate to be approximately $2 billion to $3 billion. Now, for adjusted EBITDA guidance, for the full-year 2023, we now expect our adjusted EBITDA to be between $13.5 billion and $13.6 billion, including two months of Crestwood. We continue to see strong volumes and stable cash flows throughout our business segments, with recently completed growth projects contributing several records in the third quarter.

Looking ahead, we are excited to close on the acquisition of Crestwood later this week. We look forward to working with the new Crestwood employees as we integrate these new assets into our Energy Transfer franchise. We believe the combination of these businesses will present strategic commercial opportunities and efficiencies. We expect the newly acquired Crestwood asset as well as the growth projects completed throughout this year to provide additional opportunities and positive momentum for the rest of this year and going into next year. We will continue to pursue strategic optimization and expansion projects that enhance our existing asset base, generate attractive returns, and meet the growing demand for our products and services. Our financial position remain strong, and we remain committed to our targeted annual distribution growth rate, which we will continue to balance with leverage reduction, increasing equity returns, and maintaining sufficient cash flow to pursue growth opportunities.

This concludes our prepared remarks. Operator, please open the line up for our first question.

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Q&A Session

Operator: Thank you. I’ll begin the question-and-answer session. [Operator Instructions] First question will be from Jeremy Tonet of J.P. Morgan. Please go ahead.

Jeremy Tonet: Hi, good afternoon.

Mackie McCrea: Hey, Jeremy.

Jeremy Tonet: Just wanted to start off, if I could, if you could just provide high-level thoughts for us, as the platform sits now after a number of acquisitions and projects, what type of organic growth level do you see innate in your business? What type of EBITDA growth [via base] (ph) business do you see? And also at the same time, how does this impact your capital allocation philosophy? In there’s a somewhat newer slide in the deck there that maybe alludes to buybacks potential there or distribution increases as well. So, just wondering if you could update us on these fronts?

Tom Long: Yes, for sure, Jeremy, and good afternoon to you. Listen, we’ve put out the guidance of that $2 billion to $3 billion a year. And we still have at least a mid-teen-type returns or high-teen-type returns. So, you can see the growth rate from there. We’re going to stay with that 3% to 5% growth rate on the distributions at this time. Clearly, we talk about that at every single board meeting. So, that’s kind of the math on the growth that you can see. Now, remember, we still have the 85%-15% fixed versus floating. Now, it’s moved into more of 90%-10% just because the commodity prices are lower, so that scales around based upon where those prices are, from that standpoint. So, when you factor all that in and then all the other optimization opportunities that we will definitely jump on when those opportunities present themselves, I think you can look at that type of growth rate.

But I will say that we’re going to stay with our normal schedule, meaning that with the fourth quarter results we will update the 2024 EBITDA guidance — adjusted EBITDA guidance with you. And the second party, Jeremy, did you want to just talk about the unitholder buyback, is that the second part of your — the question there?

Jeremy Tonet: Yes, overall capital allocation and thoughts in light of what you talked about for organic opportunities.

Tom Long: Yes. Well, it’s — the capital allocation is real consistent with what we’ve been saying for a while, and which we’re going to continue to focus on the balance sheet. And it’s a great place to be as you start approaching the low end of our 4 to 4.5 times leverage target. So, I think when you continue to look out, you look at all these growth projects, you look at the distribution growth that we’re looking at, that the unitholder buyback clearly remains as a option that we’ll look at. You’re probably going to look at being at the very low end of that range, if not a [three handle] (ph) on it, the upper three, where you could start seeing opportunistically starting to buy back units. But that’s the way that you should probably look at that.

Jeremy Tonet: Got it. That’s helpful there, thanks. And then, just want to shift gears a little bit towards Permian, just wondering if you could provide us thoughts. I think you touched on it a bit in your prepared remarks as far as growth opportunities there. But just wondering how you see the scaling over time, particularly as it relates to the NGL business and opportunities along that value chain? Seemed like the NGL and products business had quite a nice step up this quarter, and just wondering if you could highlight a bit more of what was happening there?

Mackie McCrea: Yes, Jeremy, this is Mackie. What an exciting area. You look at the consolidation that’s going on upstream, a lot of that, of course, is around the bigger deals in the Permian Basin. And as you know and most on this call, nobody is better positioned to capitalize that than Energy Transfer, from every standpoint, from gathering, processing, NGL takeaway, intra-interstate pipeline takeaway, crude takeaway. And so, it all kind of begins upstream with our G&P group and our NGL team working to purchase not only those barrels from our affiliate, but also barrels from others out in that basin. And we couldn’t be more excited and well-positioned to meet the growth there. And it feeds into our partnership revenue stream when you take all that downstream, and then ultimately frac it, and a lot it is, of course, hitting our export markets now. So, what an incredible area of the world that we’ve heavily invested in and we see it paying off for many years to come.

Jeremy Tonet: And if I could just follow up real quick on that, I guess on the other side of the NGL equation, just how much demand do you see materializing? How that impacts pricing for NGLs, do you see the LPGs continuing to price to export or just any broader thoughts on the NGL supply-demand dynamics and impact on NGL pricing?

Mackie McCrea: It’s hard to overexaggerate the ethane and, more importantly, the LPG growth. Assets cannot be built quick enough in the U.S. to meet the international demand or by [indiscernible] PDHs that are being built in Asia, and especially in China. There’s a lot of ethane crackers that are being built. So, you really can’t build quick enough. But we’re being very prudent. We’ve announced our Flexport project that’s under budget, on track. So, we expect to have that in service by the third quarter of ’25. We’re close to fully filling that out. And we’re analyzing another expansion, it would be a much less expensive expansion, and a much less cost per barrel to expand more. So, we’re going to continue to make sure that all of the gas that we’re gathering and processing, that we have a home for all those liquids.

So, we’re looking ahead, and we see significant growth in our NGL business, especially our export business, both on the Gulf Coast and Marcus Hook, once again, for many years to come.

Jeremy Tonet: Got it, makes sense, seems to certainly build momentum for your Panama initiatives there. Thank you for the color. I’ll leave it there.

Mackie McCrea: Thank you.

Operator: Thank you. Next question will be from Spiro Dounis of Citi. Please go ahead.

Spiro Dounis: Thanks, operator. Afternoon, guys. Just want to go back one of Jeremy’s questions actually. And Tom, fully respect that you’re not in a position to provide ’24 guidance yet, but maybe just looking at the S4 filing from Crestwood as we look to 2024. I know it’s not guidance, but some of those pro forma numbers seem to indicate you guys will be approaching $15 billion in EBITDA next year, on a combined basis. And so, pretty meaningful step up from 2023. So, just wondering, qualitatively or however you see fit, could you help us bridge from 2023 to those S4 numbers, what parts of the business could be driving that upside?

Tom Long: Yes. No, listen, it’s great to be talking about a number that has a 15 handle on it. So, let’s start with that. When you look at that S4, remember that those were estimates. We take our estimates very seriously when we file these things, obviously. And we are still in the process of finishing up the 2024 budget numbers, et cetera, which all go into the guidance. And that’s the reason we’ll always wait till that fourth quarter to come out with the very best numbers that we can. But listen, Spiro, we sure hope we hit these numbers. It would be great even if we came out with something more. But let us get through that before we put out any type of official guidance on that. We’re so excited about everything we’re seeing at this stage with closing on the transaction on Friday, it’s going to give us now the opportunity even start digging deeper into the other synergies that we didn’t make in any of the estimates especially the commercial synergies.

So, let us get through the close on Friday and we’re going to be very excited to be able to talk about what the ’24 numbers should look like, but yes what a great place to be able to earnings numbers this size so —

Spiro Dounis: Yes. No, fair enough and do your best to stay patient. One quick follow-up once again going back to capital return, just as we think about the distribution wrote here on the Cadence now that’s become predictable when you talk about the 3% to 5% range. I guess I’m just curious, what would you need to see the flex toward the higher end of that range? Is that a function of getting leverage lowered or is it something else you really focused on?

Tom Long: Well, the leverage is within our targets. So, I wouldn’t want to necessarily guide you toward that 4% to 4.5%. You can already see that we’ve got the one upgrade from S&P like we’ve mentioned. And the other two, have us on the positive outlook, and we’re going to continue to work with them to get those up to that triple the levels. So, I think the other components we always look at is we’re always looking out at the coverage ratio, making sure that we’re staying in a good solid range there but as much as any we’re also looking a lot at the growth opportunities. So, the usual capital allocation debates that you have, any company has here and that’s what we’re going to evaluate. But it’s not a matter of looking any one single point in time it is a matter of looking out with the best crystal ball we have over the next three, four, or five years. So, we try to make decisions here that we stick with without kind of jumping up and down or moving around with.

Spiro Dounis: Got it. I’ll leave it there, Tom. Thanks for your time.

Tom Long: All right. Thank you.

Operator: Thank you. Next question will be from Michael Blum of Wells Fargo. Please go ahead.

Michael Blum: Hey, thanks. Good afternoon, everyone. I wanted to ask on CapEx close in terms of this year just what exactly is driving the reduction there, slight reduction. And then, for next year, if I recall correctly your last update, I know you see your long term run rate I think is to 2 to 3 billion but I think at least as of last update you said, you don’t even have to go in community projects for ’24 or so. Just want to get the latest update on where that stands as well.

Tom Long: Yes, Michael. Good afternoon. You know as far as the first part of your question, I would say that we continue to work on some very, very good projects. Some of that it’s going to be never set a timing, but even with that, I want to be careful using that word because it doesn’t mean that 2024 is necessarily going to go up. That blends straight in to the second part of your question. If you really kind of look at that 2 to 3 billion, you could use $750 million a year that are just kind of those growth capital projects that well connects all the other great projects we have that are good high returning projects that help with the utilization, optimization of our system overall, especially with the M&A that we’ve been so successful on a lot of this projects fall in that category of that $750 million.

I will say that well, some of the stuff that we’ve talked about and I know Mackie’s talked about here is that those who have the other projects that aren’t necessarily the FID, so we can’t say that we’ve got all of that fill in right now by any means the other 2 billion or so from that standpoint we’re continuing to work on them. I think we feel good about a lot of the projects, so once again it’s probably 750 million and then we’ll be talking more about the other projects as we get them to FID the one that we get highlighted and prepare remarks, of course was Flexport, so —

Michael Blum: Got it. Okay, that helps. Thank you. And then, it sounds like a pretty encouraging update on Lake Charles. So, I guess, what I’m wondering is what would be the earliest timeframe from your perspective where you think Lake Charles could actually get the FID and then in service?

Mackie McCrea: Hey, Matt, this is Mackie. Tough question in that, we’ve got a lot of balls in the air, we’ve covered it pretty well with Tom’s remarks, so we’re sending a really good position. We really need to get the DOE to extend the permit. We think they will. As we said, a lot of folks involved behind the scenes trying to make that happen, including other countries, other businesses in other countries, but we’re just keeping our head down pushing. We don’t really have a lot of estimates. We’re hopeful that we’ll have something to the DOE, sometimes kind of mid first quarter we’re pushing, and others are also pushing and to maybe do that sooner, we don’t know. It’s the regulatory agency that we’re working closely with, and I hope to make that happen sooner than later.

But at the meantime, Tom Mason’s team are working hard back over there now, trying to finalize a lot of these contracts and agreements around equity as well as new LNG offtakers. So, it’s hard to kind of predict that, but everything went exceptionally well, in the second quarter could be a possibility, but we’ll see how things go in the next three or four months.

Michael Blum: Great, thank you.

Operator: Thank you. Next question will be from Brian Reynolds of UBS. Please go ahead.

Brian Reynolds: Hi, good morning, everyone. Maybe to follow up on some CapEx questions as it relates to the Permian natural gas egress seems like we could be seeing the last brownfield expansion get contracted here over the near future. But beyond that, seems like we need a larger pipe, which Warrior still exists out there. So, just as it relates to the Warrior Project at this juncture, has the scope or size the project changed or evolved since you started marketing the project a few years ago, just to perhaps meet specific customer needs and to get the project that ultimately FID? Thanks.

Mackie McCrea: Yes, Brian, this is Mackie again. Yes, we actually started really aggressively marketing this first part of this year, but we are pushing hard, and we’ve mentioned we’ve get about 25% already signed up. We’re working on several other shippers that would bring us to about 60% or 65%. But we’re going to be pretty careful on this, we’re very careful, like we always are, we’re going to be prudent, we’re not going to move forward with that on FID until we have a substantial amount of that capacity sold out. And also, it will feed into not only markets that we’re already connected to with our intrastate network, but also, we’ll have a lot of momentum if some of these other LNG projects get to FID. So, we’re kind of like a lot of these big projects working on, they’re just taking time, we see spread other than a few days or weeks where it blows out a little bit, spreads are very tight, there’s not a lot of pain.

Right now, for the most part, we think that’s going to get really difficult as we go in ’24 until the next pipelines built. So, we do think we’ll pick up more momentum and we’re going to push hard and kind of similar to a comments around LNG. We hope to maybe get the FID on Warrior, sometime maybe in the second quarter of next year.

Brian Reynolds: Great, super helpful. And maybe to just touch on the M&A for the year with Crestwood, and Lotus coming into the fold here, can you just maybe talk about how some of these acquisitions have maybe perhaps helped defer some capital. I know Crestwood has some Permian processing capacity and I think you alluded to, and the prepared remarks that some of that excess processing capacity might be able to defer a processing plant a little bit. So, how should we think about processing capacity for ’24, ’25? Do we need to see another new build coming in next year, or could we see some capital get deferred into the following year as it relates to maybe the crude side Lotus or Crestwood on the NGL on processing side? Thanks.

Mackie McCrea: Yes, this is Mackie again. Yes, as you can understand, we haven’t been able to really dig into the Crestwood assets yet. We don’t close officially till Friday, but from a high level we certainly recognize some capacities, they were really in all regions as well from the back in and the powder, as well as the Delaware. We are constantly evaluating when is the next time to kick off the next trial to make sure we meet our obligations that we signed up producers, but clearly we believe that this is going to give us some time to defer that decision. We’re thinking we’re going to make that decision first quarter of next year, whether we’re going to start pick up another plant, that’s probably going to push it back at least three to six months, so we’ll see.

And as we fully are able to analyze and look at these assets and see how they would just fully blend in but we’re pretty confident that a minimum is going to delay building a new pilot at least some period of time.

Brian Reynolds: Great, thanks. I appreciate it. I’ll leave it there and then enjoy the rest of your afternoon. Thanks.

Mackie McCrea: Thank you.

Operator: Thank you. Next question will be from Jean Ann Salisbury of Bernstein. Please go ahead.

Jean Ann Salisbury: Hi. There’s a lot of new NGL pipes coming to the Permian in 2025. I think ET is actually the only main company not doing an expansion. How well-positioned are Lone Star and West Texas Gateway to whether that contractual duration-wise, and does it drive more interest in inorganic opportunities in the basin?

Mackie McCrea: Yes, Jean, this is Mackie again. We have noticed that there’s a lot of pipelines announced here in the last couple of days, but what we try to do as a partnership is not really worry about what others are announcing or what others are building. We kind of focus on what do we need to build to accommodate our customers and to meet the demand growth of those that we’re working with, and we are very well positioned right now. We move about a third of every barrel of NGL that’s produced in the Permian Basin. We have the ability to move 100-plus thousand more barrels. We can add pumps and move probably in the neighborhood of 250,000 more barrels, so we’ve got some kind of dry powder or dry capacity, available capacity we’ll be able to expand on.

So, I think any kind of considerations or determinations from us are probably a year or longer away on even contemplating another pipeline. We’re positioned pretty well to move everything we’ve signed up in addition to more growth that we expect from our G&P business.

Jean Ann Salisbury: Great. That makes sense. To be clear, I’m certainly not pushing you to expand Lone Star, but that’s super helpful. And for your Nederland NGL export expansion, I know that you’re talking to a lot of ethane counterparties, but it seems like you haven’t quite signed the contracts yet. Is there a way to think about it that given how tight LPG export capacity is, it’ll probably start mostly as LPG, and then as your ethane contracts eventually get signed and kicked in, a greater share will become ethane?

Mackie McCrea: Yes, I think I would answer it this way. We are in constant dialogue and negotiations across the board. We have probably at least 140,000 barrels of ethane customers that we’re negotiating with right now, of which some prefer Marcus Hooks on the Gulf Coast. We’ll have the ability to swing the volume between either one. But clearly, LPG is also in high demand. So, we’re — there’s not a shortage of international customers. And we’re very excited, as we’ve said earlier, that we’re not only very well positioned to meet that, but also very well positioned to meet the growth two years from now and beyond. So, we do think space is going to get pretty tight. As you can see by results, we’re moving more volume. We’re hitting records on almost every aspect of our NGL business, including our export, and we’re seeing the margins widen.

We think we’ll see that over the next couple of years, and then we’ll have new contracts lined up to come online on our Flex port. So, we’re pretty excited. We got in this export business a little later than most of our competitors, certainly our biggest competitor. We’ve kind of gone from nowhere to the leading exporter in the world, and we’re proud of that. Proud of our commercial team that’s done all these deals. Proud of our E&C team who builds these assets so quickly, proud of our operating team led by Greg Mcilwain, who runs these systems efficiently and reliably, and more importantly, safely. So, we are very proud of our team and what we’ve done over the last five or six years to kind of start from nowhere and grow to where we’re at today, and we have such a bright future on the assets that we are building now and the contracts that we have in place.

Jean Ann Salisbury: Great, I’ll leave it there. Thank you.

Operator: Thank you. Next question will be from John Mackay of Goldman Sachs. Please go ahead.

John Mackay: Hey, everyone. Thanks for the time. Maybe just taking that last piece, I mean, talking about exports probably being the tightest part of the value chain for you right now, at least that’s what we’re picking up on. But I guess if you’re looking across the kind of broader ET and kind of ET combined Crestwood footprint right now, where else are you seeing relative tightness and a call on the market, either you guys or others, to add incremental capacity? Is it the Haynesville? Is it more on processing in the Permian, just curious your thoughts overall, if we’re looking maybe beyond export?

Tom Long: Yes. Let me just hit every region real quickly to kind of address, I hope, your question. And so, you start in the northeast, we’re positioned incredibly well. On any kind of product growth up there, whether it’s ethane or LPG, we are kind of the only outlet with our mariner franchise. So, we call it dry powder or available capacity, whatever you want to call it, we are ready to capture any kind of growth up there. And then, as you come further south, we mentioned that we’ve got the ability to grow our transport volumes from the Permian Basin fairly significantly. We’re expanding our Flex port fairly significantly. And we haven’t really hit on this on this call, but there is a lot of gas in north Louisiana. Yes, it’s slowed down a little bit with gas prices here the last two or three months.

We think it’s going to pick back up as prices have improved and will continue to improve. There’s enormous reserves there. But on top of that, we have multiple intrastate and interstate pipelines that feed into east Texas and north Louisiana. And so, we’re very optimistic on our Gulf Run expansion. We can add compression and add a Bcf a day, but we think it’s much more likely that we will sign up enough to loop our existing Gulf Run Zone 2 pipeline, especially aligned with LNG, if we get that FID. But we see that as certainly a huge growth area for us on a large pipeline project somewhere in the future, along with what we’ve already talked about, our Warrior expert project and other areas. So, depending on where the area is, we’re either situated very well to grow with next no capital, or we have such an excellent position to aggregate volumes to support a project like Gulf Run, an expansion project like Gulf Run.

John Mackay: All right, that’s clear. Thank you. Maybe just following up, if we’re thinking about ’23 guidance overall, can you just maybe a quick breakdown of how much of the step-up was Crestwood versus kind of underlying business outperformance? And maybe if you’re touching on the Gulf Run contributions third quarter interstate was particularly strong, or third quarter gas overall was pretty strong, particularly for kind of a shoulder season. Is this a clean new run rate from here, or are there any kind of one-offs in there? Thanks.

Mackie McCrea: Yes, no, listen, I think the best way to look at that as far as the guidance goes in the split between the two is the guidance we had coming into this quarter that we provided in the second quarter was 13.1 billion to 13.4 billion, as you know. As you really looked at the new numbers we gave, you can probably say that the existing business was right at the top end of that range, and the rest of it would be Crestwood, but Crestwood would be net transaction cost. So, that’s what we’re currently expecting right now. Still maybe some moving pieces as we get into the fourth quarter, but we feel pretty good about the 13.5 to 13.6.

John Mackay: All right, that’s clear. I appreciate it.

Operator: Thank you. Next question will be from Neel Mitra of Bank of America. Please go ahead.

Neel Mitra: Hi, good afternoon. Thanks for taking my questions. Firstly, it seems that Cushing inventories are extremely low right now, so wanted to understand how your Centurion flows and your overall Lotus acquisition was able to materialize on this dynamic in the third quarter?

Mackie McCrea: Yes, you bet. This is Mackie again. Yes, I have to do a shout out to Chris Hefty and his team and what they’ve done over the last two years has just been phenomenal as you look at Enable and kind of what it’s done over the last year and a half and the synergies that we’ve found and the same with WEX. And Lotus is the same thing. We continue to look at significant commercial synergies around blending. As we have made an announcement, we are looping pipes so that we can move more volume to benefit when the spread blows out between Midland and Cushing. So, we’re slowly positioning ourselves to become a much bigger player to be able to move volumes between the Cushing and Midland areas, as well as, of course, to the Gulf Coast, to our Houston and Nederland Terminal.

And I think, likewise, we’re going to see with Crestwood a lot of the same synergies. So, we’re pretty excited about our ability to buy these assets at the values we’re able to buy at. They’re great standalone companies and assets. And then, once we blend them in, like your question with Lotus, we’re finding significant synergies that we didn’t recognize as we were pursuing these acquisitions.

Neel Mitra: Got it. And then, my second question, you’ve had a lot of success building Permian to Mexico natural gas pipelines and it seems like the utilizations on Comanche Trail and Trans-Pecos are picking up and you have a competitor looking to build a pipeline to the border as well. With some of the West Coast LNG demand and increased industrial demand in West Mexico, are you seeing any appetite for pipeline expansions down to the border or possibly participating in a new project to move gas to Mexico?

Mackie McCrea: This is Mackie again. No, we’re not pursuing anything right now. As you mentioned, we are ramping up our two pipelines out in West Texas that deliver to Mexico. We still have quite a bit of capacity to fill up to fully utilize those pipelines. We have some pipelines in South Texas that we deliver either directly into Mexico or into other larger diameter pipelines, but no, we don’t have anything on the drawing board. Yes, we are aware of some proposed pipelines out of the WAHA area and heading west, but we aren’t involved in any of those projects at this time.

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

Operator: Thank you. Final question will come from Gabe Moreen of Mizuho. Please go ahead.

Gabe Moreen: As sort of the uplift in pricing on your interstate gas pipelines and storage, it seems like if I’m reading it right, some of that uplift may be accelerating. Can you just talk about sort of how you feel your position, rate case outcomes aside, and to what extent that’s still going to be winded to your backs going forward into 2024?

Mackie McCrea: Hey, Gabe, this is Mackie, and I apologize. We started hearing about halfway through your question. Sorry.

Gabe Moreen: Okay. Can you hear me now, Mackie?

Mackie McCrea: Yes.

Gabe Moreen: Okay, great. I was just going to say to what extent repricing your interstate gas pipeline and storage capacity is going to be winded to your backs in 2024? It seems like some of that’s accelerating as we progress through 2023.

Mackie McCrea: Yes, years ago this wasn’t fun to talk about. It is now. When you look at the value, for example, on the MEP or on Tiger or on Gulf Run or even on SESH, we’re seeing growing, growing demand on all of those assets. GW, I mean, just pick an asset, and most of what we’re doing right now is either at tariff or close to tariff. The demand is there. A lot of the gas throughout this country is trying to find its way to the Gulf Coast. We’re very well-positioned to benefit from that with all the pipelines I just mentioned and others. So, we don’t really, unlike years past, we might have had some concern when contracts were terminating of what we could do with that available capacity. I mean, Tiger is a great example. I mean, Tiger was about half empty with spreads down to $0.05 or $0.06, and now we’re running at full at much bigger spread.

And so, we’re pretty excited about any available capacity. Once it comes out from the contract, we think worst case we’ll roll it over it somewhere, if not higher rates than we already are at unless we’re already at tariff.

Gabe Moreen: Thanks, Mike.

Operator: Thank you. That concludes our question-and-answer session. I’d like to turn to call back over to Mr. Tom Long for closing remarks.

Tom Long: Once again, I thank all of you for joining us today. We greatly appreciate all your support. And we look forward to talking to you in the near future.

Operator: Thank you. That concludes our conference today. Thank you for attending. You may now disconnect.