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Presentation

Operator: Good day, and welcome to the Energy Transfer Fourth Quarter and Full Year 2022 Earnings Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Tom Long, Co-CEO. Please go ahead.

Tom Long: Thank you, operator, and good afternoon everyone and welcome to the Energy Transfer fourth quarter 2022 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 website. 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-K for the full year ended December 31, 2022, which we expect to file this Friday, February 17.

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 measures on our website. I’d like to start today by going over our financial results. For full year 2022, we generated adjusted EBITDA of $13.1 billion, which reflects continued growth over 2021 and is a partnership record. DCF attributable to the partners of Energy Transfer, as adjusted, was $7.4 billion, which resulted in excess cash flow after distributions of approximately $4.4 billion. On an incurred basis, we had excess DCF of approximately $2.4 billion, after distributions of $3.1 billion and growth capital of approximately $1.9 billion. Operationally, we moved record volumes across all of our segments for the year ended 2022, which included record volumes on our legacy midstream, intrastate and NGL transport systems as well as through our fractionators at Mont Belvieu.

In addition, we exported a record amount of NGLs out of our Nederland Terminal in 2022, and we expect our exports to continue to grow into 2023. Looking at our fourth quarter 2022 results, we were pleased to report another strong quarter during which we generated consolidated adjusted EBITDA of $3.4 billion, which was up more than 20% compared to the fourth quarter of 2021. DCF attributable to the partners, as adjusted, was $1.9 billion compared to $1.6 billion for the fourth quarter of 2021. This resulted in excess cash flow after distributions of approximately $965 million. On an incurred basis, we had excess DCF of approximately $360 million after distributions of $945 million and growth capital of approximately $605 million. On January 25, we announced a quarterly cash distribution of $0.305 per common unit or $1.22 on an annualized basis.

This distribution represents a 75% increase over the fourth quarter of 2021 and is a 15% increase over the third quarter of 2022. With this recent increase, we have now restored our distribution level to where it was in the first half of 2020. We greatly appreciate our equity investors, who have supported us over the last two plus years as we have diligently worked to lower our leverage and improve the financial stability of the partnership. This will allow us to better capitalize on opportunities that will lead to the future success for the partnership and all of our stakeholders. Future distribution increases will be evaluated on an annual basis while balancing energy transfers, leverage targets, growth opportunities and potential unit buybacks.

As of December 31, 2022, the total available liquidity under our revolving credit facilities was approximately $4.2 billion. And while we are not speaking directly for the rating agencies, based on our internal calculations, we are now within the 4 to 4.5 target leverage ratio range based on our calculations of the rating agencies leverage ratios. Now turning to our results by segment for the fourth quarter, I’ll start with NGL and refined products. Adjusted EBITDA was $928 million compared to $739 million for the same period last year. This change was primarily due to higher transportation, fractionation and terminal services margins and the recognition of gains on hedged NGL inventory. NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record 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 and Eagle Ford regions as well as on our NGL pipelines that deliver into our Nederland Terminal. And our average fractionated volumes set a new partnership record, averaging 962,000 barrels per day compared to 895,000 barrels per day for the fourth quarter of 2021. In fact, during the fourth quarter of 2022, single day fractionation throughput at Mont Belvieu reached more than 1 million barrels for the first time in our partnership’s history. NGL export volumes significantly exceeded fourth quarter and full year 2021 exports, driven by record ethane and LPG exports out of our Nederland Terminal. This was primarily driven by the second tranche of satellites contract going into effect on July 1, which doubled the volume commitments from the initial term.

In 2022, we loaded nearly 43 million barrels of ethane out of Nederland. And for full year 2023, we expect to load more than 60 million barrels. In total, we continue to export more NGLs than any other company or country with our percentage of worldwide NGL exports remaining at approximately 20% of the world market. For midstream, adjusted EBITDA was $632 million compared to $547 million for the fourth quarter of 2021. This was primarily due to increased throughput and all of our operating regions as well as the acquisition of the Enable assets in December of 2021 and the Woodford Express assets in September of 2022. Gathered gas volumes were at a record 19.4 million MMBtus per day compared to 14.8 million MMBtus per day for the same period last year.

Excluding Enable and Woodford Express, gathered gas volumes on our legacy assets were up 8% over the same period last year. For our crude oil segment, adjusted EBITDA was $571 million compared to $533 million for the same period last year. These results were driven by improved performance on our Texas crude pipeline system, increased throughput at our Gulf Coast terminals, stronger refinery utilization and higher export demand as well as the addition of the Enable assets in December of 2021. Crude oil transportation volumes increased to 4.3 million barrels per day compared to 3.8 million barrels per day for the same period last year. This was driven by higher volumes on our Texas pipeline systems and on the Bayou Bridge pipeline, the addition of the Enable assets as well as placing the Ted Collins Link and Cushing South pipelines into service.

In our interstate segment, adjusted EBITDA was $494 million compared to $397 million for the fourth quarter of 2021. This was primarily due to increased transportation revenue related to higher contracted volumes and rates on several of our pipelines as well as the addition of the Enable interstate assets. Volumes increased 33% over the same period last year and utilization on many of our interstate pipelines, including Trunkline, Tiger, FGT, Southeast Supply Header and Rover remains high. And for our intrastate segment, adjusted EBITDA was $433 million compared to $274 million in the fourth quarter of last year. This was primarily due to higher pipeline and storage optimization opportunities, higher fees on assets in the Haynesville as well as the addition of the Enable assets.

Utilization of our HPL System remains strong due to the increased demand for our gas takeaway and our Rigs pipeline system continues to flow at or near capacity due to increased activity in the Haynesville. Now looking at recent developments on our ongoing growth projects. I’ll start with an update on our Lake Charles LNG project. Global demand for LNG remained strong as energy security has emerged as a key theme for LNG. In addition, U.S. natural gas producers have shown increased interest in committing a portion of their production to long-term sales arrangements at European and Asian natural gas or LNG index prices. We view these two factors as key drivers towards securing additional long-term LNG offtake agreements. The LNG market along the Gulf Coast is currently extremely competitive.

Given this level of competition, it is taking us longer to reach FID than originally expected, but we are optimistic that we will bring this project to FID. We continue making progress on all aspects of the project and are working hard to sign up more customers, and we’ll share additional information as it becomes available. Turning to our Nederland and Marcus Hook export terminals, in November 2022 we completed dredging at Marcus Hook to increase the depth at one of our docks to 42 feet, which will allow us to fully load VLECs at this dock going forward. In addition, we recently completed a FEED study on a potential expansion project at our Nederland Terminal, which would provide us with additional NGL export capacity. We are currently evaluating next steps and hope to provide more details on this opportunity in the near future.

We also expect to approve an optimization project at Marcus Hook that would add incremental ethane refrigeration and storage capacity. NGL demand, both in the U.S. as well as from overseas customers continues to increase. We are firm believers that there will be significant growth in international demand for many years to come. Next, construction of our Frac VIII continues as scheduled, and we expect it to be in service in the third quarter of 2023. This addition will bring our total Mont Belvieu fractionation capacity to approximately 1.15 million barrels per day. Also during the fourth quarter, we brought a new storage cavern online at Mont Belvieu with a capacity of approximately 3 million barrels, which supports our ongoing purity growth at the fracs as well as growth at our docks in Nederland.

This brings our total underground NGL storage capacity at Mont Belvieu to approximately 60 million barrels. Out in the Permian, in December, we placed our 200 million cubic foot per day Grey Wolf processing plant into service, and it is already ramping up more quickly than anticipated. As a reminder, this plant, which is located in the Delaware Basin, is supported by new commitments and growth from existing customer contracts. Construction continues on the Bear plant, our eighth 200 million cubic foot per day processing plant in the Delaware Basin. This plant remains on schedule to be in service in the second quarter of 2023. In addition, we continue to evaluate the necessity and potential timing of adding another processing plant in the region.

Regarding Permian takeaway, we also recently completed modernization and debottlenecking work on our Oasis pipeline, which added at least an incremental 60,000 Mcf per day of takeaway capacity out of the Permian Basin. We also placed the Gulf Run pipeline into service in December. Gulf Run, which is a 42-inch interstate natural gas pipeline with 1.65 Bcf per day of capacity, provides natural gas transportation between our upstream pipeline network and from the Haynesville Shale for delivery to the Gulf Coast connecting some of the most prolific natural gas producing regions in the U.S. with the LNG export market as well as many markets along the Gulf Coast. It is backed by a 20-year commitment for 1.1 Bcf per day from Golden Pass LNG, and we recently concluded a non-binding open season on Gulf Run due to growing producer demand.

We were pleased with the results of the open season and customer discussions are ongoing, which will likely necessitate additional facilities beyond the initial design of 1.65 Bcf per day. We are already utilizing a significant portion of Zone 1 capacity on Gulf Run, and we have added additional customer commitments through Zone 2, which is being delivered into our Trunkline pipeline. In addition to these ongoing projects, we continue to evaluate and have customer discussions regarding a number of other projects that are over the long-term could provide strong returns and significant upside to our business. We remain optimistic that we can bring these projects to FID and look forward to sharing any significant updates on these potential projects at the appropriate timing.

On the alternative energy front, we continue to make progress on our carbon capture and storage project with CapturePoint. That is related to our North Louisiana processing plants. The Class VI permit for the sequestration side was filed by CapturePoint with the EPA in June of 2022. We also recently executed a letter of intent with Oxy related to Oxy’s Magnolia hub in Allen Parish, Louisiana, north of the Lake Charles Industrial Complex. Pursuant to the letter of intent, Energy Transfer and Oxy are working together to obtain long-term commitments of CO2 from the industrial customers in the Lake Charles, Louisiana area. If this project reaches FID, Energy Transfer would construct a CO2 pipeline to connect the customers to Oxy’s sequestration site in Allen Parish, Louisiana.

Oxy filed applications with the EPA for 2 Class 6 injection wells in 2021. Oxy is a leader in the CCS sector, and we’re pleased to be working with them to make this project successful. In addition, we’re evaluating numerous opportunities to capture and either utilize or store the CO2 across our systems. Now looking at our growth capital spend for the full year of December 31, 2022. Energy Transfer spent approximately $1.9 billion on organic growth projects, primarily in the midstream, interstate and NGL and refined products segments, excluding SUN and USA Compression CapEx. For full year 2023, we expect growth capital expenditures to be between $1.6 billion and $1.8 billion, which will be spent primarily in the midstream NGL and refined products and interstate segments.

This capital includes projects that will address growing demand like Frac VIII at Mont Belvieu, the Bear processing plant in the Permian Basin, compression and optimization projects on existing pipelines, new treating capacity in the Haynesville, additional gathering and compression build-out in the Permian, improved efficiencies and emission reduction work, as well as preliminary spend related to carbon capture projects. In addition, this number does include a small amount of capital that was pushed from 2022 into 2023 due to project in-service timing needs. A significant amount of our 2023 capital spend is comprised of projects that are expected to be online and contributing cash flow before the end of 2023 at very attractive returns. Now for our 2023 adjusted EBITDA guidance, given the continued domestic and international demand for our products and services, the ability of our base business to operate through various market cycles as well as our market outlook for the year, we expect our adjusted EBITDA to be between $12.9 billion and $13.3 billion.

Our business continues to provide stable cash flows and opportunities for optimization and expansion. And in 2023, we expect utilization in all of our core segments to increase. With the current forward curve for commodity prices and spreads, our guidance does not assume the same upside benefits from pricing and spreads that we experienced in 2022. As a result of our commitment to strengthening our balance sheet throughout 2022, we entered 2023 in a much stronger financial position, and we expect to maintain our leverage target range of 4 to 4.5 times. We will continue to place emphasis on strategically allocated cash flow in a manner that best positions us to further improve our financial flexibility and leverage, invest in high-returning growth projects and return value to unitholders.

We remain bullish about the future of our industry and the growing worldwide demand for crude oil, natural gas and natural gas liquids and refined products. As we look for additional ways to address existing and new demand for our products, we will continue to pursue strategic growth projects that enhance our existing asset base and generate attractive returns as part of our capital allocation strategy. This concludes our prepared remarks. Operator, please open the line, up for our first question.

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Operator: We will now begin the question-and-answer session The first question comes from Jeremy Tonet with JPMorgan. Please go ahead.

Tom Long: Jeremy you are being muted.

Jeremy Tonet: Pardon me.

Operator: Jeremy your line is now live.

Jeremy Tonet: Hi.

Tom Long: Hi, good afternoon.

Jeremy Tonet: That’s helpful to be unmuted. Thank you. Maybe just kind of start off here, I want to go to the Permian and kind of get high-level thoughts as you see it with regards to basin logistic needs and Permian gas takeaway has been in focus. And we’ve seen volatility in Waha prices. I’m just wondering what that means for ET this year, what’s kind of embedded to the guidance. But more so, I guess, longer term, how you see basin egress evolving and future opportunities for ET along these lines, particularly as it relates to possible timing for Warrior development?

Mackie McCrea: Jeremy, this is Mackie. Yes, when we think about the Permian Basin, probably one of the most prolific basins in the world. We love looking at the maps because, as you know, we have inter and intra state pipelines come in every direction and out of that area including three NGL pipelines and then, of course, some significant pipeline capacity across the state. As you know, everybody knows on this call, there has been a significant growth in natural gas volumes out of the Permian. There has been expansions. There continue to be compression expansions on the 42-inch getting built. And then about this time last year, we kicked off Warrior and started getting some momentum and we continue to have momentum. So we don’t know when the next project will be announced coming out of the Permian Basin, we do believe it will be ours when it happens.

Just a quick update on those volumes. We have contracted about 25% to 30% of what we need to get to FID on Warrior. We’re talking to another at least 50% to 60% of what would be needed. It is a slow process based on what you just said, when you’ve got negative spreads where Waha has been higher than Katie and or you’ve got a few cents spread. It’s hard to get deals done. But certainly, over the next three to four years on top of what’s already been expanded and built, there will need to be another line and if there is one, we do believe it will be ours.

Jeremy Tonet: Got it. That’s really helpful. And then kind of looking at the other side gas Downstream, significant LNG development coming in the Gulf Coast, particularly in Louisiana over the balance of the decade here and it seems like you guys have quite the pipeline positioning in Louisiana there to support that. But just wondering, it seems like these exporters are looking for diversity of supply beyond the Haynesville and also maybe kind of more connectivity into Texas and into the Permian. Just wondering how you see that unfolding over time and what opportunities that could present to ET?

Mackie McCrea: Yes, just a common theme I’d say throughout this on every question. I think just asked, golly look at a pipeline map and look at what energy transport can do on moving volumes to Gulf Coast, especially to Louisiana, after buying we now have three €“ I’m sorry, four 42-inch pipes in North Louisiana. We have connections from Carthage to Perryville and out to Gulf Run we connect almost to the Gulf Coast and other pipelines. So we’re so well positioned both to feed our own LNG project, should we get that to FID, but regardless even our results, we’re seeing volumes find their way from North Marcellus to and Trunkline and through all of our pipeline system to the Gulf Coast already to see the growing demand for LNG. So we’re so well positioned and pretty excited about the full utilization and even expansions of our systems across the South.

Jeremy Tonet: Got it. That’s really helpful. I’ll leave it there, thanks.

Mackie McCrea: Thank you.

Operator: Our next question comes from Brian Reynolds with UBS. Please go ahead.

Brian Reynolds: Hi, good afternoon everyone. Maybe to start off on just the guidance, it implies kind of limited growth year-over-year based off of the presentation, where you put out some puts and takes with commodity declines offset by volume growth. So I was just curious if you could perhaps just unpack the base assumptions maybe around the commodity deck and then as well, just a high-level view on Permian and Haynesville growth to help us square the guidance. Thanks.

Tom Long: Hi, you bet, Brian. This is Tom Long. Really, when you look at 2022, obviously, it was a great year for us again with the results that were given to you right now. But when you really look at the volumes, if you remember, we started off the year with our guidance of about $11.8 billion to $12.2 billion, when you looked at it. And then we saw the prices start spiking up through the year with the conflict that occurred over in Ukraine. But likewise, when we got to the first quarter and our first quarter call, we talked about the optimization opportunities that our com ops group were able to achieve. And we said that was probably to $225 million to $250 million. So it gave us a real shot in the arm as well as in the prices.

And as we continue through the year, if you were comparing 2022 results, with what we’ve got in the guidance for 2023, you’re going to have about probably $400 million to $600 million that was coming just from the, what we call the price and the spreads that we saw. So the assumptions €“ the last part of your question, I think, as far as the assumptions go, we’re pretty much using the forward curve. We’re staying kind of down the middle of the fairway. And that’s kind of the walk forward from 2022 to 2023. But you can see, once again, between the numbers that I gave you there for the first quarter and then the pricing for the full year, hopefully, that gives you a little bit of a bridge of where we are. So we’re very excited with what we’ve been able to achieve with the various projects or various assets that are coming online that we continue to see, as well as the volumes.

So we’re obviously very excited to be able to put numbers of the $12.9 billion to $13.3 billion to you.

Brian Reynolds: Great. Appreciate the feedback. Maybe as my follow-up, I appreciate some of the color on the prepared remarks around Lake Charles LNG just maybe taking a little bit longer than expected. Curious if you could just talk a little bit more about, one, just the equity interest in the projects; two, to spa contracting. It seems like, broadly speaking, it’s very hard to term out LNG in any environment. And then lastly, just any update on the EPC provider. I guess in the greater context, is there just a focus on returns for this project versus, I guess, just pursuing this project just to ultimately bring value to the downstream system? Thanks.

Mackie McCrea: You bet, Brian. This is Mackie again. And you hit the nail on the head, it has taken us longer than we had anticipated. It is extremely competitive out there. The need for natural gas for many years to come is out there. There’s international customers throughout that are looking for supplies, especially reliable, cheaper gas supplies in the U.S., but it’s extremely competitive. And we are disappointed we’re not further along in signing up customers. But even as we speak, we have Tom Mason and his team are actually over there for on a two-week trip meeting with customers, some of which were down the road quite a ways on consummating new deals, which will certainly make public. So we’re working hard on that front.

We’ve got our work cut out for us. We still believe we have the best project for a number of reasons, especially with the ability to feed it from so many different basins. So we’re still very excited about it. On the EPC front, we have received some of our costs in over the next 60 to 90 days, we’re going to fine-tune those. We’re going to put kind of €“ to get a better understanding about any risk and mitigation of those risks. But really, our focus right now is on getting the customers. And we’ve got a great effort on that, and we still remain optimistic that we will get it to FID.

Brian Reynolds: Great. Appreciate the color. I’ll leave it there. Enjoy your evening.

Mackie McCrea: Sure.

Operator: Our next question comes from Michael Blum with Wells Fargo. Please go ahead.

Michael Blum: Thanks. Good afternoon, everyone. So maybe just want to talk about €“ start with capital allocation for 2023. Tom, in your prepared remarks, you seem to indicate that deleveraging, is it continues to be a priority? So I’m wondering if you’re thinking that you want to push towards the lower end of that 4 to 4.5 leverage target? And then how should we think about dividend growth rate in 2023? And then anything on buybacks? Thanks.

Tom Long: Yes, good afternoon Michael. I’ll start with this. When you really look at it, we have been just absolutely just more than pleased, if you will, that we’ve been able to get the distributions back up to about 2022. Really, when you look at a lot of the distribution cuts that were made back that year, we’re very proud with what we’ve been able to achieve. I think we’re probably one of the few that we’re able to get it back up to the precut levels. So when you really look at the allocation, we’re going to €“ you worded it well. We’re going to continue to probably keep a lot of financial flexibility and some dry powder, which means we’ll keep it at the lower end of that 4 to 4.5, so we’ll continue to focus on bringing that down as far as the leverage ratio.

When you really look at the capital projects that we’ve talked about here, I know we start off with this CapEx number of where we are, we’re going to continue to look at acquisitions. And so when you focus on that and you see where we kind of €“ what we did in 2022 with some of the smaller type acquisitions, the $1.6 billion to $1.8 billion does not include anything that might come along only on the consolidation front. So we’re going to allocate dollars to the continued growth of the company. And then third, we’re going to look at returning capital to the unitholders, and that will be evaluating the distribution levels. Like I mentioned in the kind of the prepared remarks that we’re going to be looking at that distribution more on an annual type basis.

There’s not a whole lot of other guidance at this point that we’re going to provide at this time. But we’re going to continue to look at possible unit buybacks. So we put both of those in that same returning capital to the unitholders. But that’s the way, I think, in summary, answering your question.

Michael Blum: Okay. Great. Thanks for that. And then also I just wanted to ask you about your gas storage business. I wonder if you can just talk generally about the trends you’re seeing in storage rates and then just remind us kind of what’s your average length of your storage contracts and how much merchant capacity you have? Thanks.

Mackie McCrea: Hi Mike, this is Mackie. Yes, we’ve got a total of about 150 Bcf throughout the country of storage. So average kind of storage facility is a little bit different. We have been able to consummate over the past five or six months, some storage-related deals with transportation to some power plants in Texas as well as in Oklahoma. What happened with Yuri kind of woke some folks up, and that’s what we were kind of advertising for a while. If you don’t lock in demand charge or reserve space from storage and for pipeline capacity, you could be in trouble when times are tight. So we have been successful. Some of those deals are three to five years. A lot of our storage contracts may be as low as a year or two. I won’t get into a lot of specifics for competitive reasons, but we’ve got a wide variety of customers and a wide drive needs.

And then, of course, whatever the merchant capacity is available we’ve got an optimization team that capitalizes on that value when those opportunities arise.

Michael Blum: All right, thanks very much.

Mackie McCrea: Thank you.

Operator: Our next question comes from Marc Solecitto with Barclays. Please go ahead.

Marc Solecitto: Thanks. Good afternoon. Maybe just to start, wondering if you could share your latest thoughts on a potential C-Corp currency? And if that something that could be on the table here in 2023.

Tom Long: Yes, Mark, this is Tom Long. We do have a team that’s working on that. I guess the way I would tell you is that we are spending quite a bit of time on evaluating that. And we feel pretty good about probably 2023. We’re going to be a little bit careful about putting in guidance out there right now. But it’s something that we still think makes a lot of sense and are spending a lot of time. But can’t really guide you any closer than that.

Marc Solecitto: No, I appreciate that. And then going back to when you announced the Enable transaction, I believe at the time you referenced the opportunity to integrate slightly some of those G&P assets with your Gulf Coast frac assets over time. So just wondering if you could give us an update on that. Are we starting to see that here in 2023? Is that still a little bit longer dated?

Mackie McCrea: Hey Mark, this is Mackie. Let me kind of break it down a little bit. With the Enable assets, some of the things we have been able to do, for example, out in the Panhandle in Western Oklahoma, we’ve been able to actually shut down a couple of smaller plants and move those at much higher margins, saving a lot of operating costs with better returns. So there has been some synergies there. There’s also been synergies on connecting some of the enabled pipelines, for example, North Louisiana to our Carthage facilities, some of their interstate pipelines. And then as far as connecting the dots between Oklahoma and the Gulf Coast, yes, we will be having the vast majority of the liquids that are the tailgate of Enable’s cryo will be delivered to our fractionators when those contracts run out in a couple of years.

Marc Solecitto: Got it. I appreciate the time.

Mackie McCrea: Thank you.

Operator: Our next question comes from John Mackay with Goldman Sachs. Please go ahead.

John Mackay: Hey thanks Tom, I appreciate it. Maybe I just wanted to talk about the Haynesville a little bit. I know you’ve touched on it in a couple of other questions so far. But be curious to hear your view on just what the basin looks like given where gas prices have gone, kind of what you’re thinking for Basin growth overall and what that can mean for maybe your gathering footprint specifically, and maybe for the opportunity to get more contracts at Gulf Run?

Mackie McCrea: Hey, John, this is Mackie again. Yes, I did mention a minute ago. We have three intrastate 42-inch pipes. One 42-inch intrastate multiple other pipes, we connect Carthage to Perryville. We now are connected from the Haynesville down to our trunk plant system in Golden Pass. So we’re so well positioned. The reserves are there. Do we have a strong opinion of where the gas price will go below $2 where they’ll keep drilling? We don’t know, but we do know that these wells come on at $50,000 or $60,000 a day. You don’t need a real high gas price to justify drilling those. We haven’t had any huge indications of slowdown. In fact, we’re adding significant treating capacity in North Louisiana. So we believe that the reserves for there are going to grow and much of that volume is going to hit our system.

John Mackay: All right. That’s helpful. Maybe just a follow-up on the CapEx guide. Talked a little bit about potential NGL export debottlenecking projects. Just it wasn’t clear. Is that in the current growth guide? Or is that something we’d see more in 2024, and then more broadly I’m not trying to pin you down on the 2024 number. But is the 2023 CapEx level kind of a reasonable run rate to think about now that a lot of the bigger projects have rolled off?

Mackie McCrea: I’ll start this and then maybe Tom can follow-up. But yes, our Flex port expansion and our potential expansion up at Marcus Hook, those are not in our guidance numbers. However, as we alluded to on the last call and have been for a while, we will expand, it’s going to happen. You wouldn’t be surprised if we announce something by the next call. we have the volumes to justify it. We’re just trying to make the most prudent decision on do we expand Nederland first, do we expand Marcus Hook first or with some of the successes and the negotiations going on? Do we expand both. So that is a very positive side of our business. We’ve been growing over the last five or six years enormously. We with the world has an insatiable desire for NGLs. We think that’s going to grow for many, many years to come and we believe we’ll play a bigger role than anybody else in the industry on meeting that demand.

So we do anticipate making some announcements in the fairly near future on expanding our export capacity.

Tom Long: And John, I’m going to go ahead and jump in here, too. This is Tom Long. As far as the second part of your question there. As you can see, we gave the guidance of $1.6 billion to $1.8 billion for a company our size, you can probably also appreciate that we’ve got a lot of opportunities. So that’s really the number that we’re starting the year here based upon projects we’ve identified, but we’ve talked about these other projects, and you stated that correctly that that’s €“ the other projects that have not got to FID, we’re not including in this. So as those come along through the year, we will talk more about those, which could impact that number. But I think the other thing to make sure you stay focused on from a CapEx standpoint is that it doesn’t include some of the small M&A type opportunities.

So a lot of this growth capital are projects right now that are pretty short bills. We get good returns, very good returns on them, and at the same time we get good capital returns on them in a shorter period of time, let’s say, less than 12 months. So we’re going to continue to focus on doing the things that need to strengthen the company and continue to grow it. And so you’ll expect much more to come with the CapEx that we’re looking at, so.

Mackie McCrea: Hey, John, this is Mackie. Add one more thing, too. Keep in mind, we have built a franchise up there. We’re the only company that can transport growth of LPG. We’re the only company that can transport through pipelines growth and ethane we have the ability to increase our ethane capacity by 3 times of what we’re moving today. We can more than double our LPG capacity. So when we’re talking about expansion at Marcus Hook, we’re going to have a decent good rate of return on those €“ that expansion capital and then very little capital for same pump stations to utilize existing capacity that’s already in the ground.

John Mackay: That great. Really clear. Appreciate all the color.

Operator: Our next question comes from Jean Ann Salisbury with Bernstein. Please go ahead.

Jean Ann Salisbury: Hi. How much do you anticipate that both run can physically flow until Golden Pass comes online? And are you getting paid for all contracts today even before that?

Mackie McCrea: Jen, this is Mackie again. That contract has a foundation customer Golden Pass. Yes, they began being demand charges first part of this year would actually ramp up a little later in the year. And we will be fully utilizing that pipeline as much as we possible can. I believe we flows almost up to 0.5 Bcf a day, actually physical volumes in addition to the demand charges that we’re getting from Golden Pass. And it’s our expectations that that team will continue to fill that pipe up and every bit of the capacity is available until it’s begins being utilized by Golden Pass. As you know, probably that’s 1.65 Bcf of capacity that we can easily expand.

Jean Ann Salisbury: Yes. That makes sense. And then do you think of Lake Charles and the petchem project being somewhat dependent on each other in terms of the share that you’re willing to take? Just hypothetically, if one of them was to definitively kind of not reach up ID, would that increase your appetite to take a greater share of the other where you think of the as completely independent?

Tom Long: Yes. This is Tom Long. I’ll chime in here first. We look at them as independent. They’re not in the same dialogue we look at. In other words, our desire is to continue to look at market for all the product that we handle. And so when you start looking at petchem, you start looking at LNG, you start to have to start looking at the upstream benefits that we see. And we think they both on a stand-alone basis would make sense or we won’t take them to FID, but they are independent.

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

Operator: Our next question comes from Chase Mulvehill with Bank of America. Please go ahead.

Chase Mulvehill: Hey. Good afternoon everybody. So I guess, a quick question on the midstream segment. Obviously, took a big step down in the fourth quarter, probably more so related to POPs. But could you talk about how much in the fourth quarter that really reflected kind of spot commodity pricing versus what further downside you might have as you kind of roll in lower commodity prices. And I realize that you’re using the strip for your guidance, but just trying to understand and level set things gelato the fourth quarter.

Tom Long: Yes. This is Tom Long. It is those POP contracts. Jas, used to you nailed that as far as the way you described it. But the midstream area is the area that we did. When you look at 2022, we did enjoy a lot of the higher commodity prices as we as we went through the year and saw that. And that’s the €“ that’s probably one of the segments that we continue to look at when we give the guidance for 2023 that it is a lot about the pricing. Now remember, we are still using that forward curve for 2023, and that’s what we’ve got baked into it. But we still remain very bullish on the volumes and what we’re seeing, and we’re going to obviously capture all the value we can to continue to grow that segment.

Chase Mulvehill: Okay. Makes sense. And you probably have a decent look into kind of petchem demand. And if we’re starting to see kind of early signs of, I guess a bottoming of petchem demand potentially a pickup in the back half or you maybe think that’s more 2024. So would be curious on your thoughts on petchem demand and if you see that kind of bottom in the near term and maybe moving up as we get a

Mackie McCrea: Chase, we started losing you. Yes, I think I can answer if I don’t ask it again. But as , we do have a team they’re working diligently on a very unique €“ probably one of the most flexible projects that’s ever been built in the world, and we are in a difficult time. We’re in a very down cycle. There’s really no spread similar to what’s happening on a warrior, where there’s just no spread, and it’s hard to get a company’s commit. However, we are in dialogue with several equity partners, both of which will take a significant part of the yield out. And we do think it’s project at some point, we’ll get to FID. It’s tough timing right now based on kind of where the crack spreads are. But to your point, it is a cycle and maybe buy everybody is going to start seeing maybe by the latter part of 2024, we start seeing the upside of that cycle.

And so as we kind of get deeper into 2023 different this year, we are optimistic that we’ll get more momentum and hopefully get that to FID.

Chase Mulvehill: Okay. Perfect. I’ll turn it over.

Operator: Our next question comes from Colton Bean with Tudor, Pickering, Holt. Please go ahead.

Colton Bean: Good afternoon. Shifting back to Gulf Run, you mentioned the deliverability through Zone 2 and the trunk line. I think the team’s previously looked at extending the terminus beyond starts to add downstream connectivity. Can you just update us on where you stand on that project and what you need to see to move forward?

Mackie McCrea: You bet. This is Mackie again. We had an open season a while back, not that far back, but last year, and it was extremely successful in regards to the demand. So we’re looking at a bunch of things. It doesn’t take a lot of pipe to get down to connect our affiliated company at FTT, which would help some of those customers. We also, of course, are looking at potentially extending it down to Lake Charles. We can add compression only and at a Bcf or it may mean that loop in that pipeline and building an entire new 42-inch, not only down to trunkline but also we’re down to Florida and other of the interstate pipeline. So as the volumes grow out of the Haynesville, as customers are looking for more gas, not only along the Louisa the Gulf Coast, but all the way to Florida, we do expect some significant expansions of the Gulf Run system.

Colton Bean: Great. And then Mackie, back on the NGL export expansion, can you just frame for us the scope that you’re looking at Nederland and Marcus Hook? I mean is that incremental refrigeration, mostly birth that you’re looking at? Just trying to get a sense of the total capital that might be required?

Mackie McCrea: Both, there’s kind of different tracks this may take. But generally, both expansions right now would be 70,000 barrels a day. That would include both refrigeration and tanks both at Nederland and at Marcus Hook.

Colton Bean: Yes. Thank you.

Operator: Our next question comes from Michael Cusimano with Pickering Energy. Please go ahead.

Michael Cusimano: Hey. Good afternoon everyone. I just had a couple of clarification questions, if I could. First, on the €“ the comment that you made, Tom, on the distribution increases. And I know you said that you all are going to look to increase them annually. Is it fair to assume that we’re at a stable level here until January of like 2024?

Tom Long: We’re going to always evaluate these as each quarter when the distribution is approved by the Board. But wanted to make sure we communicated to the Street that our goal was to get back to $1.22 . We’re obviously very, very pleased to see it at a 2 times coverage ratio when you look at the fourth quarter is what I’m referring to. But it’s something that we’re going to probably get back into the kind of the normal evaluations on an annual type basis. Clearly, when you look at €“ once again, I kind of look at the capital allocation of the debt, continue to bring the debt down, but also, these projects we’re talking about. I know I’ve said already earlier on this call, but we’re going to continue to look at these good projects to continue to strengthen the company. But it’s really more on an annual basis that we’ll be looking at some type of some type of an evaluation as to where we are, so.

Michael Cusimano: Okay. Yes. No, that’s very clear. And then also to clarify on the midstream commentary from earlier. Was there any like offset benefits in other segments from the lower €“ maybe like pop realizations in midstream? I guess like did the intrastate segment benefit from lower Waha, et cetera, that there was kind of some puts and takes there across the franchise?

Mackie McCrea: This is Mackie. A little bit hard to answer that question. But if you just reflect and look at our results, as we said, in every segment, we hit records. So yes, as midstream might have got a little bit tighter and POP maybe not as strong or maybe heading this year. That’s kind of the advantage of Energy Transfer, we’re so diversified in all the different aspects, crude, NGL, to midstream, to our intra- and interstate pipelines. So for example, we hit record volumes in some of our pipelines in the intrastate as well as other of our pipeline systems. So sure, there’s offsets when some of our segments may struggle like midstream. Certainly, that’s offset many times about maybe our crude business or our NGL business.

Michael Cusimano: Okay, got it. That’s helpful.

Mackie McCrea: Okay, I’m sorry. You have another question? Yes.

Michael Cusimano: That’s helpful, that’s all from me.

Mackie McCrea: Okay.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Tom Long for any closing remarks.

Tom Long: You bet. Once again, thank all of you for joining us today. Another great year we’ve delivered and we would be remiss if we didn’t thank all of the team members of Energy Transfer for delivering another great year and to getting our balance sheet back to where it needs to be, our financial flexibility it didn’t just happen by coincidence or accidents. So a huge complement to the entire Energy Transfer team, and we can’t thank all of you enough for your continued support, and we look forward to talking to all of you in the near future.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.