Greetings, and welcome to the Energy Transfer Fourth Quarter Earnings Results Conference Call. [Operator Instructions] Please note that this conference is also being recorded. I will now turn the conference over to our host, Tom Long, Co-Chief Executive Officer for Energy Transfer. Thank you. You may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Fourth Quarter 2021 Earnings Call, and thank you for joining us today. I'm also joined today by Mackie McCrea and other members of our 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 on our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our annual report on Form 10-K for the year ended December 31, 2021, which we expect to be filed this Friday, February 18. 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 looking at some of our fourth quarter and full year 2021 highlights. For the full year 2021, we generated adjusted EBITDA of $13 billion, which was a significant increase over 2020 and in line with our expectations. DCF attributable to the partners of Energy Transfer, as adjusted, was $8.2 billion, which resulted in excess cash flow after distributions of approximately $6.4 billion. On an incurred basis, we had excess DCF of approximately $5 billion after distributions of $1.8 billion and growth capital of approximately $1.4 billion. On January 25, we announced a quarterly cash distribution of $0.175 per common unit or $0.70 on an annualized basis, which represents a 15% increase over the previous quarter and represents the first step in our…

[Operator Instructions] And our first question comes from Michael Lapides with Goldman Sachs.

Congrats on a good end of year and good quarter. Actually, I had 2. One is, in the potential development of a takeaway solution for natural gas coming out of the Permian, can you talk a little bit about just what the early feedback from shippers has been? Meaning, what's the level of interest in shippers to sign a 10 or 15-year contract? Or are they more willing to do and want to do shorter-term deals? That's the first question. And then the second question is, can you just talk a little bit about the Permian Express system and where you might have recontracts, contracts that roll off over the next couple of years?

You bet, Michael. This is Mackie. We are so excited about this project. We haven't really spoken a lot about it. We have more capacity than anybody else now across the states. We've been accommodating volumes growth for the last year or 2. We've heard a lot of our competitors talk about a project, how needed it was, how close they were to getting a project online. And it really became important over the last number of weeks that we kick in, in a big way. And so to answer your question, the customers that we talk to are very excited. If you compare our project to anybody else, most of them have gone either from the Waha area down to [indiscernible] or now they're talking about going to Katy and the luxury of what our project will provide will be just kind of a smorgasbord of markets. And we've said in the statements by Tom earlier, but the bottom line is we will take Permian Basin molecules and deliver them to the best markets on the Gulf Coast to Katy, to ship channel, to some of the LNG markets, to Henry Hub to Gilles and the better markets in Louisiana. Some of these producers can stop or shippers can stop in Carthage. So we're extremely excited about this. We continue to do what we've been doing for a long time, and let's look at all of our assets and not only how we repurpose them possibly to make more revenue, but also how we use more efficiently and utilize them in a better way. And this project will allow that. It's probably a 200-mile less pipeline than our competitors. It will tie into 36- and 42-inch pipelines downstream, where we have a significant amount of capacity, they will need…

And our next question comes from Chase Mulvehill with Bank of America.

Just a follow-up question here. If we think about the potential capacity of the pipelines coming out of the Permian or the natural gas coming out of the Permian, how much capacity do you think you'll be able to kind of pull out of there and get to the Gulf Coast as you look at these conversions for this Permian nat gas takeaway projects?

The way we're going to look at that is, of course, listen to our customers and we'll design a system that can meet those demands. But what we anticipate is kind of a minimum of combined capacity that we have today on Oasis that's available today and in the future. And with this new pipeline project, we'll have a target between 1.5 and 2 Bcf of new takeaway capacity, a couple of years after we reach FID.

Okay. All right. That makes sense. And you said, once you reach FID, to take you kind of 2 years to put it in service, and it seems like it's early stages, maybe conversations with customers. So maybe we're a few months away from FID. And if we kind of look forward 2 months, where $90 crude is going to incentivize a lot more activity in the Permian. It's only going to pull this bottleneck forward, not push it to the right. So it's probably going to happen even faster than people think. And so we reach that point of constraint for natural gas takeaway capacity earlier in the Permian in 2023. So maybe walk us through your Permian business and help us understand the puts and takes, where you can make more money and where it might hurt you if you hit some bottlenecks for nat gas takeaway in the permit?

Okay. Yes. Look -- and we've spoken about a few of these projects. We are in the middle of the project right now where we're spending on a great deal of capital, and we're increasing the capacity on Oasis by between 40,000 and 45,000 a day. We're looking at another expansion where we can increase it by about another 20,000. So -- and we should kick that off pretty soon. Not a lot of capital, just adding compression, and we'll be able to move about 60,000 more a day. So to your question about it could move forward more quickly, we agree with that, we think if you look at some of the forward curves, you're out over $1, $1.20, I think, latter part of '22 and '23, and we're well positioned to capitalize on that. We have capacity on Oasis. We have more capacity coming available in the next couple of years on contracts that are rolling off at much lower rates than where we think the market will be. So we positioned ourselves very well. So we're kind of capitalizing in 3 different ways. One, on what we have today, wherever the spread is, we're, of course, benefiting from that. We're adding capacity where it makes sense, and I just alluded to on the 60,000 that would be adding here the next 6 or 7 months. And then once we hopefully get to FID here in the coming quarters, then we'll add additional takeaway. But there is going to be some tough time regardless of the decisions late for whoever it's going to build the next pipe, and we do believe there is going to be a blowout spreads, and we're sitting in a very good spot there because where our assets are in the available capacity we have to move Permian Basin volumes to the Gulf Coast.

Next question comes from Jeremy Tonet with JPMorgan.

I just want to start off with the CapEx, if I could? I was just wondering if you could help us bridge, I guess, the $500 million to $700 million guide before to now? And any numbers you could put around how much was Enable versus new projects? Just trying to better understand the drivers there.

Okay. Yes. Jeremy, this is Tom. One, will I start first with the split of how the numbers are coming out between the various segments. And I appreciate the fact that Gulf Run is now included in this. But the largest piece of this is really earmarked toward the midstream. You heard us talk about like the new processing plant. So that's probably about 35%, 36% of the number. Then moving next, you're going to move into the interstate with the Gulf Run that I just mentioned, you're probably running about 20%, 23% or so on that piece of it. And then when you keep moving on down through the mix, the NGL and refined products are 20%, 21% with crude intrastate and other kind of bringing up the last of it. But that's the way you really kind of see it. Now kind of looking at this, remember that we did roll over a couple of hundred million from projects and in 2021. So we probably need to start with that. As far as the rest of the pieces of it, that's really how it's probably best to try to break that out. I don't really have a bridge necessarily between the $700 million to these numbers. But I would say the biggest chunk of that is coming in with the Gulf Run.

Got it. That's helpful there. And I just want to turn to Enable for a minute, if I could? Just wondering now that you have them in the fold for a little bit here, wondering how things are going versus expectations? And really, I just wanted to see, you talked about converting assets like for this potential new Permian gas pipe project, do you see, I guess, more potential conversions now that you have kind of a larger set of assets to work with here?

Yes, Jeremy, we do. We're very excited. As we've said before, we hadn't really dug into the commercial synergies. We knew they were there. We saw some kind of easy ones. But as we've dug in, we found more. There's a number of ways where we can run plants more efficiently. There's pipelines that we're looking at, we can convert them to a different product, particularly NGL in a couple of instances. And we're also looking at combining assets and pipeline assets to move volumes out of Haynesville and into some of the markets to get gas fill -- our assets to the Gulf Coast. So still a little bit early. We'll talk much about those, certainly by our next earnings call will be knee deep and announcements and taking advantage of some of those synergies, but we're very excited with kind of a very preliminary discussions and analysis that we've been going through, but we do have teams working on that daily.

Our next question comes from Michael Blum with Wells Fargo.

Just wanted to follow up on some of the Permian gas discussion. Just to confirm, the Oasis pipeline optimization project that you referenced, is that the 60,000 expansion that, Mackie, you were talking about? Or is that the limit as to what Oasis can be expanded?

Mike, it's Mackie. Yes, gosh, limit. We've seen like we've gone through this exercise, I don't know, for years, and we keep adding capacity. And as we study more, we find ways to add more. So the more recent one was the one I mentioned, too, that we're already moving forward on the 40,000-plus -- 40,000, 45,000 Mcf day expansion of ad and compression, and then we're about to approve another smaller one, but a 20,000. So combined, that's about 60,000 or 65,000 of additional capacity that we'll have added by the end of the year, first part of 2023. So that's separate from this other project that we're talking about out of the Midland Basin, a much bigger project to move gas to existing assets that we own over closer to East Texas.

Okay. Great. And then on this new project, I think you mentioned you'd have to convert some existing pipelines. Would you -- what service would you be taking those out of? And the second part of that question is for the -- this new larger pipeline, what length of contract will you need to sort of get this thing to FID?

I'll start with the end of that. Our goals on these types of projects are typically 10 years, so that's what we'll be negotiating a lot depends on the rates and what exactly the customer is looking for. So we'll be negotiable on that. But to clarify, no on this one, unlike all the others converting crude oil to gas or gas to NGLs or NGLs to diesel. This is just utilizing capacity that's underutilized today. So for example, we would be tying this project into a 36-inch pipe near Tolar, which is southwest of the Metroplex, DFW Metroplex, and that would tie into our massive intrastate 36, 42-inch pipeline systems that deliver enormous amounts of gas all over the Carthage and all the way down into the Gulf Coast, Katy and into the ship channel markets as well as the Beaumont markets. So we're not converting any capacity on this project. It's just fully utilized capacity. It's already built sitting there idle underutilized.

Our next question comes from Jean Ann Salisbury with Bernstein.

The Haynesville is growing rapidly and several new projects have been proposed. Can you kind of comment on if you think Haynesville will run out of capacity kind of before Gulf Run comes on? And are you close to moving forward on the expansion project to Gulf Run?

Yes. I'll step back a little bit. Yes, our team, [indiscernible] and her folks, have been working hard on finding a solution for the growth out of the Haynesville. So we've done that in a number of ways by bringing gas in from Tiger into Carthage and moving it to our HPL and ETC network down into the Gulf Coast. We've done some significant contracts there. We're negotiating some very significant ones that provide access and flexibility where some of these producers are looking to go east to Perryville and Tiger and also come back into Texas. At the same time, there's about 1.1 Bcf of Golf Runs already sold. So we've got about 500-plus, 550 that we're looking to sell. We're aggressively tying that into our conversations for those producers that would like to reach the markets at the end of Gulf Run. And in that now, as you can imagine, we're -- and the volume growth in the Haynesville is a tremendous volume growth. We'll need to increase Gulf Run, no doubt. And we'll be looking at doing that in the near future. In addition to that, as we move more gas Eastern on both our new CP line and on the Tiger line, we will be kind of upgrading our ability to move gas through trunk line down into the Henry Hub market into some of the LNG markets on the Gulf Coast. So Haynesville, huge growth for this country for natural gas growth and huge things that we can capitalize on with the assets we have, especially now that we own the Enable assets that run through that same area.

Great. That's super helpful. And then as a follow-up, you used to have significant exposure to the Waha differential, but then I think you firmed it all up. I'm not sure for how long. How much exposure would you have to the differential in '23 '24? And it looks like it might widen again. I know you kind of mentioned you could optimize Oasis, so perhaps that could be part of it. But on the underlying Oasis, just wanted to see if you still had open capacity?

Yes. We have -- we did have a strategy a while back of, we were very fortunate to be able to benefit from the spreads when they blew out. But during that time, we knew they'd come back in. So we did go in and carve out some of that capacity as our shippers requested and put some of those contracts in place, long-term 5, 7, 10-year contracts. But we still have several hundred thousand in excess of several hundred thousand a day of capacity across the state. And over the next year or 2, we'll have more capacity becoming available, like probably at least double that amount. So 400,000 to 500,000 in the next year or 2 will have to benefit from these wider spreads and/or benefit from those shippers that are wanting to take capacity under a 10-year deal on a new project, they may start out on Oasis for part of that time in the early years and then move them over to the bigger projects. So it just gives us kind of a significant advantage over all the competition and be able to accommodate the needs over the next year or 2 and then gives us time to build a much bigger diameter pipeline to meet the needs that we all see coming by '24, '25.

Our next question comes from Timm Schneider with Citi.

And actually, let me follow up on the contracting question on the new -- on the potential new Gulf Coast gas pipeline. Any appetite here to maybe do this even if you don't get the 10-year commitments right off the bat because you are going to, assuming this is the most cost-efficient project out there, going to be making a lot of money potentially on spreads. How do you think about that?

I'm sorry, I missed the first part of that question. Say that again. I'm sorry, Timm.

Yes. So I was just asking what the appetite was for you guys to potentially go ahead with this project even if you don't have 10-year contracts from shippers given the fact that it's probably the most cost efficient and you'd be making a lot of money on spreads as is anyways?

Yes. As we've said, one thing we are going to do even in light of how needed this is, we're going to be very prudent on our capital. And so we're going to make decisions that make sense both short term and long term. But we do believe because of the advantages that I've talked through and that you all are aware of that we have a significant advantage to kind of get this moving very quickly. And so we do believe that whether it's 7-year contracts at higher rates or 10-year terms at a little bit lower rates. We believe we're going to achieve those. We really, at this point, don't see any like major players stepping up 600,000 a day. We do think this can be made of a whole lot of different shippers and producers. But once again, I think as we get the word out and we have the number of customers, everybody is going to see a clear advantage that this project offers is significantly better than any of the competing pipeline projects that are out there.

Got it. And then a follow-up on the CapEx side. And Tom, I think you kind of talked about this in prepared remarks. The increase in CapEx, that is primarily going to be very short -- not very short cycle, but shorter cycle CapEx, where a lot of that is actually going to show up in 2022 EBITDA. Is that the right way to think about that?

Yes, that is the way to think about it. That's the real beauty of a lot of this CapEx. It is very short nature. And I'm not saying it won't be until kind of later 2022. So 2023 is probably when you'll see the full impact. But you stated it properly when you said that these are shorter build type, good returning projects.

All right. And then maybe the last one here. What are the book – I mean, the book ends 11.8 billion to $12.2 billion on the EBITDA. What are some of the moving pieces around that? A –Mackie McCrea: Yes. I’m not sure if I understand your question completely. If you’re talking – I mean some of it, Timm, is commodity prices. Commodity prices stay higher, we’ll be on the higher end or they go higher than there are today. If we see commodity prices drop off, that would tend to move a little bit off of the high end. So that’s one of the drivers. And then spreads kind of watch and see what happens with spreads. And we think that as we’ve seen in the gas, these were down the teams not that long ago, and now we’re starting to see them spread out. And as I’ve mentioned a little bit earlier, as you get deeper in this year, they’re going to spread out significantly. So we’ve made certain assumptions on those spreads. However, we’ve been very conservative along those lines. So I guess I’d summarize all that with commodity prices certainly will have an impact, but also we do believe that the drilling is returning in a big way. The rigs have even moved back into Oklahoma. We were talking a little bit earlier today that the rigs pre-pandemic in the first part of 2020 are now back to I think equal, maybe a little bit more rigs in Oklahoma, which everybody is aware they moved back in, in a big way. So there’s assumptions that the industry is going to continue to grow as the pandemic leave the world as demand grows for all these products. And so we’re very bullish on drilling to continue. And so that plays a role into our projections as well. A –Tom Long: And the one thing that I would add is the commodity piece of this is, as far as the exposure, we’re using about 7.5% to 10%, and we’re using 0% to 2.5% on the spreads. So 90% fee-based. And when you add those others together, they add up to about 10%. So that’s how you can calibrate that commodity and spread component.

Our next question comes from Spiro Dounis with Credit Suisse.

First one is just on the distribution. Curious how you guys are thinking about the time frame or maybe the pace on getting back to that prior distribution of $1.22 -- sorry, $1.22 a year? It sounds like leverage may be one of the governing factors there to some degree. And the other factor you mentioned, of course, is the pace of buyback. So just curious how you're weighing all that and just how to help us think about the pace of getting back to that prior level?

Yes. We really are focusing on the points that you just walked through there. So if you really look at this, returning to the -- at least the $1.22 that we talked -- that we had previously, back before we had reduced the distributions, that is moved up to a top priority, but we clearly have these great projects we're talking about, likewise, these capital projects, then you blend in the debt paydown likewise. Unit buybacks, I would probably put as behind those 3.

Got it. That's helpful. And then, Mackie, just putting all your comments together, just around the Haynesville, clearly, more gas coming there, this new natural gas pipeline out of the Permian. You're trying to move that gas. It sounds like as far east as you possibly can. All seems to be getting to a point where maybe Henry Hub very clearly can be well supplied for a long time. So I'm sort of curious what does that do for prospects on something like Lake Charles LNG? I saw that you guys had requested an extension there for construction recently. So I don't want to tie them together too much, but just curious where that sits commercially, got I think moving more gas towards Hub is a good thing long term?

Yes. It's a great question because, for example, one of the larger shippers that possibly could take a fairly significant amount of gas compared to the others on this project wants to get to Henry Hub and would love to be a provider of gas to our LNG projects, our Lake Charles project. So that does kind of go hand-in-hand with some of the shippers and producers we're talking to. But around LNG, we've been through cycles of excitement and emotion over the last 4 or 5 years, whether we'll ever get there. And I'd tell you, it's really pick up steam. You read it anywhere. You see what's going on around the world and China from the top of their leader, their mandate is to go out and find gas. And we're seeing that with the Chinese customers as well as other customers. Around the world, there is a big push right now, that all of a sudden natural gas is green, and everybody's realized how important it is only for the next 5 years or the next 30 years. And so it's really picked up steam. We hope to be able to announce some agreements that we are close to getting signed over the next few years. They're certainly still ways from FID but we are really excited about where that project is going. And more importantly than not of where we may end up at the end of the day, what percentage we make under that. The biggest site we have what you just alluded to, and that's all the gas that we'll feed into the system into the Henry Hub area through our multitude of pipelines, through Golf Run, through Trunkline in both directions, bringing gas across CP, across Tiger, unlike all the other projects that are along the Gulf Coast, nobody can bring gas from Marcellus, Utica, through Panhandle, I mean, Rover Panhandle Trunkline directly into this project or now from Arkoma in Oklahoma Basin all the way down or even out from Permian. So it's turning to a really good project for the markets around the world, and then it has a by far the best supply portfolio and connectivity upstream. So we do believe that the Henry Hub area is going to become a much bigger trading hub than it already is and our LNG project would just magnify that significantly.

Our next question comes from Keith Stanley with Wolfe Research.

First, just a simple one. How many units of the company repurchased in Q4, the company itself, if any?

I think it was about $4 million.

$4 million. Okay. Great. Second one, Tom, you talked about debt reduction still being a priority for this year. Can you give a sense of, I guess, how you're looking at maturities and using free cash flow? Obviously, I mean you did over $6 billion of debt repayment last year. So as you see maturities this year, are you looking to use free cash flow to repay them generally? Or are you open to refinancing some of the debt as it matures.

Let's turn off with, we're clearly going to keep working towards the $4 million to $4.5 million. So as these maturities come up throughout the year, I would say that we will be paying down some of those maturities with free cash flow, but we will probably refi some of those maturities as they come up throughout the year.

Our next question comes from Colton Bean with Tudor, Pickering, Holt.

Mackie, you mentioned seeing more drilling activity in Oklahoma. Now that you have the Enable operations in-house, can you just update us on your Mid-Con NGL strategy? And what sort of time line we should be thinking about to fully integrate those volumes into the ET value chain?

You bet. And as I mentioned, we have the teams little bit working on this daily to try to figure out a way to best utilize all of our pipelines, our processing plants. For example, there are some plants in the Panhandle that may make sense to initially or for a short period of time to shut those down and more [Technical Difficulty].

Please stand by. Thank you. Please go ahead, sir.

Can you all hear me?

Yes, sir. Go ahead.

Okay. So did you hear any of my answer? If not, I'll just start over -- we're not sure what happened. It just disconnected. But anyway, I'll do a shorter version. We do have teams working on this around the clock. We've already identified some opportunities to better utilize more efficiently some of our plants and some of our pipelines. Looking longer term, we are looking at converting a pipeline to potentially crude service. And then, of course, a lot of our folks is going to be utilizing existing pipelines and/or repurposing in other manners to get NGL barrels down into our Texas NGL franchise ultimately for deliveries to Mont Belvieu and of course, on the Gulf Coast into the export market. So we've got kind of a short-term vision of immediate things that we'll do to benefit the assets up in Oklahoma and then a longer-term vision of bringing us many of the NGL barrels into our system.

Great. And Mackie, maybe just to clarify that last point on bringing Oklahoma barrels down. Is that thought process over the next couple of years? Or is that more of a back half of the decade when those barrels might be available to you?

Without disclosing a whole lot, I guess, from a competitive standpoint, in the next 3 years or so, we do expect the demand to grow in our ability from a contractual standpoint to start moving more barrels from the tailgate of both plants and other plants in Oklahoma, even third-party plants into our NGL franchise for deliveries down to the Gulf Coast.

Perfect. And then maybe, Tom, switching back to the capital priorities. You mentioned buybacks sliding a bit lower in the stack versus some of the alternatives -- can you remind us how you all evaluate the return potential on buybacks versus new growth projects?

Yes. It's based upon what you what you look at from a DCF per unit standpoint, is how we really look at that, probably not as much from a distribution yield. And as we look at where the unit price is and where that breakeven is versus the other opportunities for some of the capital projects we've talked about today. But we do look at it from a DCF per unit standpoint. A DCF yield, let's call it that.

And that concludes today's conference call. We appreciate your participation. All parties may now disconnect. Have a good day. Thank you.