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

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer third 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 the 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 quarterly report on Form 10-Q for the quarter ended September 30, 2022, which we expect to be filed this Thursday, November 3. 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'll start today by going over our third quarter financial results. We were pleased to report another strong quarter during which we generated consolidated adjusted EBITDA of $3.1 billion, which was up approximately 20% compared to $2.6 billion for the third quarter of 2021. In the third quarter, we experienced a nonrecurring $126 million charge in the crude oil segment related to the resolution of a prior year legal matter. In addition, we had an approximately $130 million negative impact due to the timing of the recognition of gains on hedged inventory in the NGL and refined products segment. Absent these two items, adjusted EBITDA for the third quarter would have been $3.34 billion. Results for the third quarter benefited from higher volumes across all of our segments, including record volumes in the Midstream, intrastate, crude oil, and through our fractionators. In addition, the acquisition of the Enable assets in December of 2021 contributed to our growth over the prior period. DCF attributable to the partners, as adjusted, was $1.6 billion for the third quarter of 2022 compared to $1.3 billion for the third quarter of 2021. This resulted in excess cash flow after distributions of approximately $760 million. On an incurred basis, we had excess DCF of approximately $265 million after distributions of $819 million and growth capital of approximately $500 million. On October 25, we announced a quarterly cash distribution of $0.265 per common unit or $1.06 on an annualized basis. This distribution will be paid on November 21 to unitholders of record as of the close of business on November 4. This distribution represents a more than 70% increase over the third quarter of 2021. As a reminder, future increases to the distribution level will be evaluated quarterly with the ultimate goal of returning distributions to the previous level of $0.305 per quarter or $1.22 on an annualized basis while balancing our leverage target, growth opportunities, and unit buybacks. As of September 30, 2022, the total available liquidity under our revolving credit facility was approximately $2.32 billion. Now turning to our results by segment. I'll start with the NGL and refined products. Adjusted EBITDA was $634 million compared to $706 million for the same period last year. This change was primarily due to the previously mentioned $130 million negative impact due to the timing of the recognition of gains on hedged NGL inventory during the current period. We expect to fully realize the offsetting gains on our financial derivatives and physical forward sales as the majority settle in the fourth quarter with a small amount settling in the first quarter of 2023. Adjusting for the noncash timing matter around hedging, adjusted EBITDA for the third quarter would have been $764 million. Results in this segment were otherwise driven by higher fractionation, transportation, terminal services, and storage margins related to increased volumes and higher rates. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.9 million barrels per day compared to 1.8 million barrels per day for the same period last year. This increase was primarily due to higher volumes on our NGL pipelines that deliver into our Nederland Terminal as well as a record volume on the combined Mariner East pipelines. Our average fractionated volumes set a new partnership record, averaging 940,000 barrels per day compared to 884,000 barrels per day for the third quarter of 2021. NGL export volumes significantly exceeded the third quarter of last year, driven by record ethane exports out of both Nederland and Marcus Hook. At Nederland, this was driven by the second tranche of the satellite contract going into effect on July 1, which doubled the volume commitments from the initial term. Year-to-date, we have loaded approximately 29 million barrels of ethane out of Nederland. For the full year 2022, we expect to load more than 40 million barrels of ethane out of Nederland, with that increasing to approximately 60 million barrels for 2023. 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 $868 million compared to $556 million for the third quarter of 2021. This was primarily due to the increased throughput in all of our operating regions, favorable natural gas and NGL prices, and the acquisition of the Enable assets in December of 2021. Gathered gas volumes were a record 19.1 million MMBtu’s per day compared to 13 million MMBtu’s per day for the same period last year. Excluding Enable, gathered gas volumes on our legacy assets were also a partnership record for the third quarter. Permian Basin and inlet volumes remain at or near record highs. We continue to utilize the Permian bridge daily to optimize our available processing capacity as we await the completion of two new plants that are currently under construction. For the crude oil segment, adjusted EBITDA was $461 million compared to $496 million for the same period last year. Earnings were offset by a $126 million charge related to the resolution of our prior year legal matter. Absent this charge, adjusted EBITDA would have been $587 million for the third quarter of 2022. These results were otherwise driven by improved performance on our Bakken pipeline, 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 a record 4.6 million barrels per day compared to 4.2 million barrels per day for the same period last year, driven by higher crude oil prices and strong refinery demand, as well as the addition of the Ted Collins Link and Cushing South pipelines and increased throughput through our Houston terminal. Excluding Enable, crude oil transportation volumes were also a record for the third quarter. In our intrastate segment, adjusted EBITDA was $409 million compared to $334 million for the third quarter of 2021. During the quarter, we benefited from increased rates, higher production in the Haynesville Shale that drove greater utilization on Tiger, improved demand on trunk line and line CP, as well as the addition of the other interstate enabled assets. We continue to see heavy utilization on many of our interstate pipelines, including Tiger, FTT, Stash, and Rover. And for our intrastate segment, adjusted EBITDA was $301 million compared to $172 million for the third quarter of last year. This was primarily due to higher optimization opportunities, increased retained fuel revenues related to higher natural gas prices, and the addition of the Enable assets. Utilization of our HPL system remains strong due to the increased demand for gas takeaway, and our rig pipeline system continues to flow at or near capacity due to increased activity in the Haynesville. Turning to a brief update on our M&A activity. In August of this year, we completed the sale of our 51% interest in Energy Transfer Canada for cash proceeds of approximately $300 million. The sale reduced our consolidated debt by approximately $850 million. It also allowed us to divest of these noncore assets at an attractive valuation and utilize the cash proceeds to further deleverage our balance sheet and redeploy capital within our U.S. footprint. In September of this year, we completed our acquisition of the Woodford Express LLC, which owns a Mid-Continent gas gathering and processing system for approximately $485 million. This bolt-on opportunity provided roughly 400 million cubic foot per day of cryogenic gas processing and treating capacity in Grady County, Oklahoma, as well as more than 200 miles of low and mid-pressure gathering lines in the heart of the SCOOP play. The assets are already connected to our inter and intrastate systems as well as our gas gathering system. The system is supported by dedicated acreage with long-term, predominantly fixed fee contracts. Now looking at recent developments on our ongoing growth projects. Year-to-date, Lake Charles LNG has executed six LNG offtake agreements for an aggregate of nearly eight million tons per annum, including a 20-year LNG agreement with Shell LNG LLC that was executed in August. As we have previously stated, we expect to finance a significant portion of the capital cost of this project by means of the sale of equity in the project to infrastructure funds and possibly to one or more industry participants in conjunction with LNG offtake agreements. We have recently signed nonbinding letter agreements with two Japanese customers for LNG offtake, and we are in active negotiations with several customers for long-term offtake contracts for significant volumes of LNG. We are making progress on all aspects of the project, and we're now targeting FID by the end of the first quarter of 2023. Upon completion of the LNG project, we expect to realize significant incremental cash flows from the transportation of natural gas on our Trunkline pipeline system and other Energy Transfer pipelines upstream from Lake Charles. We believe that our Lake Charles LNG project will provide an important contribution towards solving the growing global energy demand. As a reminder, our Mariner East pipeline system is fully commissioned and capable to transform more than 365,000 barrels per day, including ethane. As we have previously mentioned, we completed work at our Marcus Hook terminal to allow us to increase ethane exports out of Marcus Hook. As a result, we reached a new record for ethane exports out of our Marcus Hook terminal in the third quarter. NGL demand both in the U.S. as well as from overseas customers continues to increase, and we have sufficient commitments to move forward with an ethane export expansion. Even though we expect to expand our ethane export capabilities at both our Marcus Hook and Nederland Terminals, these commitments provide us with the optionality to initially expand at either terminal. Construction of Frac VIII continues on schedule, and we expect it to be in service in the third quarter of 2023, which will bring our total Mont Belvieu fractionation capacity to over 1.1 million barrels per day. Construction of our new 200 million cubic foot per day Grey Wolf processing plant in the Delaware Basin is underway. This plan is supported by new commitments and growth from existing customer contracts and remains on schedule to be in service by the end of 2022. Construction is underway on the Bear plant, our second 200 million cubic foot per day processing plant also located in the Delaware Basin, which was accelerated to meet growing demand. We expect this plant to be in service in the second quarter of 2023. In addition, given the significant amount of demand we're seeing, we are evaluating the necessity and potential timing of adding another processing plant in the region. Mainline construction of the Gulf Run pipeline was only finished, and we expect to complete the modifications of compression by the end of this year. Gulf Run, which is a 42-inch interstate natural gas pipeline with 1.65 Bcf per day of capacity, will provide 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. It is backed by a 20-year commitment for 1.1 Bcf per day for Golden Pass LNG, and we recently concluded a nonbinding open season on Gulf Run due to growing product demand. We're pleased with the results of the open season and customer discussions are ongoing, which will likely necessitate additional facilities beyond the initial design of the 1.65 Bcf per day. Modernization and debottlenecking work on the Oasis pipeline continues, which will add an incremental 60,000 Mcf per day of much-needed capacity out of the Permian Basin. We expect it to be partially in service by the end of this year with full service by the end of January of 2023. In addition to these ongoing projects, we continue to evaluate and have customer discussions regarding a number of other projects that, over the long term, could provide significant upside to our business. These include the Warrior Pipeline project, which is the most optimal solution for customers to transport gas out of the Permian, as well as opportunities to develop a petrochemical project on the Gulf Coast or acquire petrochemical facilities. We remain optimistic that we can bring these projects to FID and look forward to sharing any significant updates on these projects at the appropriate time. On the alternative energy front, our focus remains on reducing emissions across our pipelines, including pursuing a number of projects related to carbon capture and sequestration, enhanced oil recovery for use in the food and beverage industries, as well as sequestering CO2 from our proposed Lake Charles LNG liquefaction facility. We'll be excited to update you once we have a project and specific agreement in place. Looking at our growth capital spend for the nine months ended September 30, 2022, Energy Transfer spent approximately $1.3 billion on organic growth projects, primarily in the midstream, intrastate, and NGL refined products segment, excluding SUN and USA Compression CapEx. For full year 2022, we expect growth capital expenditures to be near the high end of our range of $1.8 billion to $2.1 billion. Over 90% of our 2022 growth capital spend is comprised of projects that are already online or are expected to be online and contributing cash flow before the end of 2023, at very attractive returns. We will provide our 2023 growth capital outlook on our fourth quarter earnings call. For 2022, adjusted EBITDA guidance, given our strong performance for the first nine months of the year as well as continued demand for our products and services, we now expect our adjusted EBITDA to be between $12.8 billion and $13 billion. This is up compared to our previous guidance of $12.6 billion to $12.8 billion. Overall, our outlook is strong as we have a stable business that has demonstrated its ability to manage through various market cycles. We expect future growth to be supported by production improvements, improved market conditions, increased utilization of our existing assets, as well as strong domestic and international demand for our products. We remain bullish about the future of our industry and the growing worldwide demand for crude oil, natural gas, and natural gas liquids. We expect to reach our leverage target range of 4 times to 4.5 times by the end of 2022 to continue to strategically allocate our 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 our unitholders. 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.

At this point, we will take our first question from Jeremy Tonet with JPMorgan. Please go ahead.

Just want to kind of start off with the LNG project with Lake Charles, if I could. Just walking through a number of different details that have emerged over the past quarter or so. You've had smaller competitors kind of fall by the wayside, if you will. Yet, it's still kind of an inflationary environment where it's hard to kind of lock in contractors, I think. Just wondering how you see these different influences coming together and how that impacts, I guess, your outlook for Lake Charles at this point?

Jeremy, great question. A lot of moving parts to your question, but as is common in the LNG world right now. Obviously, as you've touched on, the EPC costs have escalated since our first bid we got two years ago, and that had an impact on pricing of liquefaction. We have made good progress in increasing our liquefaction charge as we progress with new contracts. We're excited about where we are in terms of being a bigger company with a strong balance sheet and a great natural gas pipeline network. We are one of the strongest companies with a brownfield facility with storage tanks and docks. We're in a really good position to get to the goal line.

And then maybe just kind of pivoting to the Permian a bit. If you could update us, I guess, as far as how you see the takeaway outlook evolving here at the latest thoughts on Warrior. I imagine negative Waha prices do not hurt your business, but just wondering if you could provide more details on that, and I guess open capacity you have and maybe how that could increase over the first half of the year?

Yes, Jeremy. This is Mackie. We continue to be very excited about that project as we've experienced the last two or three weeks. When there's any kind of a blip on any pipeline that's moving gas out of the Permian Basin, we see these wide spreads. We, like most of the industry believe that as we get deeper into this year and throughout most of the next two years, it's going to bounce back. The base is going to blow out. We do sit in a very fortunate situation that we have capacity available today, which actually increases over the next few years across the state. So we will be able to benefit from those wider spreads. But at the same time, we are diligently working towards getting to the finish line on Warrior after the announcement of this other 42-inch line that will move a couple of Bcf across. It's kind of slowed things down. But we will be the next pipeline that's announced out of there. We aim to be the best option for anybody coming out of the Permian Basin, whether it's Delaware or Midland by Katy Ship Channel as well as other really good markets off our interstate systems. So we're keeping our head down, but we're going to be very prudent when we make that decision, and we hope to finalize that in the next couple of quarters.

Our next question will come from Chase Mulvehill with Bank of America. Please go ahead.

I guess a question on ethane. Obviously, ethane prices have softened a little bit here. I'd be kind of curious on your thoughts about ethane rejection and kind of how that plays out over the coming quarters. And kind of rolling into that, about your thoughts on ethane exports and if you see that as kind of a near-term release valve? Or do you actually think that we're running kind of up against full capacity there?

Chase, this is Mackie. Yes, we're just so pleased with what we've done in building out Marcus Hook and building out Nederland around ethane. As we've said, we now have sufficient contracts to expand. However, that will take three or four years to expand once we decide on whether it's in the North or along the Gulf Coast. But the way we look at rejection or recovery depends on the region. So from an Energy Transfer standpoint, we may be projecting ethane in some areas and recovering in others. But right now, given the ethylene prices and gas prices, we are recovering ethane in most regions. As you know, a significant amount of ethane is rejected daily up in the Northeast. There's a lot of ethane up there for our projects. And as we head toward a decision to expanding at either Marcus Hook or Nederland, we'll look at maximizing what we have today. As we've said in our opening remarks, the satellite kicked into their second tranche. So we've got that. We also have additional capacity that we will be fully utilizing on a month-to-month basis as the market dictates.

So another follow-up is just really on Lone Star. If I'm right, I think you've got some latent capacity there. But kind of what I'd like to ask is if there are opportunities for you to kind of work with some of your peers to maybe offload some of their long-haul Permian NGL volumes. I mean, the reason that I ask is when your competitors laid one of their expansion projects on NGL and maybe somebody else announces something here later this week. But just curious because you do have some latent capacity and if there's an opportunity for you to work with some of your peers and offload some of those volumes and help the industry be a little bit more capital-efficient.

Yes, this is Mackie again. Yes, I'd love to know who you're talking about; that's interesting, but please give my telephone number. We certainly would offer transportation to anybody piped through our natural gas liquids pipelines. And we feel real good about where we're at. Over the last several weeks, we've set records out of the Permian. I think we exceeded 860,000 barrels a day. Around our NGL business, we almost hit 1 million barrels this past week of fractionation at Mont Belvieu with these colder temperatures. So we have the ability to move significantly more volume out of the Permian as our two new cryogenic plants come online by the second quarter of next year. So we certainly have built it to accommodate our own barrels. If your peers are trying to get their barrels from off below, we would love to hear from them.

Our next question will come from Marc Solecitto with Barclays. Please go ahead.

So maybe following up on one of the earlier questions around basis exposure. I think a few quarters ago, you referenced a couple of hundred Mcf that was open with a couple of hundred becoming available over the next couple of years. So just wondering if you are sharing an update if you could provide that?

Sure. I'll quantify it a little bit. We are in negotiations on Warrior, and that very easily could impact what capacity is available over the next year or two, as that kind of comes into those negotiations. But notwithstanding that, we've had about 250,000 a day available. As we said in our opening remarks, we've got about another 60,000 coming available in the latter part of this year and the first part of next year. So that puts us right around 300,000 a day that we'll have available as we sit here today.

And then just with respect to the updated guidance. First, I just wanted to clarify whether the previous guidance range included the legal settlement in the crude segment. And then as we think about the upward revision, was that mostly a function of just upside to your conservative commodity price assumptions or other operational drivers? And then any variables between the lower and upper end of the revised range? Curious if you have any color there.

Yes, Mark, this is Tom Long. Short answer is that the legal settlement was not included in the previous guidance. So this guidance you see right now does include the $126 million. But I will tell you, it also includes the $130 million for the timing around the mark-to-market on some of the NGLs. So the guidance we're giving you right now of $12.8 billion to $13 billion does now include both of those. But as we highlighted in the prepared remarks, we are expecting one or more of the $130 million to come back to us in the fourth quarter. So keep that in mind that that guidance does include what occurred in the third quarter but the reversal of most of it in the fourth quarter. Mark, as far as the rest of your question goes, we've always stayed fairly conservative on the commodity prices, and we continue to do that. I think you see where some of the prices, at least on the natural gas side, are going to right now. It was prudent for us to do that. But at the same time, we don't have many months left in the year for much of an impact. You had quite a few other parts of that question, you may need to repeat what part of it I'm not answered here.

Just as far as within the revised range, the upper and lower end, what are some of the drivers between the upper and lower parts of the range?

It continues to be pricing that was running a little higher than what we had anticipated. Once again, a little bit of that got shaved off with what you're seeing occur right now in the fourth quarter. The other piece of that is we just continue to have a great commercial team, and the optimization efforts that are occurring across our system are really huge compliments to the team and what they're able to do. And so that's probably the primary two drivers.

Our next question will come from Gabe Moreen with Mizuho. Please go ahead.

It may still be a little bit early days, but can you talk about the CapEx outlook for next year? Whether you think you're going higher or lower? I realize there's still a lot of things on the drawing board. But just as you sit here today, kind of directionally where do you think you're headed for CapEx next year?

Yes. It's always a good question, okay? We worked hard in trying to hold off until that fourth quarter. And in fairness, a lot of that is because we do have so many great projects. Mackie was going over several of them. So you've got everything from the Lake Charles LNG to the Warrior to several other items, petrochemical projects, etc. So it's really difficult to provide that guidance right now. That's the reason we wait until the end of the fourth quarter to be able to provide that. But we've talked about pretty much everything that's out there that we're seeing. So if you really kind of go back to what guidance we give this year, the $1.8 billion to $2.1 billion, there's not a lot of additional guidance we can give you for next year until we have a little more visibility into those. But as you can see, it's not going to be a really large number.

And then maybe if I can follow up sort of on a two-part Haynesville pipeline question. I'm just wondering where you guys think you are in terms of, I guess, utilization out of all the multiple straws you have in and out of the Haynesville, also, I guess, repricing contracts to market now that that capacity is really in demand. And the second part would just be kind of an update on Gulf front and the possibility of expanding that with or without Lake Charles?

Okay. Gabe, this is Mackie again. Yes. What an exciting area, my goodness, who could have seen this? Maybe some people saw this years ago, but when you see these wells coming on to 50,000, 60,000, 70,000 a day and holding out for a while, it's a great place to own three 42-inch pipes and a lot of other systems. So we're very excited about that. You touched on some things like we said earlier in our remarks, the rigs are pretty full. So we're looking at backhaul, some of our Enable assets to get down the cartage and also get to our Gulf Run and Tiger pipelines. So we're doing everything we can to utilize capacity in both directions on all of our pipelines in North Louisiana. Jumping into the Gulf Run, we're very excited to bring that on by the end of the year. We've got the 1.65. We have 1.1 Bcf that's sold to Golden Pass for a long-term contract. We also have secured another 350 of that. We've got a couple of hundred left that we are trying to extract as much value as we can as we finalize that. We're continuing to evaluate what the next step is. Is it adding compression and an extra Bcf? Or is it looping the entire 42-inch? As we get closer and arrive at FID, we hope in the first quarter of next year on the Lake Charles, that will be very much the emphasis behind us probably looping that line, that 42-inch. So that is probably the route we will end up taking once we get to FID there. But we also may do that anyway. In addition to that, we are really excited about values on Tiger and on CP, which will be Gulf Run. They're narrowing down to $0.04, $0.05, $0.06, $0.07, almost given the past way, and we are seeing that move out. We're excited to see that. We're seeing wider margins. We're seeing a much higher value for gas east of Louisiana as you go further, and there's a real need as you get closer to Florida. So we're very pleased with where we sit, and we will fully utilize those to the maximum for our revenues and our unitholders.

And I have both to locate the ethane export expansion based on who wins the World Series, but I don't want to.

Our next question will come from Ann Salisbury with Bernstein. Please go ahead.

Your NGL segment saw some growth this quarter due to the Medford frac being down. There are some new third-party fracs expected to start by the end of this year and early next year. Do you see this as a temporary boost for just one quarter, or do you believe you can sustain that additional earnings over several quarters?

Ann, this is Mackie again. Yes, I'll kind of step back. We've really seen a tightening of T&F for the last 18 months or so, and over the last five or six months, early summer to mid-summer, it really got tightened. Now, similar to some of the spreads on some of our other assets, we're seeing it move out. If you just look at the frac spreads, we are very optimistic that whatever frac capacity we have available before our eighth frac comes on will have significant revenues from that capacity. We see a very tightening of it. Yes, there's a frac coming on. One of them that’s coming on isn't that accessible to Mont Belvieu, whereas the fracs that are more accessible to Mont Belvieu, like ours and a few others, really aren't until the third and fourth quarter and into 2024 of next year. So there's going to be a tightening of capacity there; it already is at Mont Belvieu, and we hope to benefit from that as the value of fracking — fractioning widens.

And then can you remind us currently on your Permian crude pipeline, just roughly how much is still take-or-pay? And if there's any recontracting interest yet on the part that's not take pay or if you see that happening in the next couple of years when other pipelines start to roll off?

Yes. I don't have the exact numbers top of my head of how much take-or-pay there is, but it's a little bit of a loaded question in the sense of what exactly that means. But we feel that pipe up as much as we can on that basis. There is some portion of it locked in at wider spreads than where we see today. But similarly to what we just talked about, we believe even with the overbuild of crude oil pipelines, we will see widening. The reason we do is some of our customers is what we say on every earnings call and at other times is that we're not just offering Midland to Nederland or Midland to Houston service; we're offering blending, we're offering storage. We're offering access into Bayou Bridge or into the header at or to feed into the refineries as well as at the header systems and other pipeline systems in Houston. So we did see that start to move out several months ago, and we do expect that to move out more. But we don't have all that old contract that really lit margins. Most of that's kind of way. We are filling that in daily, monthly, and also doing term deals at what we see as slowly widening spreads.

Our next question will come from Michael Blum with Wells Fargo. Please go ahead.

Just had a couple of questions. One, can you talk about once you get to that $1.22 distribution? I guess, looking into next year, how are you thinking about buybacks, distribution growth, and I guess, especially in light of rising interest rates?

And we're so thankful to be talking about it from that standpoint versus the alternatives. I will tell you, at this point, we are planning this quarter by quarter as far as the distribution side of it and looking at it. There's not been dialogue on anything around the distribution growth. We'll wrap up 2022 with our targets, so we're going to continue to look at that. When it comes to unit buybacks, I don't want to say that we're going to continue to look at paying down that debt. We really want to get that leverage target in that four to four and a half range. And we'd be quite happy to get closer to the four range. We will have some opportunities next year with all the free cash flow that we're seeing and some of the debt maturities. We're going to continue to look at that. So we would put that up higher than unit buybacks to get to lower leverage but also the great capital projects that we're talking about. Those likewise set up a little bit higher than the unit buybacks. So let us get to that point. It is a good healthy discussion we have quarter-by-quarter with our Board of Directors as we look at the distribution and how we're going to do that. But right now, our target is to get to the $1.22. And we've made great progress, 70% higher than where we were. So we've executed on it, and it's really looking like we've got ourselves to a great place from that standpoint.

And then just wanted to ask on the potential cracker. So obviously, there's some weakness in petchem fundamentals right now, spreads, etc. Does that give you pause in terms of making that investment? Does that make you more likely to want to make that investment? And does it change the calculus between buying versus building?

Mike, this is Mackie. It certainly gives pause to people that we're trying to take capacity with right now. That's for sure. But the way we're looking at that project is we're not spending a material amount of dollars at this point. Coincidentally, as of today, we have filed a second permit. So in the last couple of days, we filed our TCEQ permit and we filed our core wetlands permit. So that kind of gets us going. That's those are 18- to 24-month processes depending on whether it goes to full-on EIS and all that. So we've kind of started that and done all that work. Our team is working diligently with a number of players throughout the country and really the world. And there's a great deal of interest. We do believe we'll get there. But to answer your question, we're not going to get there unless we have sufficient commitments to get us a rate of return that meets our threshold. So if the hesitancy to sign up right now because the crack spreads are so narrow compared to what we need to build it, we won't get anything signed. But we know the industry, as you and quite a many out there know, is very cyclical. You can generate a lot of income in a short period of time in the good times, and then there are tough times. So we're approaching this project like we do everything. We're not going to speculate on this to hit a home run or not; we're going to line this up with both our partners potentially. As we've said, we anticipate we'll own about 25% at the end of the day, and we expect to bring in partners who will also be part of the yield take. But as we go around all these customers, we continue to hear and believe that this will be the most unique and the most flexible cracker in the world. If you look at the upstream pipeline as we talked about before, our pipeline network to all the refineries to bring butane products and gasoline by-products as well as we've got four pipelines feeding, and we can see enormous amounts of ethylene, propane, butane in natural gasoline to Nederland. And then you look at the takeaway, we'll have the ability to tie the storage for our customers and/or to deliver into ethylene and propylene pipelines and into the export market. So once again, it's way early, but that's going to be one of those projects that if we get to FID, we'll have sufficient commitments, some great customers to have a great project and a rate of return, and we'll have some good partners.

Our next question will come from Keith Stanley with Wolfe Research. Please go ahead.

Two clarifications. First, Tom, it seems like you were alluding to probably paying down some debt again next year to try to get to the low end of the leverage target. I know the company has a decent amount of maturities for next year. Can you just talk to how you're planning on addressing that? Is it pay some down cash? Would you look to issue new debt here? Or would you look to leverage your short-term borrowing facilities more?

Yes, Keith, we're clearly looking at paying down as much as we can. There's still a little bit to go as far as getting to our free cash flow. But in fairness, we do have very good capacity left on our revolver from our credit facility. So we've got options as to how to navigate that, and we're going to be careful. I don't really want to get out in front of it and try to pre-announce. But you nailed it when you said looking at trying to pay down as much as we can of it, if not moving some of it to the revolver only because when you look out over the remainder of the year and you see what the free cash flow continues throughout the year, we have a lot of financial flexibility right now. That's the way I'd like to leave it, and we're going to play the best options we can of reaching all the targets that we want.

And on Lake Charles, so it sounds like the base case is still for up to a 75% sell-down. But when you talked about 2023 CapEx, that was one of the areas of uncertainty when you look to next year. Are there scenarios where you could possibly need to fund a meaningful amount of Lake Charles next year as part of your capital budget? Or is that pretty unlikely?

Funding a meaningful amount next year will probably be more of what I would call unlikely; probably very unlikely that we would have to do that for next year. But we'll see where it all goes. But at this point, based upon the way we would move through 2023, I'll leave it in the unlikely category.

And our last question today will come from Brian Reynolds with UBS. Please go ahead.

Maybe as one quick follow-up on the capital allocation. I was curious if you could just opine on how the desire for a credit rating upgrade influences the timing and financial flexibility for buyback or an additional distribution base? And then perhaps on just the growth CapEx. Having a little bit of priority was just curious as it relates to '23 CapEx specifically, if there's just limited upside to that number at this point given that Lake Charles seems to be pushed out a quarter or two at this point?

Yes. I think the best way to start with that one is the target, the 4 to 4.5. Pretty much all three agencies put out there that you get to that closer towards maybe the lower end of that range. You're now looking at upgrades. And that is important to us. We want to continue to get into that 4, 4.5 and get into that next higher notch on the rating agencies. All the dialogue we had with them has been very constructive, by the way. They hear us. We believe we've got a lot of credibility with them, and we're going to continue to have this dialogue with them. It remains a priority to continue to pay down the debt to get within those leverage targets that we've got laid out there. The capital portion of your question, we really do. When you look at our entire infrastructure, the critical mass we have, we look at these capital projects, they're looking at a much broader benefit that comes to Energy Transfer. When the question was asked earlier about what are the drivers on the guidance, moving up. A lot of that is around optimization. We talked about the Lake Charles LNG; you heard us talk a lot about petrochemical projects. We're not trying to own a large percentage of many of these assets. What we're trying to do is look at the demand side as much as we look at the supply side. These capital projects are important. We do give them a high priority, and we’ll continue to be very disciplined in how we spend every dollar.

And I guess just as a quick follow-up, it just seems like there's limited upside to '23 CapEx given those comments at this point.

Yes, I'm sorry, could you please repeat that last part?

New projects coming into the backlog, it seems pretty set from the slide deck that you provided that it doesn't seem like any new large projects have come into '23 CapEx and it's really more a '24 and '25 event if those projects come to fruition.

Yes, that's a fair assumption. I'll just leave it as a fairly immaterial amount as far as 2023.

I might have on the second half of that; I ask again. I didn't understand this is Mackie again. On Gulf Run, yes, we sold 1.1 Bcf a day to Golden Pass, and they're paying demand charges. So they are getting geared up to use some of that. But the way we look at that pipeline is like we look at all our assets, we will do everything we can to fully utilize in the capacity that's not being utilized, regardless of whether it's demand charge being paid for or not. I'm sorry, what was the second half?

Just how much open capacity does Energy Transfer have on the nat gas takeaway side for '23?

As I mentioned earlier, we've got about 250,000 a day. By the end of January, we should have close to approximately 300,000 a day across the state.

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

Yes, and this is Mackie. I don't know why I'm compelled to do this, but I'm making a statement real quick. The reason is we've got an election coming up here in about a week. And also what's driving it is this relentless attack on fossil fuels. I have teenage boys that are asking if fossil fuels are going to go away tomorrow. So I'm going to make a quick statement that ironically, fossil fuels changed humanity. If you look over the last 20 years, these aspirational policies in trillions of dollars with subsidies and tax expenses and credits have barely put a dent or haven't affected the growth in fossil fuels. In fact, I think 3% of electricity production in the world comes from renewables. As everybody knows on this call, there are thousands of products that we use every day. Fossil fuels have increased our lifespans, improved our health, and increased our standard of living tremendously. It's made us more mobile with planes, trains, and automobiles. It's just been impactful to our lives. I think it's fair to say that modern life with a reasonable standard of living and affordable energy is simply not possible without fossil fuels. The logical and rational politically led to renewables will have devastating impacts on cost, reliability, and security of energy around the world, as we're seeing in Europe and other places. We find it interesting that the co-founder of a large environmental access organization has come out fairly recently and said that he now left. One of the reasons was that their METRO became within the organization that doesn't matter what the truth is; it matters what the public believes the truth is. That environmental movement has turned into a political movement perpetuated by the media and the administration. Statements recently play a key role in reinforcing that the Energy Transition is not feasible in any meaningful time frame. It's a dangerous dilution to base policies on the idea that such a transition is even possible. What we believe is to reduce submissions across this world is to build more natural gas-fired generation to replace coal-fired generation, send more natural gas liquids around the world, especially to undeveloped countries that use wood, biomass, and animal waste. That's the solution to all of this. Ironically, we have an administration that came into this with very hostile administrators at FERC, EPA, and SEC to attack our industry. They're not allowing new leases, not allowing drilling permits, slowing down pipelines in service for years, and taking them out of service. We have an election coming up, and we start gaining the strategic petroleum reserve. We approach countries like Venezuela and Iran, who promote terrorism and hate the U.S. to produce more oil. What do we do? We attack our oil and gas producers and say they're going to be penalized for not producing more. If this doesn't seem like a sitcom or Saturday Night Live skit, it'd be funny if it weren't so tragically sad. Sorry to get on this soapbox tonight, but I'm tired of being attacked in the fossil fuel business. I just wanted to make my voice heard. So anyway, Tom, do you want to close?

Thank you all for joining us today. We truly appreciate your support and look forward to speaking with you soon.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.