This conference call transcript was computer generated and almost certianly contains errors. This transcript is provided for information purposes only.EarningsCall, LLC makes no representation about the accuracy of the aforementioned transcript, and you are cautioned not to place undue reliance on the information provided by the transcript.
spk07: Good afternoon, and welcome to the Energy Transfer Third Quarter 2022 Earnings Conference Call. All participants will be in a listen-only mode. Should you need any assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your telephone keypad. To withdraw a question, please press star, then two. 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.
spk14: Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer Third Quarter 2022 Earnings Call. I'm also joined today by Mackie McCree 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 Security 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 10Q for the quarter ended September 30, 2022, which we expect to be filed this Thursday, November 3rd. 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 non-recurring $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 product 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 25th, we announced a quarterly cash distribution of 26.5 cents per common unit, or $1.06 on an annualized basis. This distribution will be paid on November 21st to unit holders of record as of the close of business on November 4th. 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 30.5 cents 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 million. 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 non-cash 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 needle and terminal, as well as a record volumes on the combined Mariner East pipelines. And 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 volume 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 satellite's contract going into effect on July 1st, which doubled the volume commitments from the initial term. Year to date, we have loaded approximately 29 million barrels of ethane out of Nederland, and for 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 MMBTUs per day compared to 13 million MMBTUs 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 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 a 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 interstate 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 shell 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, FGT, SESH, 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, as well as the addition of the Enable assets. Utilization of our HPL system remains strong due to the increased demand for gas takeaway, and our RIGS 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 non-core assets at an attractive valuation and utilize the cash proceeds to further deleverage our balance sheet and redeploy capital within our U.S. footprint. And 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 at our ongoing growth projects. Year-to-date, Lake Charles LNG has executed six LNG offtake agreements for an aggregate of nearly 8 million tons per annum, including a 20-year LNG agreement with Shell NALNG 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 and more industry participants in conjunction with LNG offtake agreements. We have recently signed non-binding 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 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 of transporting 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 Needland terminals, these commitments provide us with the optionality to initially expand at either terminal. Construction of Frac 8 continues this schedule, and we expect it to be in service in the third quarter of 2023, which will bring our total Montbellevue fractionation capacity to over 1.1 million barrels per day. Construction of our new 200 million cubic foot per day gray wolf processing plant in the Delaware Basin is underway. This plant 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 bare 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 recently finished, and we expect to complete a modification 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 Hainesville Shell 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 from Golden Pass LNG, and we recently concluded a non-binding open season on Gulf Run due to the 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 de-bottlenecking work on our ACES 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 pet chem project along the Gulf Coast or acquire pet chem 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, interstate, and NGL refined product 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 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 cashflow 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. And 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 four to four and a half times by the end of 2022. and we will 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 unit holders. 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.
spk07: We will now begin the question and answer session. To ask a question, you may press star, then 1 on your touchtone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then 2. We ask that you please limit yourself to only one question and one follow-up. At this time, we will take our first question, which will come from Jeremy Tonant with JP Morgan. Please go ahead.
spk10: Hi, good afternoon. Hello, Jeremy. Just want to kind of start off with the LNG project with Lake Charles, if I could. Just walking through a number of kind 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.
spk02: Hi, Jeremy. Great question. A lot of moving parts to your question, but as there is 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's had an impact on pricing of liquefaction. We have made good progress in increasing our liquefaction charge as we progress with new contracts, and 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 with the brownfield facility with storage tanks and docks. We're really good position to get to the goal line.
spk10: Got it. That makes sense there. 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, 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.
spk15: Yeah, 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 Permanent Basin, we see these wide spreads. We do, like most industry, believe that as we get deeper into this year and throughout most of the next two years, it's going to get bad. The bases are going to blow out. We do sit in a very fortunate situation that we do have capacity available today that actually gets a little bit more 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 do have a team diligently working toward getting to the finish line on Warrior Ends. after the announcement of this, uh, other 42 inch line to, it's going to move a couple of BCF across. It's kind of slowed things down. Uh, but we will be the next pipeline that's announced out of there. We are by far the best option for anybody coming out of the permanent basin, whether it's Delaware or Midland. Uh, we provide Katie ship channel as well as other, uh, you know, really good markets off of our intra interstate systems. So we'll keep our head down, but we're going to be very prudent when we make that decision. And, uh, We hope to do that in the next couple of quarters.
spk10: Got it. That makes sense. I'll leave it there. Thanks. Thank you.
spk07: Our next question will come from Chase Mulvhill with Bank of America. Please go ahead.
spk06: Hey, good afternoon, everybody. I guess, you know, question on FAA. You know, obviously, I think prices have softened a little bit here. You know, it 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?
spk15: Chase, this is Mackie. Yeah, we're just so pleased at what we've done as far as building out Marcus Hook and building out Nederland. around ethene. As we've said, we now have sufficient contracts to expand. However, that'll take three or four years to expand once we make the decision whether it's in the north or along the Gulf Coast. But the way we look at rejection or recovery just depends on the region. So from an entity transfer standpoint, we may be rejecting ethene in some areas and recovering it in others. But right now, we're ethylene prices are and where gas prices are, we are recovering ethylene in most of the regions. As you know, a tremendous amount of ethylene is rejected daily up in the Northeast. There's a lot of available ethylene up there for our projects. And then as we head toward a decision to expanding at either Marcus Hook or at Nederland, we'll look at maximizing what we have today. As we've said in our opening remarks, satellite kicked into their second tranche, so we've got that. But we also have additional capacity that we will be fully utilizing on a month-to-month basis as the market dictates.
spk06: Okay. Another follow-up is just really on Lone Star. If I'm right, I think you've got some latent capacity there. But, you know, kind of what I'd like to ask is if there's 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 when your competitor has actually delayed one of their expansion projects, you know, on NGL, on Chinook, and, you know, maybe somebody else announces something, you know, here later this week. But just kind of curious because you do have some latent capacity and just kind of if there's an opportunity for you to work with, you know, some of your peers and offload some of those volumes and, and, you know, help the industry kind of be a little bit more capital efficient.
spk15: Yeah, this is Mackie again. Yeah. I'd love to know who you're talking about. Uh, that's interesting, but please get my telephone number. We certainly would offer transportation to anybody. Uh, through our, I mean, natural gas, liquid, sterile pipelines. And, uh, You know, we feel real good of where we're at. Over the last several weeks, we've set records out of the Permian. I think we exceeded 850,000 barrels a day. And actually, around our NGL business, we almost hit a million barrels here this past week of fractionation at Mount Bellevue with these colder temperatures. So we have the ability to move more volume, significantly more volume out of the Permian as our two new cryogenic plants come on. by the second quarter of next year. So we certainly have built it to accommodate our own barrels. But you bet, if anybody's out there and they're trying to get their barrels to mock-bale a few, we would love to hear from them.
spk06: All righty, perfect. I'll turn it over. Appreciate the cover.
spk07: Our next question will come from Mark Solisito with Barclays. Please go ahead. Hey, good afternoon.
spk11: So maybe following up on one of the earlier questions around Waha basis exposure, I think a few quarters ago, You referenced a couple hundred MCF that was open with another couple hundred becoming available over the next couple years. So just wondering if you are sharing an update, if you could provide that.
spk15: Sure. I'll quantify it a little bit. No matter what I say, we are in negotiations on Warrior, and that very easily could impact what capacity is available the next year or two because that kind of comes into those negotiations. But notwithstanding that, we've got about – 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 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.
spk11: Great. That's very helpful. 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 variable between the lower and upper end of the revised range? Curious if you have any color there.
spk13: Yeah, Mark, this is Tom Long. The short answer is that the legal settlement was not included in the previous guidance. So this guidance you see right now that we came up with, 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, the $12.8 to $13 billion, does now include both of those. But as we highlighted in the prepared remarks, we are expecting that the $12.8 or most of the 130 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. And Mark, as far as I think the rest of your questions that you were going through, you know, we've always stayed fairly conservative on the commodity prices, and we continue to do that. I think you see with where some of the prices, at least on the natural gas side of it, are going here 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've not answered here.
spk11: 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?
spk13: It continues to be pricing that was running a little higher than what we 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.
spk04: Got it. Appreciate the time.
spk05: Thank you.
spk07: Our next question will come from Gabe Maureen with Mizuho. Please go ahead.
spk08: Hey, good afternoon, guys. 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, 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 things may be headed for CapEx next year?
spk13: Yeah, that's always a good question, Gabe. We work hard in trying to hold off until that fourth quarter. And, you know, 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, you know, the Lake Charles LNG to the Warrior to several other items, Pet Chem, etc., So it's really difficult probably to give you that 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've given this year, the $1.8 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.
spk08: Got it, Tom. Thank you. 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 and 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 Run and the possibility of expanding that with or without Lake Charles.
spk15: Okay. Hey, Gabe. It's Mackie again. Yeah, what an exciting area. My goodness, who could have ever seen this? Maybe Auburn and Clinton saw it years ago. But when you see these wells coming out in the 50,000, 60,000, 70,000 day and holding out for a while, what a great place to own three 42-inch pipes and a whole lot of other systems. So we're excited. Very excited about that. You touched on some things like we said earlier in our remarks, Riggs is pretty full. So we're looking at backhauling that into some of our enable assets to get down to Carthage and also to get to our Gulf Run and Tigra pipelines. So we're doing everything we can to utilize capacity in both directions on all of our pipelines in North Louisiana. Jumping to Gulf Run, very excited to be bringing 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 secured another 350 of that. We've got a couple hundred left that we are trying to extract as much value as we can. We finalized that, and we're continuing to evaluate what is the next step. Is it adding compression and adding a 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, year on Lake Charles, that will be very much the impetus behind us probably looping that line, that 42 inch. So that is probably where we'll end up once we get to FID there, but we also may do that anyway. In addition to that, as you said, we're really excited about values on Tiger and on CP, which will be Gulf Run. They narrowed down to four, five, six, seven cents, almost giving it past the 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 a real need as you get closer to Florida. So we're very pleased to where we sit, and we will fully utilize those to the maximum value we can for our revenues and our unicorns.
spk08: Thanks, Mackie, and I vote to locate the ethane export expansion based on who wins the World Series, but I'm not sure if that's... Thanks for the time, guys. Appreciate it. Thank you, Jake.
spk07: Our next question will come from Anne Salisbury with Bernstein. Please go ahead.
spk01: Hi. Your NGL segment was boosted, I think, a bit in the quarter by the Medford frac being down. I think that there's some new third-party fracs starting by the end of the year and then early next year. So do you kind of view this as a, like, a one-quarter boost? Or do you, in your view, can you kind of maintain that incremental earning over multiple quarters?
spk15: Hello, Ann. It's Mackie again. Yeah, I'll kind of step back. We've really seen a tightening of TNF for really that last 18 months or so. I know the last five or six months, early summer, midsummer, it really got tightened. And now, similar to some of the spreads on some of other assets, we're seeing it move out. So if you just look at the frack spreads, we are very optimistic that whatever frack capacity we have available before our eighth frack comes on, that that 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 Bellevue. The fracs that are more accessible to Mont Bellevue, like ours and a few others, really aren't until the third and fourth quarter and into 24 of next year. So there's going to be a tightening of capacity. There already is at Mont Bellevue, and we hope to benefit from that as the value of fracking fractioning their widens.
spk01: That's really helpful. Thank you for that, Kelly. And then can you remind us currently on your Permian crude pipelines just roughly how much is still take or pay and if there's any recontracting interest yet on the part that's not take or pay or if you see that happening in the next couple of years when other pipelines start to roll off?
spk15: Yeah, I don't have the exact numbers in my head of how much take or pay, but it's a little bit of a loaded question in the sense of what exactly that means. But we fill that pipe up as much as we can on a daily basis. There is some portion of it that is locked in at wider spreads than where we see today. But similar to what we just talked about, we believe, even with the overbuilt of crude oil pipelines, we believe we'll see widening. And the reason we do with 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 Midland or Midland to Houston service. We're offering blending, we're offering storage, we're offering access into Bayou Bridge or into the header and we're offered 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 here several months ago and we do expect that to move out more, but we don't have all that old contracts at really wide margins, most of that's gone away, and we are filling that in daily, monthly, and also doing term deals at what we see as slowly widening spreads.
spk05: Great. Thanks a lot.
spk07: Our next question will come from Michael Bloom with Wells Fargo. Please go ahead.
spk09: Thanks. Good afternoon, everyone. Just got a couple questions. Can you talk about once you get to that $1.22 distribution, I guess looking into next year, how are you thinking about buybacks versus distribution growth, and I guess especially in light of rising interest rates?
spk13: That's a great question, Michael, and we're so thankful to be talking about it from that standpoint versus the other alternatives. So we... I will tell you at this point, we are playing 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 after the buck 22 in meeting our target. So we're going to continue to look at that. When it comes to unit buybacks, I 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. We'd be quite happy to get it to the closer to the four range. We're going to 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. We would put that up there higher than unit buyback to get to the lower leverage, but also the great capital projects that we're talking about. Those likewise sit up a little bit higher than the unit buyback. Let us get to that point. It is a good, healthy discussion we have quarter by quarter with our uh board of directors as as we look at the the distribution and how we're going to do that but right now our target is to get to the get to the buck 22 and my gosh we've made great progress on that it's it's great to be here at this level it's 70 higher than where we were so we've we've executed on it and it's it's really looking uh uh like we've we've got ourselves to a great place uh from that standpoint
spk09: Got it. That makes sense. Thanks. And then just wanted to ask on the potential cracker. So obviously there's some weakness in pet chem fundamentals right now, spreads, et cetera. 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?
spk15: Hey, Michael. This is Mackie. You know, 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 our second permit. So in the last couple of days, we've filed our TCEQ permit and we've filed our core wetlands permit. So that kind of gets us going. Those are 18 to 24 month processes, depending on whether it goes full-blown 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 beds are so narrow compared to what we need to build it, then we won't get anything signed. But we know the industry, as you and probably many out there know, is very cyclical. And you can generate a lot of income in a short period of time in the good times, and then there's tough times. And so we're approaching this project like we do everything. We're not going in this to speculate, to try to get a home run or not from time to time. 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 that will also be part of the yield that they'll take. But as we go around to 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 that we talked about before, pipeline network to all the refineries to bring butane products and gasoline byproducts, as well as we've got four pipelines that are feeding and can feed enormous amounts of ethylene, propane, butane, and 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, way early, but that's going to be one of those projects that If we get to FID, we'll have sufficient commitments from great customers to have a great project and a rate of return, and we'll have some good partners.
spk09: Thanks for all that. Appreciate it.
spk07: Our next question will come from Keith Stanley with Wolf Research. Please go ahead.
spk12: Hi. Thank you. Two clarifications. First, Tom, it seemed 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 with cash and then would you look to issue new debt here or would you look to leverage your short-term borrowing facilities more?
spk13: Yeah, 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 what our free cash flow is going to be. But in fairness, we do have a 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. 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 is the way I'd like to leave that, and we're going to play it the best options we can of reaching all the targets that we're going after.
spk12: Great. 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, Lake Charles 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?
spk13: I think finding a meaningful about next year will probably be more what I would call unlikely, probably very unlikely, that we would have to do that for next year. We'll see, you know, see where it all goes. But at this point, based upon the way we would move through it through 2023, we'll leave it in the unlikely category.
spk04: Thank you. And our last question today will come from Brian Reynolds with UBS.
spk07: Please go ahead.
spk03: Hi. Good afternoon, everyone. 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 a buyback or an additional distribution raise. And then maybe perhaps on just the growth capex, you know, having a little bit of priority there.
spk13: 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 thanks yeah i think the best way to start with that one is the the target the four to four and a half pretty much all three agencies put out there that you get to that closer toward maybe the lower end of that range you're now looking at upgrades. And that is important to us. We really do want to continue to get into that four to four and a half and get into that next higher notch on the rating agencies. All the dialogue we've had with them has been very constructive, by the way. We think that they hear us. We think we've got a lot of credibility with them. And we're going to continue to have this dialogue with them. And so it remains a priority, I would say, to to continue to pay down the debt to get within those targets, leverage targets that we've got laid out there. The capital portion of your question, when you really look at our entire infrastructure, you look at the critical mass we have, et cetera, when 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 continuing to get moved up, and a lot of that is around the optimization. When you really look at all the various access we have to some of the very best pricing points and the flexibility we have around that, a lot of these capital projects are very, very important, and we continue to work on the demand side. We've talked about the Lake Charles LNG. You've heard us talk today a lot about the PET chem. We're not trying to own a large percentage of a lot of these assets. What we're trying to continue to do is look at the demand side as much as we look at the supply side. So 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.
spk03: Great. And I guess just as a quick follow-up, it just seems like, you know, there's limited upside at 23 capex, you know, given those comments at this point.
spk05: Yeah, I'm sorry. Do you mind, Brian?
spk03: In terms of new projects coming into the backlog, it seems pretty set from the slide deck that you guys provided that, you know, it doesn't seem like any new large projects would come into 23 CapEx. It's really more about, you know, a 24 and 25 event if those projects come to fruition.
spk13: Yeah, that's a fair assumption. I would just leave it as a fairly immaterial amount as far as 2023.
spk03: Great. Thanks. And then just quickly on the last question, I know we talked a lot about Permian and Hainesville spreads. I'm curious, is Golden Pass have open capacity all year during 2023 or Gulf Run have open capacity given Golden Pass can come online for another year or so and can effectively benefit from the spreads all year? And then second, is there an open capacity number for the Permian that you guys have provided for 23? That's it for me. Thanks.
spk15: I might have the second half of that ask again. I didn't understand it, but this is Mackie again. On Gulf Run, yes, we sold 1.1 BCF a day to Golden Pass, and they're paying demand charge. So they are getting geared up to where they actually be able to use some of that. But the way we look at that pipeline is like we look at all of our assets. We will do everything we can to fully utilize any of the capacity that's not being utilized, regardless of whether it's demand charge being paid for or not. And I'm sorry, your second question, second half?
spk03: Just how much open capacity does energy transfer have on the NAC gas takeaway side for 23?
spk15: They already talked about it earlier. So, yeah, as I mentioned earlier, we've got about 250 now. And by sometime in the end of January, we should have close to, say, approximately 300,000 a day across the state.
spk05: Okay. Thank you for the clarification. Have a good rest of your evening, everyone. Thank you.
spk07: And that concludes our question and answer session. I would like to turn the conference back over to Tom Long for any closing remarks.
spk15: Yeah, and this is Mackie. I don't know why I'm compelled to do this, but I'd like a statement real quick. And the reason I am, we've got an election coming up here in about a week. And also what's driving it is this attack, relentless attack on fossil fuels. And I have teenage boys that are asking if fossil fuel is going away tomorrow. So I'm going to make a quick statement that will end kind of ironically, and that's that fossil fuels change humanity. If you look at over the last 20 years of these aspirational policies in trillions of dollars with subsidies and with tax incentives and credits, it's barely put a dent in or hasn't been at all the growth in fossil fuels. In fact, I think 3% of electricity demand in the world I mean, not demand, of electricity production in the world comes from renewables. And as everybody knows from this call, there's thousands of products that we use every day. And fossil fuels has increased our lifespans. It's increased our health. It's increased our standard of living tremendously. It's made us more mobile with planes, trains, and automobiles. It's just been a, you know, it's so impactful to our lives. And 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. And the illogical, irrational, politically-led rush to renewables will have devastating impacts on the cost, reliability, and security of energy around the world, as we're seeing in Europe and other places. And we find it interesting is that the co-founder of a large environmental activist organization has come out fairly recently and said that he's now left And one of the reasons was is that their mantra became within the organization that it doesn't matter what the truth is, it matters what the public believes the truth is. So that particular environmental movement has turned into a political movement that is really being perpetuated by the media and by the administration. So statements have been made recently, some kind of plagiarizing here is the energy transition is not feasible. In any meaningful timeframe, it is a dangerous delusion to base policies on the idea that such a transition is even possible. And so what we believe in energy transfer is to reduce emissions around this world is build more natural gas-fired generation to replace coal-fired generation, send more natural gas liquids around the world, especially to undeveloped countries who are burning wood and and biomass and animal waste and everything else. That's the solution to all this. And so I'll end on this irony is that we have an administration right now that came into this and has put in very hostile administrators at FERC and EPA and SEC to attack our industry. And that's gone on for a while within this administration where they're not allowing new leases, not allowing drilling permits, not allowing or slowing down approvals of pipelines and even going after pipelines that have been in service for years and trying to take them out of service. And lo and behold here, we've got an election coming up and we start draining the strategic petroleum reserve and we come out with approaching countries like Venezuela and countries like Iran who just promote terrorism and are you know, hate the U.S. to try to get them to produce more oil. And then what do we do the last few days? We come out and attack our oil and gas producers and say they're going to be penalized for not producing more. I mean, my goodness, if this doesn't seem like a sitcom or a Saturday Night Live skit, it'd be funny if it wasn't so tragically sad. And sorry to get up on this podium, but I guess we're kind of tired of being attacked in the fossil fuel business. I'm tired of my boys hearing about it. So anyway, Tom, you want to close?
spk13: Listen, as always, we thank all of you for joining us today, and we really do appreciate your support. Look forward to talking to you in the near future.
spk04: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.
Disclaimer