Welcome to the Energy Transfer Q2 2022 Earnings Conference Call. My name is Darryl, and I will be your operator for today's call. As a reminder, this conference is being recorded. I will now turn the call over to Tom Long, Energy Transfer's Co-CEO. Mr. Long, you may begin.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer second quarter 2022 earnings call. I'm also joined today by Mackie McCrea and other members of the senior management team, who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon, as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our quarterly report on Form 10-Q for the quarter ended June 30, 2022, which we expect to be filed tomorrow, August 4. I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website. I'd like to start today by looking at some of our second quarter highlights. We were pleased to report another strong quarter, during which we generated adjusted EBITDA of $3.23 billion and DCF attributable to the partners of Energy Transfer, as adjusted, was $1.88 billion. This resulted in excess cash flow after distributions of approximately $1.17 billion. On an incurred basis, we had excess DCF of approximately $730 million after distributions of $710 million and growth capital of approximately $440 million. On July 26, we announced a quarterly distribution of $0.23 per common unit or $0.92 on an annualized basis, which represents a more than 50% increase over the second quarter of 2021. As a reminder, future increases to 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. Operationally, our diverse asset base saw throughput increases across all of our segments as rig counts continue to improve across the U.S., and we saw record midstream volumes as well as record throughput on our NGL transportation pipelines, Mont Belvieu fractionators and terminals. In addition, construction continues to progress on several of our growth projects, which I will provide more details on shortly. I'll start with a brief update on the sale of Energy Transfer Canada. In March of this year, we announced a definitive agreement to sell our 51% interest in Energy Transfer Canada for cash proceeds of approximately $270 million. In addition, the sale is expected to reduce our consolidated debt by approximately $550 million. This sale allows 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. The transaction remains on track, and we continue to expect it to close this month. This week, Energy Transfer signed an agreement to acquire Woodford Express, LLC, a Mid-Continent gas gathering and processing system for approximately $485 million. This bolt-on opportunity will provide a roughly 450 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 with active proven producers. We're excited to have these strong assets, quality customer contracts and established operations to our footprint in the Mid-Continent, all at an attractive valuation that will be immediately accretive to Energy Transfer unitholders. This transaction is expected to close by the end of the third quarter of this year, subject to regulatory review and other customary closing conditions. Now I'll walk you through recent developments and other growth projects. Year-to-date, Lake Charles LNG has executed five LNG offtake agreements for an aggregate of 5.8 million tons per annum. The purchase price in all these agreements is indexed to the Henry Hub benchmark plus a fixed liquefaction charge and the LNG will be delivered onto customer vessels on an FOB basis. The agreements will become fully effective upon the satisfaction of the conditions precedent by Energy Transfer LNG, including reaching FID. We're also in active negotiations with a number of other high-quality customers as we expect to make announcements of additional offtake agreements in the weeks ahead. As we previously stated, we expect to finance a significant portion of the capital cost of this project by means sale of equity in the project to infrastructure funds and possibly to one or more industry participants in conjunction with LNG offtake agreements. We continue to work toward achieving FID for this project by the end of this year, and we expect that our anticipated announcements of additional long-term LNG offtake agreements over the next several weeks will keep us on track for meeting this objective. Upon completion of the LNG project, we expect to realize significant incremental cash flows from transportation of natural gas on our trunk line pipeline system and other Energy Transfer pipelines upstream from Lake Charles. Recent events in Europe highlight the importance of LNG from the United States, a country with abundant natural gas supply and government support for LNG exports. These events have caused companies around the world to place increased importance on long-term security of natural gas supply. We believe that our Lake Charles LNG project will be a significant factor in the long-term solutions for global energy needs. Looking at the Mariner East pipeline system, which is fully commissioned and capable of transporting more than 365,000 barrels per day, including ethylene. For the second quarter of 2022, NGL volumes through both the Mariner East pipeline system and Marcus Hook terminal reached new records. And in July, we set a monthly throughput record for the combined Mariner East pipes, and we continue to see strong utilization of these pipes. In addition, we recently completed work at the terminal to allow us to increase the ethane exports out of Marcus Hook, and we continue evaluating all options to achieve incremental ethane and LPG exports out of Marcus Hook until we complete an expansion of the terminal. At our expanded Nederland Terminal, NGL export volumes were very strong during the second quarter, including export volumes under our ethane export joint venture. We had a record in the second quarter for ethane exports and year-to-date, we have loaded nearly 18 million barrels of ethane out of the facility. The second tranche of the satellites contract went into effect on July 1, which doubles the volume commitments from the initial term and we loaded the first vessel under this demand-based agreement in July. For the full year 2022, we continue to expect to load more than 40 million barrels of ethane with that increasing to as high as 60 million barrels for 2023. In total, we continue to export more NGLs than any other company or country, and our percentage of worldwide NGL exports remains at approximately 20% of the world market. We continue to see an increase in NGL demand, both in the U.S. as well as from overseas customers seeking additional supply from the U.S., and we have sufficient commitments to move forward on 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 of initially expanding at either terminal. In addition, due to the significant tightening and fractionation capacity, we recently resumed construction on Frac VIII, which was more than half funded when construction was paused in 2020. Frac VIII is expected to be in service in the third quarter of 2023 and will bring our total Mont Belvieu fractionation capacity to over 1.1 million barrels per day. In the second quarter, our Permian Basin plant inlet processing volumes were approximately 2.2 Bcf per day, which is a new record and due to significant producer demand and continued growth around the Permian Basin gathering and processing assets, we are adding additional capacity to meet increasing production from the basin. Construction of our new 200 million cubic foot per day GrayWolf 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 this year. We are also moving forward with a second 200 million cubic foot per day processing plant in the Permian Basin. A portion of the growth capital associated with the Bear plant was included in our previous forecast, but we have accelerated some spending into 2022 to expedite the completion of this plant in order to meet growing demand. This plant is expected to be serviced 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. Once in service, the volumes from the tailgate of these plants will utilize our gas and NGL pipelines for takeaway, providing revenue streams for our intrastate and NGL segments on top of the incremental revenue for our midstream segment. In the meantime, we continue to heavily utilize the Permian project to provide operational flexibility between our processing facilities in the Delaware and the Midland Basin. Crude terminal throughput increased nearly 20% over the second quarter of last year, driven by increased upstream pipeline throughput, a strategic petroleum reserve drawdown, and additional market connectivity via the Ted Collins Link. At our Nederland Terminal, we have recently seen record crude volumes destined for the refinery and export markets. Overall, we expect to see exports continue to stay strong, largely due to the Ted Collins Link, which provides our systems with more market connectivity and access to deeper water as well as a quality management program, which ensures a higher-quality Midland WTI barrel as desired by our customers. We continue to make progress on the construction of the Gulf Run Pipeline, which is a 42-inch interstate natural gas pipeline with 1.65 Bcf per day of capacity. Gulf Run is backed by a 20-year commitment for 1.1 Bcf per day from Golden Pass LNG and will provide natural gas transportation between the Haynesville Shale and the Gulf Coast, connecting some of the most productive natural gas producing regions in the U.S. with the LNG export market. Gulf Run remains on schedule to be complete by the end of this year. We recently completed a nonbinding open season for Gulf Run due to growing producer demand. We were pleased with the results of the open season and customer discussions are ongoing, which will likely necessitate additional facilities beyond the initial design of 1.65 Bcf per day. Turning to the Warrior Pipeline Project, which is the most optimal solution for customers to transport gas out of the Permian in regard to timing, cost, flexibility, and access to premium markets. We are still evaluating the construction of this new intrastate pipeline from the Midland Basin to our extensive pipeline network south of the DFW area and remain optimistic that we can bring this project to FID. In the meantime, modernization and debottlenecking work on our Oasis pipeline continues, which will add an incremental 60 million cubic foot per day of much-needed capacity out of the Permian Basin. This capacity is expected to be available by the end of this year. We also continue to evaluate opportunities in the petrochemical space, which would include developing a project along the Gulf Coast as well as potential M&A opportunities. We are in discussions with a number of high-quality customers as we work to secure long-term tolling-type commitments prior to reaching FID. We also intend to have a significant partnership with one or more industry participants. If we are able to reach FID on this project, the ethylene and propylene production units would be synchronized into a world-class facility, providing unique feedstock and product flexibility. This would allow our customers to capitalize on access to the lowest cost feedstock through our comprehensive pipeline system as well as unparalleled access to downstream domestic and international markets through our pipelines, underground storage facilities and export terminals. Now for an update on our alternative energy activities. We are continuing to focus on efforts on reducing emissions across our pipeline. We have established an internal task force to coordinate these efforts in conjunction with third-party consultants. We recently entered into a letter of intent with Capture Point Solutions to pursue the joint development of a carbon capture and sequestration hub in Louisiana. This project would involve the installation of carbon capture equipment at several natural gas treating plants in the Haynesville area and the transport by pipeline of CO2 to a sequestration site that Capture Point is developing. Preliminary cost estimates as well as projections of cash flow and tax credits indicate that this project will generate an attractive financial return. We continue to pursue a number of projects related to carbon capture, including sequestration, enhanced oil recovery, and utilization projects. We are in active discussions with several developers of CO2 sequestration sites in close proximity to our existing facilities in other regions as well as our proposed Lake Charles LNG liquefaction facility. That would be good candidates for carbon capture and sequestration. Now I'll take a closer look at our second quarter results. Consolidated adjusted EBITDA was $3.23 billion compared to $2.62 billion for the second quarter of 2021. DCF tripled to the partners, as adjusted, was $1.88 billion for the second quarter of 2022 compared to $1.39 billion for the second quarter of 2021. Results for the second quarter included higher transportation volumes across all of our segments as well as a full quarter contribution from the Enable assets that were acquired in December of 2021. On July 26, we announced a quarterly cash distribution of $0.23 per common unit or $0.92 on an annualized basis. This distribution will be paid on August 19 to unitholders of record as of the close of business on August 8. This distribution represents a more than 50% increase over the second quarter of 2021. Turning to our results by segment, and starting with NGL and refined products. Adjusted EBITDA was $763 million compared to $736 million for the same period last year. This was primarily due to higher fractionation margin, higher transportation margin, as well as higher terminal service margin related to increased throughput at our Nederland and Marcus Hook terminals in the second quarter of 2022. NGL transportation volumes on our wholly owned and joint venture pipelines increased to a record 1.9 million barrels per day compared to 1.7 million barrels per day for the same period last year. This increase was primarily due to a ramp-up in volumes through our propane and ethane export pipelines into our Nederland Terminal and higher volumes from the Permian and Eagle Ford regions, as well as record volumes on our Mariner East pipeline. And our average fractionated volumes were also a record at 938,000 barrels per day compared to 833,000 barrels per day the second quarter of 2021. For our crude oil segment, adjusted EBITDA was $562 million compared to $484 million for the same period last year. This was primarily due to improved performance Bakken pipeline despite significant weather impacts during the quarter, increased throughput at our Gulf Coast terminals, as well as the addition of the Enable assets in December of 2021. Crude oil transportation volumes increased to 4.3 million barrels per day compared to 4 million barrels per day for the same period last year, driven by higher crude oil prices and strong refinery demand. For midstream, adjusted EBITDA was $903 million compared to $477 million for the second quarter of 2021. This was primarily due to the acquisition of Enable assets in December and an increase related to favorable NGL and natural gas prices as well as significant increases throughout the majority of our operating regions. Gathered gas volumes were 18.3 million MMBtus per day compared to 13.1 million MMBtus per day for the same period last year due to the addition of the Enable assets, increased production in South Texas in the Northeast, as well as additional gathering capacity from the Permian Bridge pipeline in West Texas. Permian Basin volumes continue to be strong, and Permian Basin inlet volumes remained at or near record highs. We are utilizing the Permian Bridge daily to optimize our available processing capacity as well as increasing our processing capacity in the area to accommodate incremental demand we are seeing. In our Interstate segment, adjusted EBITDA was $397 million compared to $331 million for the second quarter of 2021. During the quarter, we benefited from the addition of the Enable assets as well as increased rates and higher utilization on the Transwestern, Tiger, Rover, and Frontline systems due to more favorable market conditions and volume growth. We continue to see heavy utilization on many of our interstate pipelines, including Tiger, FGT, Stash, and Rover. And for the end of the second quarter, basis spreads on our interstate pipelines began to widen, creating stronger demand for capacity across our interstate network, and we expect that to continue throughout the rest of this year. And for our Interstate segment, adjusted EBITDA was $218 million compared to $224 million in the second quarter of last year. Absent benefits from Winter Storm Uri in both quarters, this segment would have been up approximately $30 million due to an increase in retained fuels related to higher natural gas prices. This was partially offset by lower storage optimization opportunities. Utilization of our HPL system remained strong due to increased demand from gas takeaway, and our rig pipeline system continues to flow at or near capacity due to increased activity in the Haynesville. Now turning to our 2022 adjusted EBITDA guidance. Given our strong performance in the second quarter as well as continued demand for our products, as we move through the rest of the year, we now expect adjusted EBITDA to be between $12.6 billion to $12.8 billion. This is up compared to our previous guidance of $12.2 billion to $12.6 billion. And moving to a growth capital update. For the six months ended June 30, 2022, Energy Transfer spent approximately $825 million on organic growth projects, primarily in the midstream, Interstate and NGL and Refined Products segments, excluding Sun and USA Compression CapEx. For full year 2022, we continue to expect growth capital expenditures to be between $1.8 billion to $2.1 billion, and we will likely be near the high end of that range as we have added new projects related to incremental demand that we are now seeing. These projects include the addition of capital related to frac A and accelerated spend on new processing facilities in the Permian and a new connection for Gulf Run, which are all offset by deferral of some spend to 2023 based upon project timing. Now looking briefly at our liquidity position. As of June 30, 2022, total available liquidity under our revolving credit facility was approximately $2.44 billion. We continue to expect to generate a significant amount of cash flow this year, which will be strategically allocated in a manner that best positions us to continue to improve our leverage, invest in high-returning growth projects, and return value to our unitholders. And we expect to continue to pay down debt throughout this year and beyond with excess cash flow from operations. We also expect to reach our leverage target range by the end of this year and going forward, expect our strong coverage and balance sheet strength to allow us to further prioritize growth within our capital allocation strategy. Our strong second quarter and performance was driven by significant volume growth across all of our segments as a result of improved production and increased demand, which we expect to continue throughout 2022. In addition, the Enable assets acquired at the end of 2021 continued to outperform our internal budget during the second quarter. We expect production improvements, market conditions, and strong domestic and international demand for our products to positively impact all of our segments for the remainder of this year. We are pleased with the progress we have made toward reaching our leverage target range. We remain focused on improving our financial flexibility and paying down debt in order to further strengthen our balance sheet. In addition, we will continue to evaluate returning additional capital to our equity unitholders through distribution growth on a quarterly basis. We remain bullish about the future of our industry and the growing worldwide demand for natural gas and natural gas liquids. As we look for additional ways to address the existing and new demand for our products, we will continue to evaluate and pursue strategic growth projects that enhance our existing asset base and generate attractive returns as part of the capital allocation strategy. Operator, please open the line up for our first question.

Our first question comes from Jeremy Tonet from JPMorgan. Go ahead, Jeremy.

Hi, good afternoon. Just wanted to start off touching base on the guidance real quick here. And doing a quick peruse of the first half of the year by annualize that goes over the high end of the guide range. If I take the second quarter annualized, that goes over the high end of the guidance range. Are there any headwinds that you're expecting in the back half of the year that would indicate that EBITDA run rate would decline from here? Or just trying to figure out gives and takes.

No headwinds, Jeremy. Let me start off with that. We remain conservative on the price deck, and that is the primary driver. In other words, when you look at the first half of the year and the prices that we were able to realize in the first two quarters, we continue to look at the second half of the year, and we remain conservative on the price deck. I wouldn't give you any other headwinds that we see.

And then the Woodford Express, just wondering if you could talk a bit about the background there, what drove you to this acquisition? And what type of multiple you paid or all the thoughts on the economics there?

Yes. This is Mackie, Jeremy. Really, that's a value-driven acquisition. It's situated in a great area in Oklahoma. As we mentioned, it has connectivity already with our gathering assets and also with the residue takeaway pipelines, and it just was one heck of a buy. If you look at the acreage and the producers that are committed under long-term contracts and the fees that are associated with that, we're very pleased with the price that we could pay for those assets.

A real quick last one, if I could. With regards to Ira and a potential 45Q increase there, just wondering how this might impact your thoughts on pursuing carbon capture initiatives? Do you need that to go after these projects? Or are these economics even without that?

Yes. This is Mackie. And Tom, who leads our ESG team, can elaborate. But as we mentioned, we're chasing a project right now in North Louisiana that we're extremely excited about. It's one of those projects we may or may not exercise in. We certainly will allow our CO2 to be captured. But what the new credits in this new bill would provide for is a significantly higher rates of return with that tax credit going from up to $85. So depending on how that plays out in this bill, that certainly will be very positive for that type of project on creating very significant returns.

Our next question comes from Chase Mulvehill from Bank of America. Go ahead, Chase.

Good afternoon. I guess maybe I'll start with Lake Charles. It looks like there wasn't really anything new on the offtake front, but it sounds like you're still pretty positive and optimistic about signing more SPAs for the rest of the year. So could you maybe just kind of talk a little bit further about the opportunities that you see signing more offtake for the rest of the year? And then also about selling down some interest, just kind of the conversations that you're having there and the potential to do that? And would you need to FID the project before you actually sell down some interest?

Great questions. Obviously, we've been busy negotiating offtake contracts over the last - since our last earnings call, and we wish we'd maybe had a couple of extra weeks here before this call and we're optimistic close to an announcement on pretty important contracts. But some of these things just take time. They are 20-year contracts and significant dollars involved. So we're working on a lot of different offtake contracts, still seeing very strong demand worldwide, both in Europe and in Asia. So things are going great. I think the people are - security of supply is becoming even more recognized around the world than it was even three, four months ago. So we're highly optimistic we'll get to the goal line on our offtake. As far as the equity sell-down, we're likely to start that process in the next couple of months. We want to kind of get to a critical mass of offtake contracts before going down that path. Obviously, the equity participants want to know kind of what our portfolio offtake contracts looks like, but that's just around the corner for us. And then I think - what was the last question?

The timing with net FID.

Yes, we're still targeting FID by the end of the year. Obviously, the big project and lots of things have to come together, but things are looking really good.

Very perfect. Unrelated follow-up is really on the fractionation side. We saw the fire with Medford over in Conway. I'm guessing that's probably jobbing a little bit more rich gas down to Mont Belvieu. Obviously, it didn't impact 2Q, but when we think about 3Q, could you talk about whether you're seeing rich gas kind of make its way down to Belvieu and the impact that this could have on kind of the fractionation market in the third quarter?

You bet Jason, this is Mackie again. Without that, we're seeing significant volume growth for NGL barrels reaching Mont Belvieu, both from the Permian Basin and other areas of Texas and the Ford basin. Ironically, some of the barrels that were affected by that, we are now fracking at Mont Belvieu. And so what we are seeing is a very tightening of frac capacity. We think that's going to increase over the next six to nine months before some of these other fracs come on, including ours. So we see the value of any available capacity at Belvieu getting increasingly better. So we're pretty excited about that. And we're also excited that we kicked off the frac A; we'll push hard to get that done by the third quarter or earlier.

Do you know if you're seeing any of the NGL barrels making their way down from Conway? Or is there enough capacity there?

I can't speak to what a lot of others are doing, but we are receiving barrels from Oklahoma delivered to our frac as a result of that.

Okay. Awesome. I'll turn it back over.

And our next question comes from Colton Bean from Tudor, Pickering, Holt and Company. Go ahead, Colton.

Starting off on Gulf Run, you mentioned incremental demand and the potential to upsize the pipe, I guess in terms of upsize capacity, are you looking at something in the range of 2 Bcf a day or potentially beyond that? And then would you add compression ahead of in-service or just at a later date tied to commitments?

I'd tell you, when we look at the Enable asset acquisition, we just keep turning over gears and how incredible it is in this time when the fastest-growing area in the nation in Haynesville, there was already a 42-inch approved and being constructed. And as we have said, it should be in the ground by the end of the year. We did just complete an open season. It went exceptionally well. The demand to get volumes, not only out of North Louisiana, but other areas of the U.S. down Gulf Coast is enormous. We're going through discussions and negotiations with a large amount of producers and shippers that were interested in that, and we'll be making those decisions. We can add compression and add about 1 Bcf, but we also are looking at having to loop the line potentially all the way down to Lake Charles. So still a lot we're working on there, but we are in negotiations and certainly expect to talk more for our next earnings call.

Mackie, just to confirm that you - it sounds like you can get up to north of 2.5 just for the compression.

Yes, we can go from 1.65x to 2.6x just with compression.

Great. And then maybe sticking on pipeline development. Can you explain on what you're seeing in terms of commercial interest on Warrior? And is there any reduced urgency from E&Ps? I think we've seen basis widened, but then some of the other brownfields have been a little bit slower to FID than expected. So just a bit tough to reconcile that at present.

You said Warrior, right?

Yes, Warrior, so thinking Permian just it seems like maybe the certainly slow, but yes -

Yes. Certainly, with the announcement of the pipeline, some of the bigger producers that were worried about capacity. They've signed those up. However, we are talking to some of those already. In addition to that, we have a bunch of producers, of course, upstream and then some very strong markets downstream. We have a pretty balanced customer base from both ends. We are seeing a tremendous amount of interest - and we do expect to hopefully make some headway, certainly before our next earnings call and still remain very optimistic that we'll get that to FID.

You bet.

And our next question comes from Brian Reynolds from UBS. Go ahead Brian.

Hi everyone - just curious if you can just talk about and you'll takeaway capacity out of the Permian and potential expansions there just given the recent processing plan announcement additionally to the frac A of the next year? Thanks.

Okay this is Mackie again. Yes, we've already announced that we're building 2 more cryo plants; things like everybody that can say the word cryo is announcing projects out there. Fortunately, we kind of - we're looking ahead years ago. We built a 24-inch and then we built another 24-inch. So we've got capacity to not only handle the liquids from our plant that we're building plus additional plants. We also are a big takeaway from a lot of the other plants out in that area. I believe there's about 2.2 million barrels moving out of the Permian Basin - I mean, I'm sorry, out of the Permian Basin and about 35% to 36% of that is us, and we do see that increase for the remainder of this year and beyond.

And just as a quick follow-up, do you see any need for expansion on your existing pipes or are you good for, I guess, the interim?

We don't see that over the next year to two, but who knows. There are still enormous opportunities to grow from the best rock in the world, with multiple pay zones out in the Permian Basin. So - but we're sitting pretty good for the next year or two and, of course, we have the 30-inch from the fourth basin down and have plenty of capacity in that pipeline.

Great, I appreciate it. And as a quick as we talk about CCUS and some of the earlier questions. Just curious if you can just pursuing projects in Louisiana or the Northeast or Texas is there kind of a preference to pursue first or any incremental color around there?

So around capturing CO2?

Correct, yes.

Okay yes, I think others have been asked that question. But the bottom line on that is where is the CO2 and where is the closest location to sequester it. And Louisiana is such an excellent state because they're one of the only states that we're aware of that have asked for primacy so that you could actually get a permit, a plastics permit approved by the state instead of going through the EPA, that hasn't been approved yet. But anyway, Louisiana is a little ahead of the game. There's a lot more treating, a lot more CO2 in North Louisiana. So there's more of a need to sequester CO2 there. And that's why we've kind of focused our efforts on a really attractive project that Tom and his team have worked very closely on that we're pretty excited about.

Great, appreciate it the color. Have a good rest of the evening.

Sure.

And our next question comes from Michael Blum from Wells Fargo. Go ahead Michael.

Thanks, just wanted one quick follow-up on Warrior Pipeline. Can you just remind us whether there's any CapEx in the budget this year tied to Warrior?

Michael is Mackie. There is some. We're not rushing that, but we certainly are way out in front of it as far as surveying and laying out the route. But no, there's no significant dollars in 2022.

Okay great. And then on Lake Charles, is there a certain percentage of the capacity that you want to contract before you move forward to FID. Just trying to look at kind of the signs where we should be looking for to know that you're going to get to FID by year-end?

Well, the bottom line of that entry is at what point are we going to go to our Board and our Executive Chairman to ask for approval. I think we've said publicly that we can get to that 12% to 14% depending on the customer mix and of course, the infrastructure funds that will be a part of this, but that's probably a pretty good range, 12 million to 14 million tons, but certainly, we'll make that decision at the right time here towards the end of the year.

Okay great. And then just last one from me. if I heard right, it sounds like you either did expand or in the process of expanding your ethane export capacity at Marcus Hook. So just curious if I heard that right and where the capacity will be when the expansion is complete?

Yes, Michael, it's not that material. We're - as you know, we have built out an extensive pipeline network that we have tremendous ability to grow. We're close to maxing out what we can do both from an ethane standpoint and from an LPG standpoint. But we're looking at everything. We were able to eke out a little bit more, a little less than 10,000 barrels that we were able to expand, and we'll continue to look at those opportunities until we make the decision to significantly expand at Marcus Hook.

Okay got it, thanks. Thank you.

Thank you.

And our next question comes from Keith Stanley from Wolfe Research. Go ahead Keith.

Hi afternoon. I wanted to start on capital allocation and make sure I got the message right. So the distribution, you've been very consistent in growing that every quarter. You said you'd be at the leverage target by year-end. So how does the capital priority shift, if at all, into next year in terms of distribution growth buybacks and growth capital expectations? Tom, it sounded in your comments like a little more focus on growth once the balance sheet and to grow distribution goals are met. Is that right?

Yes, I don't know, Keith, that I would sum it up as a shift. We're going to continue to focus on the balance sheet. But I think it's very important to note with all the projects we're talking about right now that are very good, high-returning projects. We're going to continue to look at that. But it's also worth noting the portion about returning capital to the unitholders. So we'll continue to evaluate that as from a distribution, we'll also continue to evaluate it, from even a unit buyback. So there's going to be various components here that are moving around, and we'll have a good, healthy discussion internally here with our Executive Chairman as well with our Board as we continue to focus on that. So anyway, this is a good question to be answering here. Right now, it's great to be at this place on the leverage. We're very, very excited about this. And it's - let's just call it, it's kind of a high-class evaluation to have to be doing. We're very pleased to be here at this stage and as quick as we got here.

Great, thanks for that. And a separate one, I just wanted to follow up on Lake Charles. So sound very optimistic on contracts. Any color you can give, plus or minus on where pricing has been? You kind of - you have tons of demand, obviously, from Europe and Asia. But you also have a lot of competing projects? And then relatedly, any update on how discussions are going on the cost side and the EPC contract, if that's kind of in line with what you were thinking so far? Thank you.

Yes, it's been a very competitive market in spite of the increased demand worldwide. And so we can't ignore competition in our pricing. However, I think the number of companies and customers around the world that have - that are stepping up, and that nontraditional players for LNG and traditional, the demand has just increased significantly. So we're pricing, we're moving, adjusting our prices up to reflect kind of anticipated a little bit higher cost on the EPC side. We're going through a big refresh process now. We'll get that number towards the end of this year. And so, we're obviously trying to balance the anticipated somewhat higher cost, but we still make a very, very competitive EPC price compared to our peers because of our Brownfield assets we have on the ground today. But it's a balancing between a competitive market and getting - trying to get a good return for the project.

Thank you.

And our next question comes from Jean Ann Salisbury from Bernstein.

Just following up on that last question. Obviously, I think it's fair to say that all LNG projects kind of want the same EPC. Would you consider just doing the 10 MTA instead of the 15 if you can lock in the EPC and you're not quite at the 12 MTA to 14 MTA contract level that you wanted to be out for the 15?

Yes, certainly, we'd consider that. I think we're - we think that overall, it's going to be kind of more cost competitive to do three trains versus two. But where we think we're going to be in the next few weeks with signed contracts, we're certainly in a position to do a 2-train deal if we want to go down that path. So we'll evaluate that during the course of the fall, but that's an option we could do.

But I'll just add to that, we're extremely optimistic. Tom and his team are working with many companies in many countries, and we're highly confident that we'll get just fully sold out to the 15 million tons.

That's great. And then could you just give more color on Energy Transfer's petchem strategy, especially around buy versus build?

Sure. This is Mackie again. When Kelsey kind of gave us the directive that we need to step into pet chem, we certainly are doing that, two perspectives: one, we're - from an M&A perspective, anything that's for sale, we'll take a look at pretty much like anything in the industry; and then on the organic side, we're excited about the project that we're working on, we truly believe we're not just saying it. It's the most unique world-class facility anywhere on the - around the world. And we say that because where it's located, we're going to be able to move propane, butane, ethane, and natural gasoline through four existing pipelines, all four of which we have significant capability of expanding. In addition to that, upstream of the cracker, we'll have access to refined products like butane components and gasoline components. Who knows where the gasoline demand is going to go in the next 5 to 10 to 15 years? Some believe that that's going to get very depressed pricing, and we think that will be a very cheap feedstock for our customers. And also with the cracker and the pathosis technology that's part of our plant, we'll be able to track things like methanol and ethanol and mixed alcohols and even plastics into ethylene. So just an incredible amount of flexibility, and we think very advantageous to any other cracker in the world as far as the cost and value of the upstream feedstocks. And then you look at downstream, we have every intention to connect it to our new Spindletop ethylene storage facility that has a header system connected to multiple ethylene pipelines. We have every intention to connect all of this to Mont Belvieu as well as to some of the pipes going into Louisiana. And then, of course, at Nederland, we'll have the capability of exporting both ethylene and propylene. So once again, we're in the early stages. We have no intention of moving forward without a very big customer - I'm sorry, a very big partner on that. And we're structuring this agreement, and we'll move forward with tolling agreements. So this isn't going to be a petchem where we're going to be speculating a roll of the dice on the cyclical nature of profits from petchems. We're going to do this like we do all our deals. We're going to have a polling arrangement with guaranteed revenues and a guaranteed rate of return over a period of time. So we're not there yet, but we have a great team working on it, and we really are excited about that project, we can get that FID.

Great. If I can sneak in 1 quick yes or no. Will Gulf Run be able to run at full capacity before Golden Pass starts when Gulf Run starts up later this year?

Yes.

And our next question comes from Michael Cusimano from Pickering Energy Partners. Go ahead, Michael.

Hi, good afternoon. On the Woodford acquisition, can you talk about your existing Oklahoma utilization and the Woodford utilization? I'm trying to understand if there's like operational synergies part of the deal that maybe you can rationalize capacity like we've seen others in the industry deal through relocation or what have you of processing capacity.

Yes. As we mentioned, our gathering system already connected. We have our inter and intrastate, residue pipelines connected to it. It's very early on. This acquisition moved pretty quickly. So we'll continue to evaluate and certainly do like we do with any of our acquisitions or any of our new build cryos, where we'll integrate it in and figure out a way to best, most properly and efficiently operate that system. Fortunately or unfortunately, however you want to look at it is it's going to be pretty darn full just with the long-term dedications from a handful of producers today. But certainly, as we integrate and bring into our system, we'll create as much value as we can with that new asset with our existing assets.

Got it. Okay. That's helpful. And then I wanted to shift quickly to CapEx. I think I heard you said that some capital costs were maybe deferred into '23, whereas some projects maybe move forward maybe '22 budget. Can you maybe help us wrap our head around what '23 could look like as we stand today without other additional projects in the backlog coming into the budget?

Yes. It's - as you know, our normal practice is with our fourth-quarter announcement to put out the '23 CapEx guidance. But it's fair, it's a fair question in the sense that we're talking a lot - about very, very good projects. We're here right now. So as we move forward with those and get those to FID, we will be transparent as those get approved and move forward, which will clearly move into 2023 CapEx guidance at the time. But at this point, I don't really have a number that we can give you, but very excited about some of these projects we're referring to. And we will update everyone as those get done.

And our final question comes from Michael Lapides from Goldman Sachs. Go ahead, Michael.

Thank you for taking my question. Just curious, the M&A environment right now, I mean, if I think about your history over time, you helped on tons of M&A over the years. Just curious, what type of assets do you think the M&A environment is very ripe for, meaning where there's lots of attractive things to do? And maybe on the other flip side of that, what type of assets do you think are either priced too high for your blood or simply not on the market even if there are things you'd love to have in the portfolio? I'm not looking for specific names, I'm just looking for asset types.

Well, thank you, Michael. On the specific name part, we do feel very, very strong that consolidation makes a lot of sense in the midstream space. So starting with the midstream space, we would - you would see us look around the assets we have right now, those assets that would be great bolt-ons for us, and we're going to stay focused on those. We do - you've seen a lot of them come to market. Rest assured, we have looked at these, and we're going to continue to evaluate them. I think the second part of your question is what kind of makes sense from the standpoint of valuations? When we look at these things, we evaluate them based upon where we're currently trading. And when you look at the commercial synergies, the cost synergies, we're very, very careful in how we evaluate each one of these. And we remain disciplined on what we're doing. But just like the smaller one today we announced, I know it's an all-cash transaction, but even if you were to do that one on a 50-50, it was accretive. It was accretive relatively small just because of the sheer size. I think that's a good example of what we'll continue to look at and how we evaluate these. But let me go back to the first part again as far as assets go. You've seen us talk - you've heard us talk about the petchem side of it. And we continue to evaluate moving downstream. And we continue to look at on the international front, too. We've talked about the Panama project. So there are other projects that we continue to look at that really kind of moving downstream, taking advantage of all the CapEx that we've spent over the last several years around our export facilities, etc. So it's going to be a natural fit with us. And as Mackie was highlighting on the petchem side of it, it's - there's no doubt that that's a natural fit for us. And those are the things we'll continue to look at here on that front. I don't know, Mackie, if you want to chime in if there's anything else, but that kind of sums up where we're spending most of our time and evaluations.

And we have no further questions at this time. I'd like to turn the call back to Tom Long for closing comments. Mr. Long, you may proceed.

Once again, thank all of you for joining us today. We really are excited to have the opportunity to talk to you about another great quarter and clearly a great year that we're seeing. Thank you for your support, we look forward to talking to you in the near future.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.