Good day, and welcome to the Energy Transfer LP First Quarter 2024 Earnings Conference Call. [Operator instructions]. Should you need assistance, [Operator instructions]. After today's presentation, there will be an opportunity to ask questions. [Operator instructions]. We ask that you limit to asking one question and one follow-up question. Please note this event is being recorded. I would now like to turn the conference over to Tom Long, CEO of Energy Transfer. Please go ahead.

Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer First Quarter 2024 Earnings Call. I'm also joined today by Mackie McCrea and other members of the senior management team who are here to help answer your questions after our prepared remarks. Hopefully, you saw the press release we issued earlier this afternoon as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based upon our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our Form 10-Q for the quarter ended March 31, 2024, which we expect to file tomorrow, May 9. 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 for non-GAAP measures on our website.  I'll start today by going over our financial results. For the first quarter of 2024, we generated adjusted EBITDA of $3.9 billion compared to $3.4 billion for the first quarter of 2023. We had record volumes through our crude pipelines and also saw strong performances across the rest of our operations. DCF attributable to the partners of Energy Transfer, as adjusted, was $2.4 billion compared to $2 billion for the first quarter of last year. This resulted in excess cash flow after distributions of approximately $1.3 billion. On April 24, we announced a quarterly cash distribution of $0.3175 per common unit or $1.27 on an annualized basis. This distribution represents an increase of 3.3% and from the $0.3075 paid in the first quarter of 2023. In February, Fitch upgraded Energy Transfer's senior unsecured credit rating to BBB with a stable outlook, which followed an upgrade by S&P to BBB in 2023. At the end of the first quarter, we had no outstanding borrowings under our revolving credit facility. Following the redemption of all of our outstanding Series C and Series D preferred units in February of 2024, in March, we issued a notice to redeem all of Energy Transfer's outstanding Series E preferred units on May 15, 2024. In April of 2024, we redeemed $1.7 billion of senior notes using cash on hand and proceeds from our revolving credit facility. And for the first quarter of 2024, we spent approximately $460 million on organic growth capital, primarily in the Midstream and NGL and refined products segments, excluding Sun and USA Compression CapEx.  Now turning to our results by segment for the first quarter, and we'll start with NGL and refined products. Adjusted EBITDA was $989 million compared to $939 million for the first quarter of 2023. This was primarily due to growth across our transportation, fractionation and terminal operations, which was partially offset by lower gains from hedged NGL inventory. As a reminder, the first quarter of 2023 included gains that were carried over from the prior year. NGL transportation volumes increased 5% to 2.1 million barrels per day. This increase was primarily due to higher volumes from the Permian region on the Mariner East pipeline system and on the Gulf Coast export pipelines. NGL fractionation volumes increased 11% to 1.1 million barrels per day. Total NGL export volumes grew 6% over the first quarter of 2023. We continue to see strong international demand for natural gas liquids and saw record LPG exports out of our Nederland terminal for the month of March. During the first quarter of 2024, we loaded approximately 14 million barrels of ethane out of Nederland and nearly 7 million barrels of ethane out of Marcus Hook. During the first quarter, we continued to export approximately 20% of worldwide NGL exports.  For midstream, adjusted EBITDA was $696 million compared to $641 million for the first quarter of 2023. This was primarily due to the addition of the Crestwood assets as well as higher volumes in the Permian Basin. As a reminder, results in the first quarter of 2023 included a onetime positive adjustment of approximately $40 million. Gathered gas volumes increased to 19.9 million MMBtus per day compared to 19.8 million MMBtus per day for the same period last year. Now for our crude oil segment, adjusted EBITDA was $848 million compared to $526 million for the first quarter of 2023. This was primarily due to significantly stronger pipeline volumes, increased terminal throughput as well as favorable timing on gains associated with hedged inventory. We also benefited from the acquisition of the Lotus and Crestwood assets in May and November of 2023, respectively. Results for the first quarter of 2024 included a $40 million benefit related to favorable timing on gains associated with hedged inventory, a portion of which we expect to reverse in the second quarter. And as a reminder, the first quarter of 2023 did include onetime negative adjustments of approximately $35 million. Crude oil transportation volumes increased 44% to a record 6.1 million barrels per day compared to 4.2 million barrels per day for the same period last year. Excluding the additions of Crestwood and LOTUS, adjusted EBITDA and crude oil transportation volumes on our base business increased 47% and 14%, respectively, compared to the first quarter of 2023.  In our Interstate segment, adjusted EBITDA was $483 million compared to $536 million for the first quarter of 2023. During the quarter, we saw margin growth related to higher contracted volumes at increased rates on several of our pipelines. This growth was more than offset by lower operational sales resulting from lower prices and unplanned maintenance projects. In addition, the first quarter of 2023 included a onetime benefit from the realization of certain amounts related to a shipper bankruptcy. Total system volumes increased 5% over the same period last year due to increased demand and higher utilization on the Transwestern Tiger Trunkline and Gulf Run pipeline systems. We continue to fully utilize Zone 1 capacity on Gulf Run, and with the completion of the Trunkline backhaul project, we are fully utilizing deliveries into our trunk line pipeline from Zone 2. Our team continues to work on the next phase of a potential capacity expansion to facilitate the transportation of natural gas from Northern Louisiana to the Gulf Coast based upon customer demand. And for our intrastate segment, adjusted EBITDA was $438 million compared to $409 million for the first quarter of last year. During the first quarter of 2024, we recorded gains of approximately $250 million related to pipeline optimization opportunities that were not expected to repeat throughout the remainder of the year. In addition, we saw volume ramp-ups and new contracts on several of our Texas pipelines. All of this was partially offset by lower storage optimization opportunities.  Turning to our growth projects, and we'll start with Nederland and Marcus Hook export terminals. Our NGL terminals continue to benefit from increased demand, both in the United States as well as from international customers. Construction of the expansion to our NGL export capacity at Nederland continues to progress. This expansion is expected to give us the flexibility to load various products based upon customer demand. We have completed the installation of all pilings for the facility and the construction remains on schedule for an anticipated in-service in mid-2025 for the initial phases of the project. And as mentioned on our last call, we are also building new refrigerated storage at Nederland, which is expected to increase our butane storage capacity by 33% and double our propane storage capacity. This will further increase our ability to keep customer ships loaded on time and give us the ability to more than fully optimize our export capabilities. We expect the total combined cost of these 2 projects to be approximately $1.5 billion.  At our Marcus Hook terminal, construction continues on the first phase of an optimization project that would add incremental ethane refrigeration and storage capacity. On our Lone Star NGL pipelines we recently [FID-ed] 2 projects that will debottleneck our West Texas Gateway and Lone Star Express pipelines. On the gateway pipeline, a debottlenecking project is underway that will allow us to fully utilize our interest on the Epic pipeline and optimize our deliveries from the Delaware Basin into the gateway pipeline for deliveries into Mont Belvieu. These upgrades are expected to be completed in 2025. As a reminder, this undivided interest was acquired as part of the Crestwood acquisition, and it's just one of the several synergy projects we are working on. And on the Lone Star Express, we are completing upgrades that are expected to provide more than 90,000 barrels per day of incremental Permian NGL takeaway capacity upon its anticipated in-service in 2026. The combined project costs are expected to be approximately $125 million. Upon completion of these 2 projects, our total deliverability in the Mont Belvieu is expected to increase to more than 1.3 million barrels per day.  As we mentioned on our last call in early 2024, we closed on the acquisition of 2 pipelines. Sabina 1 Pipeline from Mont Belvieu to the Houston Ship Channel and the Sabina 2 Pipeline from Mont Belvieu to our Nederland terminal. We recently commenced the conversion of the Sabina 2 pipeline to provide additional natural gasoline service between our Mont Belvieu NGL complex and our Nederland storage and export terminal. This project, which we anticipate will be in service in 2025, is expected to increase the capacity from 25,000 barrels per day to approximately 70,000 barrels per day. In addition, discussions are ongoing to provide transportation for potentially multiple products on the Sabina 1 Pipeline that extends from Mont Belvieu to the Houston Ship Channel. As a reminder, in addition to the incremental processing capacity acquired through the Crestwood acquisition, we are expanding our processing capacity at several of our existing processing plants. In total, we are moving forward with upgrades to add approximately 200 million cubic feet per day of processing capacity in West Texas. In addition, we recently completed upgrades in South Texas that added approximately 60 million cubic feet per day. These upgrades can be completed at more favorable capital cost when compared to building a new processing plant.  Also, we continue to increase optionality and improve reliability along our pipeline systems. At the end of 2023, we completed a backhaul project on our trunk line pipeline. The project added an incremental 400,000 Mcf per day of Southern flow capacity on the pipeline system at very efficient capital cost. Looking at our crude oil assets, we are adding a direct connection from Midland to our pipeline that flows from the Permian Basin to Cushing. The construction of this approximately 30-mile pipeline continues. And upon its anticipated completion in the fourth quarter of this year, it is expected to be able to transport approximately 100,000 barrels per day of crude from our terminals in Midland, Texas to our terminal in Cushing, Oklahoma.  We also continue to develop our proposed Blue Marlin offshore project, and we are hoping to receive the draft EIS this quarter. As a reminder, in November of 2023, we announced a heads of agreement or HOA with Total Energy's for crude offtake. And additional customers remain very engaged and interested in our project, recognizing the value of fully loading VLCCs and the reduced execution risk that comes with repurposing existing underutilized assets. Now for an update on Lake Charles LNG project. As we discussed on our last earnings call in January of this year, the Biden administration imposed a moratorium on the approval of LNG exports, while the Department of Energy conduct studies to determine whether LNG exports are in the public interest. The Biden administration stated that these studies would focus on the cumulative impact of LNG exports on climate change, U.S. natural gas prices and the impact of LNG facilities on local communities. We remain optimistic that the DOE studies will continue to support DOE export authorizations, particularly for LNG projects that have lower Scope 1 and Scope 2 emissions profiles like Lake Charles. And so we continue to believe that Lake Charles LNG will receive a DOE export authorization in due course. As such, Lake Charles LNG continues to pursue the development of the project. In this regard, Lake Charles LNG is in discussions with LNG offtake customers for the remaining unsold offtake volumes necessary to take FID. Lake Charles LNG remains extremely thankful for the continued support of its existing LNG customers.  And for a brief update on other projects. Energy Transfer has approved 8-10 megawatt natural gas-fired electric generation facilities to support the partnership's operations in Texas. We expect these facilities to go into service throughout 2025 and 2026. On the blue ammonia front, we continue to develop an ammonia hub concept at Lake Charles, Louisiana and Nederland, Texas, where we have deep water access at our existing facilities. This hub concept would allow us to provide critical infrastructure services to several blue ammonia facilities, including natural gas supply, CO2 transportation to third-party sequestration sites, ammonia storage and deep water marine loading facilities. This hub concept is expected to promote economies of scale and efficiencies as compared to individual stand-alone blue ammonia projects and the market response to this approach has been favorable. Yesterday, we entered into an agreement with Capture Point that commits CO2 from our treating facilities in Northern Louisiana to the capture and sequestration project being jointly developed by Capture Point and Energy Transfer.  Now looking ahead at our 2024 organic growth capital guidance. With the addition of several new growth projects, we now expect 2024 growth capital expenditures to be approximately $2.9 billion, which will be spent primarily in the NGL and refined products and midstream segments. This has been revised from our previous guidance for approximately $2.5 billion to include newly approved debottlenecking projects on our Lone Star Express and Gateway NGL pipelines, the Sabina 2 pipe conversion, optimization work at Mont Belvieu, backhaul, looping and compression projects on FGT, new power generation facilities as well as additional processing plant optimization in the Permian and gathering system build-outs and compression projects in the midstream segment. We continue to expect our long-term annual growth capital run rate to be approximately $2 billion to $3 billion.  Now turning to our adjusted EBITDA guidance. We are raising our 2024 adjusted EBITDA guidance to be between $15 billion to $15.3 billion compared to our prior guidance range of $14.5 billion to $14.8 billion. Our 2024 guidance has been updated to include earnings related to Sunoco's acquisition of the NuStar assets, which closed May 3. As we look at our first quarter performance and bring the NuStar assets into the family, we continue to be excited about 2024 and are comfortable that we can deliver on our plan despite various market headwinds like lower gas prices and production curtailments that have impacted midstream volumes. Overall, worldwide demand for crude oil, natural gas, natural gas liquids and refined products remained strong. as does demand for our products and services. We will continue to position ourselves to meet this demand by strategically targeting optimization and expansion projects that enhance our existing asset base and generate attractive returns. We also continue to pursue synergy opportunities around recently acquired assets with several projects underway, including the optimization of processing capacity in West Texas and NGL pipeline takeaway capacity from the Delaware Basin. Our financial position continues to be stronger than any time in Energy Transfer's history, which we believe will provide us with the continued flexibility to balance pursuing new growth opportunities, further leverage reduction, maintaining our targeted distribution growth rate and increasing equity returns to our unitholders. That concludes our prepared remarks. Operator, please open the line up for the first question.

We will now begin the question-and-answer session. [Operator instructions]. As a reminder, please limit to asking only one question and one follow-up question. At this time, we will pause momentarily to assemble our roster. The first question comes from Jeremy Tonet with JP Morgan.

Good afternoon. Jeremy. Just wanted to start off with regards to Crestwood, now that the acquisition has been under your belt full a little bit here. I wonder if you could update us a little bit more. You talked about the synergy capture a bit before, but just what you see now as far as the impact and what you see, I guess, for potential synergies across commercial cost savings, what have you. Just curious for latest thoughts there.

Yes. I mean, I'll go ahead and start. We still feel very good about the $80 million on the cost synergy side that we said we would be able to achieve, and that's going well. And then I'm looking over at Mackie will comment on the commercial side of it.

Yes. Jeremy, as every time that we go and acquire somebody, we always have anticipated synergies and then we just dig stuff up and find things, and once again, we're doing that with Crestwood. Some that we can talk about, for example, in the Permian Basin, they've got some idle capacity that we'll be able to utilize sooner than later will delay any kind of expansions we may need out there. There's also some things going on up in the Bakken that we can't really elaborate on, but very significant opportunities up there to help not only fill up some of their available higher now available processing capacity, but also bringing fairly significant more barrels in Dakota Access. And there's others we can go out of every other areas. But we're very excited about what we've seen early and look forward to really benefiting from some of these synergies we've already recognized.

Great. And I appreciate the guidance update reflects the Sun acquisition of NuStar there. But if I just want to kind of parse through that a little bit more and see how the base business for ET is proceeding versus guidance provided before, how would you describe, I guess, the outlook at this point versus before, if it's similar or if anything has changed?

Similar is going to be the short answer. We had the $14.5, $14.8 billion. We're including an incremental $500 million just for that portion of the year for Sunoco. So that's what you're seeing at this time with where we are in the process. Sunoco team has done a great job, and we'll -- they'll be probably updating that number a little bit more as we go forward. But right now, $500 million is the number that we're using.

Got it. That's helpful. Just the last one, if I could. I think you talked about the potential for increasing equity returns. And just wondering if you could comment a bit more on what you meant there.

There's obviously 2 -- as far as just the overall equity Jeremy, if I understand you correctly, equity returns, meaning that we continue to bump the distributions, but I don't ever want to say that we're not focused on unit buybacks when we get to the right place from a leverage standpoint. And what I mean is when we're kind of looking out at the forecast, we'll be opportunistic there.

Our next question comes from Spiro Dounis with Citi.

Thanks, operator. Maybe start with some of the new projects and the CapEx update. Mackie, your team has clearly been busy over the last quarter with all those additions. Curious now just given you're sort of higher end of the range of $3 billion at this point in the year, anything that could sort of tip us over that, that's in the hopper? Are you contemplating that in that new range, thinking about projects like Blue Marlin or your goal front expansion? Anything to kind of point you that you can get us over that?

Yes. Spiro, this is Mackie. Everything that we have in right now is what we're going to do. Next 30, 60, 90 days, we may make significant progress and some of the things we're working for. But the things that we announced recently, the additional $400 million or things that we have approved recently that we've kicked off, several of those will actually come online later this year. All of them come online kind of within 2 years or earlier. So yes, we're adding more capital, but we're also going to see revenues much quicker than, of course, a lot of our projects.

Got it. It's helpful. And just want to go to the slides, one sort of point to new opportunities you're evaluating on the power plant side to connect into new and existing power plants. Curious if you could expand on that and what that could mean in terms of scope. Is that sort of interstate pipeline expansions? And then are we also talking about brownfield or even greenfield storage expansions?

Yes. I'll tell you this is kind of the first small step for us. But as everybody is aware, certainly in Texas and throughout many states, the grids are in jeopardy, very cold or hot weather. So we're doing what we can to help support that. But really, the driver behind what we're doing on adding these 10 megawatts at a time facilities is, -- number one, reliability is to make sure that when we have glitches of the grid, especially out West Texas were those not uncommon that we can keep our facilities running. In addition to that, it also will help grid security, for example, we'll be able to -- in the kind of urea-type or cold weather-type circumstances when ERCOT asks us to get off the grid, we'll be able to get off the grid, keep our plants running reliably and allow that excess energy that we're not going off to go to benefit producers, for example, upstream that might have issues with loose electricity. So we think what we're doing are kind of small steps that we'll grow into to help make our system, our assets much more liable, the grid more stable, in addition to that, I won't go into this in great detail, but there's also a lot of revenue benefits from LAR and ancillary services that we'll be able to provide with this added generation. So we're pretty excited about it. It's kind of small stuff right now, but it makes a lot of sense for our partnership.

Our next question comes from Keith Stanley with Wolfe Research.

Wanted to go back to the interstate gas sales and the strong results there. Is there any more detail you can give on the optimization opportunities you saw that drove the $250 million gain? And then relatedly, just any updates on how much capacity you have available for -- to benefit from Permian differentials this year? And anything on the Warrior project as well.

Okay. Let me start with the end of that. So on Warrior, we continue -- our team continues to work. One thing we are doing, we're going to be very disciplined and prudent. We're not going to run out and announce the project unless we feel good about all of our capacity, [sold] long term. So we're not going to run out in an FID Warrior when we have some capacity on our existing system that we're still terming up. So we're working hard, the pause in LNG has impacted a little bit with some of the bigger customers that we're working with. However, there remains, as everybody [Indiscernible] probably knows a strong interest in another pipeline, probably by mid to late 2026. We are very optimistic that we will build the next pipeline to come out of West Texas, and we'll continue to work hard to get that finish line when it makes sense.  As far as the spread across Texas, it kind of varies month-to-month, but it's certainly north of $300,000 a day of [Indiscernible] a day that we have available that are benefiting from these widespread -- we sure hate to see prices do what they're doing at Waha, but that's what happens when you have capacity constraints, which we have right now out of the Permian. And so there is a pipeline coming on later in the year than alleviate a lot of that but certainly, the way we're positioned is very well to take advantage of that type of spread for our customers' benefit as well as for our own benefits. As far as the intrastate revenue, it's just -- it's what we've built. We feel extremely fortunate with the assets we have throughout the U.S., but especially in Texas and the team we have that's operating those assets where really cold weather times are really volatile times, even really hot weather, we have the ability to create a lot of revenue by peak hourly sales or putting some storage positions on moving gas from west to east, even backhaul. There's just a lot of things we can do with our massive intrastate pipeline network in Texas. And so -- we see this every year, we see it in most winters, many times in summer where we're able to capture kind of some unexpected revenue that will always be there at very volatile times at some level.

I appreciate the detailed answer. Second question on -- just on M&A and how you're thinking about things. And so -- and thinking about it from the lens of Energy Transfer and then obviously, you have Sun as well, which I know is an independent company, but there's a fair amount of overlap now in some of the assets and business mix between ET and Sun. So how do you think about M&A going forward? And kind of what types of acquisitions or assets make more sense at the ET level versus the Sun level and any differentiation there?

Yes. That's -- listen, that's obviously a very, very good question. We spent a lot of time within Energy Transfer strategizing here. I will -- I think I will start off saying that we still feel like consolidation makes sense in the midstream space. So just at the 50,000-foot answer to your question, we still fully intend on evaluating various opportunities as we look out. So we're not going to slow down on that front. Now as far as what we look at is going to be always trying to look at those things that feed all the way downstream. We always like to talk about how we go from wellhead to the water, and we do it across all the commodities. So you can see our strategy as we look at this stuff and what assets we look at as to how it feeds all the way through the value chain when we make these acquisitions. And it gives us great opportunities for commercial synergies when we do that as well as the cost synergies.  Now as to the -- I guess, as to the last part of your question about the Energy Transfer versus Sunoco, clearly, the Sunoco team has done a fantastic job on this new star. I couldn't be more excited about that asset base coming into the family here. So what you'll see is, you'll see that they're in kind of the wholesale fuel distribution terminal business, et cetera. And you're right, there's going to be some overlap and in those instances, we'll look at ways on a combined basis of what we can do. But Sunoco's can continue to make those kind of acquisitions. This is really their first big public company transaction. They've made a lot of other asset acquisitions, but it's clearly something that's very, very accretive to them, and it's very good for the family from that standpoint. And I'm going to look across the table to Mackie and give him a chance to add in a little bit more even on the latest NuStar acquisition and some of the optimizations we might be looking at here.

You bet. Yes. And I want to elaborate much more on what Sun said or anybody that follows them, they kind of explained it. We're excited for them. They are kind of stepping up and kind of growing up a little bit in one regard as far as different type of assets. And there are some assets that overlap, we think there's a real benefit and potentially partnering up with them. So we are in discussions of possibly doing that. And if opportunities arise that are very beneficial and accretive to both of our partnerships as we do with other JVs, we look forward to capturing those opportunities as time moves forward.

Did that answer all your question there?

Sure did.

Our next question comes from Manav Gupta with UBS.

A quick question as it relates to your Slide 6. When we look at 2024, CapEx, 80% of that is between NGL, refined products and midstream. And I know it's still early, but with your crystal ball, if you look at 2025, do you believe this mix could change significantly in the next year where other segments could get more CapEx? Like any view over there would be very helpful.

Yes, I can start with that. I guess, looking at it right now, nothing jumps out that would change it significantly. However, you walk through some hypothetical, let's just think say, everything the pause gets lifted, for example, on LNG, we intend to own maybe 20%, 25% of that. That could start earlier. That's probably not likely. But it just kind of depends on Warrior, does it pick up later in the years, sooner or later? So there's a lot of different variables and negotiations going on and even permitting issues with the government. So I think the high-level answer to that kind of the spin rate run right now, at least through '25. That's pretty consistent, but we've got a number of projects that I just alluded to in different segments that might begin quicker than others, and that would, of course, queue it one way or the other.

A quick follow-up. At Marcus Hook, I think on the last quarter call, you spoke about construction of the first sale of optimization project that could add ethane refrigeration and storage capacity. Is there any update on that one?

No update. We're excited that phase, and we're diligently moving through that phase. We will be adding ethane storage and we are excited about the future of our export facilities and capabilities and revenues out of the markets for many years to come.

Our next question comes from Michael Blum with Wells Fargo.

I wanted to ask -- go back to the 8, 10 megawatt gas-fired power plants you announced for Texas. Just to clarify, are these basically [peaker] plants? Are you going to supply them with your own gas? And how do we think about return on invested capital for an investment like this?

Michael, this is Mackie. Yes, we will provide the natural gas for these with our own facilities. As I mentioned, the 2 main drivers here are reliability, number one, for our assets, keep our plants running, keep the gas flowing and number two, to benefit the grid. In our economics, we don't expect necessarily run these a lot. There's almost 9,000 hours in a year, we have run the economics we run about 1,300, which we think will be significantly lower than what they will run, and that meets our rate of return [hurdles]. That has no anomalies in it in regards to like a urea-type situation or any kind of cold weather, or any kind of huge run-up in power prices or any benefits from ancillary services or LAR and things like that. So like I said, it's not -- we're not putting these in to try to create significant returns, but it very likely could create a lot better returns than what we're projecting, but we're really building these for reliability of our assets in the grid.

Okay. Got it. And then just a follow-up on the Warrior potential project. Just to clarify, if you want to have this in service by 2026, when do you need to get FID on that?

Pretty quick. No, probably about -- we typically -- I'll say, typically, a lot of changes over the last 3 or 4 years. But if we're able to get FID hypothetically, for example, by late third quarter, early fourth quarter, we believe we'll have it in by the end '26 at the latest.

Our next question comes from Theresa Chen with Barclays.

A follow-up question related to the M&A topic. Related to your comment about wanting that wellhead-to-water strategy, so pro forma the NuStar assets in the family, you now have an expansive crude oil system, Permian to Cushing, Permian to Nederland and a sizable Corpus Christi export facility. So the long-haul movement between Permian and Corpus Christi, is that a natural area where you might want to fill your portfolio?

Sure. I mean anywhere we can connect the dots from where producers want to go to the best markets, we want to be in that market. We certainly, over the years, have been focused on bringing as many barrels as possible from Bakken, from Midland, from Cushing to our new and used assets to benefit those as well as our downstream pipes with Bayou Bridge, our VLCC project. But certainly, if the 30 assets are for sale, that can move more crude, for example, from Midland down to Corpus, we'll always look at those. But remember, those are NuStar assets and so they're the ones that will be chasing those opportunities wherever we might fit in, where it might make sense and they want to talk to us about, we're certainly open to that. But that's probably a better NuStar question related to Corpus.

Got it. And looking at the Dakota Access recontracting outlook and all the way through Bayou Bridge, just taking into account TMX now being online shipping not just WCS, West but also Syncrude, which seemingly has indirectly compressed Bakken dips given the connection to mainline. What is your outlook for [Indiscernible] would be contracting coming up in a couple of years and balanced with the incremental barrels that you're getting from Crestwood?

Yes. We love Bakken. We love what we've done out of there, proud of the role we play to get barrels out of such a great basin, the refineries in the Midwest and the Gulf Coast. So it's been a great asset for us. It's funny through the years, there's times when we have recontracting concerns on different assets, and that's just not one off. We think long term, there's blips from time to time. We think long term, it is the premier optimum outlet for producers. The best way to get your production to, as I mentioned, Patoka and into many of the Mid-Continent refineries as well as refineries around Port Arthur and Houston and then, of course, into Bayou Bridge all the way over into Lake Charles and the St. James refineries and then you add on our VLCC project. So it's just -- it's an asset that we're not really concerned if there's companies that aren't willing to roll over for a long period of time or a period of time it makes sense to us. We make no yearly at the time. We just -- we don't have a lot of concern. We think that basin is going to be very stable for the next 5 to 10 years. We don't see massive growth. But as long as oil prices remain fairly strong, we do see, like I mentioned, stable kind of consistent flows out there. We do believe we're the best option for producers and so we'll engage with anybody that wants to roll over, of course, already talking to some of them, but it's certainly not something we will sleep on.

Our next question comes from John Mackay with Goldman Sachs.

Maybe just to take one more at the power plant side. I guess, curious, are you guys operating any small plants now or have you in the past? And then if I think about this potential capacity you're adding, it's, I guess, relatively small versus what ET probably consumes overall. So do you think there's room for you guys to expand this number over time? And should we think of this as maybe kind of a first look on a kind of set of projects from here?

Yes, John, in fact, I thought I said it earlier, I probably didn't make it clear enough. Yes. These are first steps. There's grid problems all over the country in Texas is no exception. A lot of people are moving in Texas, a lot of data centers, a lot of AI data centers or crypto miners are still coming in industrial growth. I mean it's just we're so optimistic on -- for natural gas-fired generation. So it's something that we will continue to look at, and we will -- it will be highly unlikely that we don't announce more of these as each quarter goes on. But we are -- we will be the operator of these as I mentioned earlier, these aren't peaking units. They are units that are very good heat rates. So they're very efficient and very -- provide very well-priced megawatt of cost when we run them. And so this is just kind of the first step, and we're excited about where this may take us, especially in some areas, for example, maybe at Mont Belvieu, where we think there's a real opportunity there and then some other of our bigger cryo-complexes around the state. So it's an area that we will continue to growing.

I appreciate that detail. Maybe just zooming out or moving over a little bit. Can you spend a minute, maybe just talking about the blue ammonia hub, maybe kind of what your role in that could look like, what kind of pieces of that value chain you'd want to own versus maybe having a partner come in and kind of run it with you?

Yes. We keep talking about how excited we are -- all of our fossil fuel business, especially natural gas, incremental in so many things and certainly with ammonia production. So right now, probably a little bit higher priority, a little bit more focus is in the Lake Charles area. We've got a lot of momentum with some very significant players that really know what they're doing. We're approaching this very similar to our LNG project and our potential [Pet Chem] and that we don't want to be big owners of ammonia. Do we want to operate? Yes, we'll retain ownership of some level, very likely or possible. But what really drives us is to give you an example, one of these among your plants will deliver approximately 120,000 to 130,000 Mcf a day. In Lake Charles, we're looking at anywhere from maybe 5 to 7 over a certain period of time. So it's not insignificant natural gas transportation revenue. In addition to that, we'll have storage revenue, we'll have term loan revenue, we'll be able to load it there.  At Lake Charles, we see enormous growth for ammonia. Everybody probably knows that the fertilizers to feed the people in the world is going to do nothing but grow depending on the experts 2% to 4% over the next 10 or 15 years. And now you've got this power side of it and fuel side of it, where ships are being built to burn ammonia as their fuel. You've got a bunkering for ammonia and then you've got South Korea and Japan and other places where ammonia is going to be blended with coal for fuel. So there's a big -- it's another big plus for NuStar in the ammonia offline they bought. We see a big future of ammonia, and it's interesting standpoint, what I just said, it really helps facilitate our natural gas transportation business as well. So we're very excited about where that's headed, and we'll do the same thing we hope as well at [Natera].

Our next question comes from Elvira Scotto with RBC Capital Markets.

Can you talk a little bit about what you're seeing, producer activity in the Haynesville? Looks like there was some decline on your system. Also, what you're seeing relative to what's embedded in your original expectations or your guidance? And then how you see that activity trending the rest of the year?

Yes. This is Mackie again. Certainly, lean plays throughout the U.S., Marcellus, Utica in the Northeast, parts of Oklahoma, Panhandle Texas and East Texas and certainly Haynesville. We've seen a slowdown. There's no [Indiscernible] when prices fall to about $50 above $60 at Henry Hub, it puts a lot of pressure on producers. So yes, we've seen it fall off fairly significantly in the Northern Haynesville for our interstate group, though, I got to get a shout out in that -- our volumes grow. And so yes, we've got to be more aggressive, our margins tightened, but we did a good job on our intrastate in North Louisiana. But yes, as far as our G&P business, we have seen it fall off. However, if you look at kind of what's happening, we saw a peak about 6 months ago with LNG exports of almost 15 Bcf. That's now down around 12 Bcf. There's another LNG facility coming on I believe in June or July. So we see growth, we start seeing demand like we believe we will overseas in Europe and elsewhere and the heat picks up this summer, we can see -- [Indiscernible] we can see demand jump up on 5 or 6 Bcf overnight. And so you see these declines in Haynesville or other areas, you're not going to be able to ramp up those that quickly. So we see pricing out the rest of this year, I think, getting as high as $350 or $360 by the end of the year, we think that possibly could be moved up that we could see higher prices mid or latter part of the summer with a hot summer, and if the LNG demand really picks up like we think it will. But yes, no doubt about it. It has been a tougher quarter on some of the main areas and Haynesville is one of those.

Okay. Great. That's super helpful. And then just going back to your Slide 8 and the comments that you made about the 8, 10 megawatt gas-fired electric generation facilities. You also then talked about kind of data centers. So I'm curious, are you having any conversations with some of these data centers or maybe some of the utilities regarding incremental capacity or potential expansion opportunities? Or how do you think about that part of the equation longer term?

Yes, we are. We are all the above. We're in conversations with anybody that wants to gas up our systems, a quick little story here. So 2 or 3 years ago, we started a strategy and agenda to anything within 10 miles of any of our intra-interstate pipelines, we need to go connect. And a lot of that was focused on power plants. So we've been doing that for a while, our team -- we got [Indiscernible] and her team have done an excellent job of connecting 2 plants, of extending agreements we have to power plants, but that also rolls over into a lot of other opportunities. And so we're looking at playing a pipeline to a large chip manufacturer in Texas and as well as that we will -- we're believers like everybody else, there is the data centers and especially around AI, it's going to happen. Whether that means over the next 5 or 8 years, it's going to go drive by 3 Bcf demand of gas-generated electricity or 8 Bcf. We don't know. We just know it's going up. So in combination with population growth, as I mentioned earlier, industry growth, ammonia growth, all the AI data centers, et cetera, power plant growth. We're talking to probably separate different power plants at least on fairly significant natural gas-fired generation expansions in Texas, a handful of Oklahoma as well. So it's just that common theme that Tom and I keep talking about in this call is that the demand for natural gas is going to do nothing but go up for many years to come, and we're excited that we have the assets that we believe will benefit the most from those opportunities.

Our next question comes from Zack Van Everen with Tudor, Pickering, Holt & Co.

Maybe just circling back on that last one on the data center side. I know you guys have probably one of the larger interest footprints between the Permian and call it, Dallas. We've seen a lot of development and talks of development for the data centers in that area. Just curious on what is your ability to expand some of those intrastate pipes to maybe see more of that power demand, whether it's in Dallas or Houston or other states?

Well, that kind of coincides a little bit what I just said. We really have made it our job to go to connect to every possible gas generating power plant in every state that we operate in. And we certainly have done that and have tremendous capability of doing more of that in Texas. We're already connected to approximately 55% to 60% of the power plants in Texas, either directly or indirectly, we have very strategically located storage facilities, both in North Texas and near Dallas and also in the [Indiscernible] because a lot of these AI unlike the crypto miners through a lot of times, you're making a lot of money off selling the electricity and not running their computers, "Hey, I can't do that". I think everybody knows it's got to have reliable, so it can't rely on renewables. So yes, if we need to add additional power plants to provide that electricity to help meet all the demand in the Dallas forward area, including AI expansion, we will certainly be a part of that. Look at our assets. I mean there's nobody as you just mentioned that's even close to be able to provide the services we can, especially for those type of markets.

Perfect. That makes sense. And then maybe switching to Blue Marlin. If you guys were able to get the favorable EIS study as well as the permit, do you have a time frame for when that would be commercially in operation?

I guess I would say it like this, is that we believe that once we receive the draft EIS that we are hopefully confident that within a year, we'll get our permit and our license. We're making certain assumptions of things that might happen in November. But certainly, we are -- the great thing about our project is unlike our competitors, it's a brownfield project. I mean we have a pipe party, a lot of it already in the ground or in the sea. And so we have a huge advantage there. We have a pretty good deal for costs of some of our competitors. We think we're significantly less than that. We have the kind of unique ability to move barrels from different basins that some of our competitors can't to feed that project. So we're very optimistic. But any way to finish the answer your question, just -- just say hypothetically by second, third quarter of next year, we're ready to go. I believe we're looking at it 2.5, 3 years? Yes, about 2.5 to 3 years before it would actually own such.

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

Once again, we appreciate all of you joining us today. Thank you for your support, and we really look forward to any follow-up questions that you all have in addressing those. Thank you all.

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