Good day, and welcome to the Energy Transfer LP First Quarter 2024 Earnings Conference Call. After today's presentation, there will be an opportunity to ask questions. 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% 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 one-time 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 one-time 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 one-time 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 two 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 finalized two 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 two projects, our total deliverability in 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 two 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 costs 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 a 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 for crude offtake. 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 the 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 conducted 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 to 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. At this time, we will pause momentarily to assemble our roster. The first question comes from Jeremy Tonet with JP Morgan.

Good afternoon. I just wanted to start off with regards to Crestwood. Now that the acquisition has been under your belt for 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 for potential synergies across commercial cost savings, what have you. Just curious for the 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 that 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 bring in fairly significant more barrels in Dakota Access. And there are others we can go out of every other area. 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. 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 the outlook at this point versus before, if it's similar or if anything has changed?

The short answer is similar. We had projected between $14.5 billion and $14.8 billion. We are now adding an extra $500 million for Sunoco for this portion of the year. That's the current situation in the process. The Sunoco team has done an excellent job and will update that figure as we move forward. For now, $500 million is the figure we are 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 are two aspects to consider regarding overall equity returns, Jeremy. If I understand you correctly, we are continuing to increase distributions. However, I want to emphasize that we are also focused on unit buybacks when we reach the right leverage position. What I mean is that while looking at our forecast, we will take advantage of opportunities in that area.

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 at sort of the 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 Gulf 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 two 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. 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 reliable, the grid more stable, and we are 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 to benefit from Permian differentials this year? And anything on the Warrior project as well.

Let me start with the conclusion. Regarding the Warrior project, our team is continuing their efforts. We are being very disciplined and cautious, and we will not announce the project until we feel confident about our long-term capacity. We are working diligently, but the pause in LNG has slightly affected some of our larger customers. Nevertheless, as many are aware, there is strong interest in another pipeline, likely by mid to late 2026. We are very optimistic about building the next pipeline from West Texas and will continue to put in the effort to reach that goal when the timing is right. The spread across Texas varies from month to month, but it is certainly over $300,000 a day, benefiting from these spreads. While we dislike the price fluctuations at Waha, they are a result of capacity constraints. A pipeline set to come online later this year will help alleviate much of this issue, and we are well-positioned to take advantage of the spread for the benefit of our customers and ourselves. Regarding intrastate revenue, we feel very fortunate with our U.S. assets, particularly in Texas, and the team managing those assets does an excellent job, especially during volatile times.

I appreciate the detailed answer. My second question is about mergers and acquisitions and how you view them. Considering your perspective on Energy Transfer, as well as Sun, which is independently operated but has significant overlap in some assets and business operations with ET, how do you approach M&A moving forward? What types of acquisitions or assets are more suitable for Energy Transfer compared to Sun, and is there a clear distinction between the two?

Yes, that's a very good question. We have dedicated a significant amount of time at Energy Transfer to strategizing. To begin with, we still believe that consolidation is a sensible approach in the midstream sector. In summary, we intend to continue evaluating various opportunities as we move forward. We will not be slowing down in that regard. When it comes to our focus, we are always looking for opportunities that benefit the entire value chain, from the wellhead to the water, across all commodities. Our strategy involves assessing assets based on how they integrate into the entire value chain when we make acquisitions. This approach provides us with excellent opportunities for both commercial and cost synergies. Now 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 the kind of wholesale fuel distribution terminal business, et cetera. And you're right, there are going to be some overlaps, and in those instances, we'll look at ways on a combined basis of what we can do. But Sunoco is going to continue to make those kinds 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 very good for the family from that standpoint.

You bet. Yes. And I want to elaborate much more on what Sun said or anybody that follows them. They're excited for them and they are kind of stepping up and growing up a little bit in one regard as far as different assets. There are some assets that overlap, and 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? 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 on LNG, we intend to own maybe 20% to 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 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 the 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 about the 8 to 10 megawatt gas-fired power plants you announced for Texas. Just to clarify, are these essentially peaker plants? Will you be supplying them with your own gas? And how should we consider the return on invested capital for an investment like this?

Yes, we will supply the natural gas for these using our own facilities. The two primary factors driving this are reliability for our assets, ensuring our plants run smoothly and gas is consistently available, and benefiting the grid. We don't anticipate operating these plants frequently. Although there are nearly 9,000 hours in a year, we project running them for about 1,300 hours, which is significantly less than their potential operation, and that will still meet our return on investment targets. This estimate does not account for unusual circumstances such as urea-related situations, cold weather, dramatic spikes in power prices, or benefits from ancillary services. As I mentioned, we are not implementing these for the purpose of generating substantial returns, but there is a strong possibility that the actual returns could exceed our projections.

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?

If we can hypothetically get FID by late third quarter or early fourth quarter, we believe we'll have it operational by the end of 2026 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 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 the mainline. What is your outlook for contracting coming up in a couple of years and balanced with the incremental barrels that you're getting from Crestwood?

We are very enthusiastic about Bakken and proud of our contributions to transporting oil from this exceptional region to refineries in the Midwest and Gulf Coast. It has proven to be a valuable asset for us. Throughout the years, we have faced recontracting concerns with various assets, which is not uncommon. However, we believe that despite occasional fluctuations, Bakken will remain the premier outlet for producers. It offers the best route for transporting production to places like Patoka, various Mid-Continent refineries, as well as refineries near Port Arthur and Houston, extending to Bayou Bridge and all the way to Lake Charles and the St. James areas, especially with our VLCC project in place. We are not particularly worried if other companies are hesitant to commit to long-term contracts; it still makes sense for us. Our confidence in this basin's stability over the next five to ten years remains strong. While we do not anticipate massive growth, we expect to see stable production flows as long as oil prices stay relatively strong. We believe we provide the best option for producers and are ready to work with anyone looking to commit long-term.

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? Should we think of this as maybe kind of a first look on a 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'm optimistic about natural gas-fired generation. So it's something that we will continue to look at, and it will be highly unlikely that we don't announce more of these as each quarter goes on. But 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 provide a 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 grow. Yes, John. So right now, we think it's a first step. There’s an opportunity to come back and significantly expand that market share.

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 with 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 other strategic locations. So yes, if we need to add additional power plants to provide that electricity to help meet all the demand in the Dallas-Fort Worth 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 being able to provide the services we can, especially for those types 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 would put it this way: we believe that once we receive the draft EIS, we are hopeful that within a year, we'll obtain our permit and license. We're making some assumptions about things that could happen in November. The advantage of our project is that, unlike our competitors, it's a brownfield project. We already have a lot of the infrastructure in place, either on the ground or in the sea, which gives us a significant edge. Our cost structure is also quite favorable compared to some competitors, and we believe we are notably lower in costs. Additionally, we have a unique capability to transport barrels from different basins, which some competitors cannot do. So we are feeling very optimistic. To answer your question directly, hypothetically by the second or third quarter of next year, we expect to be ready to proceed. We anticipate that it will take about 2.5 to 3 years before it is fully operational.

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.