Energy Transfer LP (NYSE: NYSE:ET) has announced a strong start to 2024 with its first-quarter financial results, highlighting an increase in adjusted EBITDA and distributable cash flow (DCF) compared to the same period last year.
The company's credit rating has seen an upgrade, and it has made significant strides in redeeming outstanding preferred units. Energy Transfer has also provided updates on several growth projects and has revised its 2024 organic growth capital guidance.
Key Takeaways
- Adjusted EBITDA rose to $3.9 billion, up from $3.4 billion in Q1 2023.
- DCF increased to $2.4 billion, compared to $2 billion in the previous year.
- The quarterly cash distribution per common unit is $0.3175.
- Credit rating upgraded to BBB by Fitch and S&P.
- Redemption of all outstanding Series C, D, and upcoming Series E preferred units.
- $460 million spent on organic growth capital in Q1, primarily in Midstream and NGL and Refined Product Segments.
- Expansion of NGL export capacity at the Nederland terminal and optimization at Marcus Hook terminal.
- Approval of eight natural gas-fired electric generation facilities and development of an ammonia hub concept.
- 2024 organic growth capital expenditures expected to be approximately $2.9 billion.
Company Outlook
- Adjusted EBITDA guidance for 2024 is between $15 billion to $15.3 billion.
- Focus on acquisitions that provide commercial and cost synergies.
- Plans to add ethane storage at Marcus Hook and prioritize reliability over significant returns with new gas-fired power plants.
- Optimism regarding the demand for products and services, with continued pursuit of new growth opportunities.
Bearish Highlights
- Decline in activity in the Haynesville area.
- The potential for higher natural gas prices in the future.
Bullish Highlights
- Successful extension of agreements with power plants.
- Confidence in meeting power demands in the Dallas Fort area and supporting AI expansion.
- Positive re-contracting outlook for Dakota Access.
Misses
- No specific misses were reported from the earnings call.
Q&A Highlights
- The company will evaluate M&A opportunities for consolidation in the midstream space.
- The timeline for the Warrior project depends on the final investment decision by late Q3 or early Q4.
- Open to adding assets that connect Permian to Corpus Christi.
- Belief in the future growth of the ammonia market.
- Anticipation of commercial operation for the Blue Marlin project in two and a half to three years.
Energy Transfer LP has expressed a strong commitment to ensuring reliable operations and grid security, particularly with the construction of gas-fired power plants in West Texas. These plants are not only expected to support the company's operations but also provide additional energy to the grid and generate revenue from ancillary services.
The company's strategy includes connecting pipelines to power plants within a 10-mile radius, which has proven successful, and exploring opportunities in sectors like data centers. With a significant connection to power plants in Texas and strategically located storage facilities, Energy Transfer is well-positioned to meet the growing demand for natural gas. The company remains optimistic about its future, with various projects in the pipeline aimed at enhancing its portfolio and service offerings.
InvestingPro Insights
As Energy Transfer LP (NYSE: ET) demonstrates a strong financial performance in the first quarter of 2024, several metrics and tips from InvestingPro can provide a deeper understanding of the company's market position and investor considerations.
InvestingPro Tips for Energy Transfer LP indicate that the company is a prominent player in the Oil, Gas & Consumable Fuels industry and has a notable track record of maintaining dividend payments for 19 consecutive years. This consistency in dividends, coupled with a current high dividend yield of 7.82%, showcases the company's commitment to returning value to shareholders. Additionally, the stock's low price volatility may appeal to investors seeking stability in their energy sector holdings.
Key InvestingPro Data metrics further enrich the context of Energy Transfer's recent performance:
- The company's market capitalization stands at $54.89 billion, reflecting its significant presence in the industry.
- With a Price/Earnings (P/E) ratio of 14.68 and an adjusted P/E ratio for the last twelve months as of Q4 2023 at 14.35, the company's valuation appears reasonable relative to its earnings.
- Energy Transfer's revenue for the last twelve months as of Q4 2023 was $78.59 billion, despite a slight decline in growth by -12.56%.
These financial indicators, alongside the company's strategic growth projects and operational updates, suggest that Energy Transfer is navigating the current market with a blend of stability and forward-looking initiatives. For investors considering Energy Transfer LP, additional InvestingPro Tips are available to provide a comprehensive analysis of the company's prospects. Use coupon code PRONEWS24 to get an additional 10% off a yearly or biyearly Pro and Pro+ subscription, and access the full suite of 10 additional InvestingPro Tips for a more informed investment decision.
Full transcript - Energy Transfer LP (ET) Q1 2024:
Operator: Good day, and welcome to the Energy Transfer LP First Quarter 2024 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. 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.
Tom Long: Thank you, operator, and good afternoon, everyone. And welcome to the Energy Transfer's 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 full 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 of our non-GAAP financial 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, equivalent 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 Cs and Series Ds 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 Product Segments, excluding SUN and USA Compression (NYSE:USAC) 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 Trunkline 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. terminals. Our NGL terminals continue to benefit from increased demand both in 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 customers 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 FID two projects that will de-bottleneck our West Texas Gateway and Lone Star Express pipelines. On the Gateway pipeline, a de -bottlenecking 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 take-away 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 into 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, the 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 and 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 Trunkline 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 TotalEnergies (EPA:TTEF) 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 conducts 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 off-take 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 eight 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 standalone blue ammonia projects, and the market response to this approach has been favorable. Yesterday, we entered into an agreement with CapturePoint that commits CO2 from our treating facilities in northern Louisiana to the capture and sequestration project being jointly developed by CapturePoint 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 deep bottlenecking 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 buildouts 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 3rd. 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 remain 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 unit holders. That concludes our prepared remarks, operator. Please open the line up for the first question.
Operator: [Operator Instructions] The first question comes from Jeremy Tonet with JPMorgan.
Jeremy Tonet: Hi. Good afternoon. Just wanted to start off with regards to Crestwood. Now that the acquisition has been under your belt for a little bit here, I'm wondering 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.
Tom Long: Yes. Jeremy, 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. Then I'm looking over at Mackie who will comment on the commercial side of it.
Mackie McCrea: 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. Once again, we're doing that with Crestwood. Some of it 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 to delay any kind of expansions we may need out there. There’re also some things going on up in the Bakken that we can't really elaborate on, but very significant opportunities up there help not only fill up some of their available iron out with available processing capacity, but also bring in fairly significant more barrels in Dakota access. And there's others we can go out of river 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.
Jeremy Tonet: Great. Thank you for that. 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?
Tom Long: Similar is going to be the short answer. We had the $14.5 billion to $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 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 so.
Jeremy Tonet: 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?
Tom Long: There's obviously two as far as just the overall equity. Jeremy, if I understand you correctly, equity returns meaning that we continue to bump the distributions. But 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 at it, the forecast will be opportunistic there.
Operator: Our next question comes from Spiro Dounis with Citi.
Spiro Dounis: Thanks, operator. Afternoon, everybody. Maybe to 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 under 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, Warrior, Gulf Run Expansion, anything to kind of point to there if you can get us over that.
Mackie McCrea: Yes, Spiro, this is Mackie. Everything that we have in right now is what we're going to do. We, next 30, 60, 90 days, we may make significant progress on some of the things we're working for, but the things that we announced recently, the additional $400 million things that we have approved here recently that we've kicked off. Several of those will actually come online later this year. All of them will come online kind of within two years or earlier. So, yes, we're adding more cash flow, but we're also going to see revenues much quicker than, of course, a lot of our projects.
Spiro Dounis: Got it. It's helpful. And I just want to go to the slides. One sort of point is the new opportunities you're evaluating on the power plant side to connect them to 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 greenfield storage expansions?
Tom Long: Yes, I'll tell you what. 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-megawatt at a time facilities are number one reliability. It's to make sure that when we have glitches off the grid, especially out in West Texas, where those are 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 [URE] 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 the grid to benefit producers, for example, upstream that might have issues with losing 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 reliable, the grid more stable. In addition to that, we won't go into this in great detail, but there's also a lot of revenue benefits from law 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.
Operator: Our next question comes from Keith Stanley with Wolf Research.
Keith Stanley: Hi. Good afternoon. I wanted to just 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? Thanks.
Tom Long: 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 a project unless we feel good about all of our capacity so as long term. So we're not going to run out in FID Warrior when we have capacity on our existing system that we're still terming up. So we're working hard. The pause in LNG has impacted us a little bit with some of the bigger customers that we're working with. However, they remain, as everybody in this call probably knows, a strong interest in another pipeline, probably by mid to late 2026. We're very optimistic that we will be in 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 from month to month, but it's certainly north of 300,000 in a day, Mcf per day that we have available that are benefiting from these widespread, we sure hate to see prices do it, 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 that will alleviate a lot of that, but certainly the way we're positioned is very well to take advantage of that type of spread where 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 in the team, we have that's operating those assets where really cold weather times or 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 back home. 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, May time and summer where we're able to capture kind of some unexpected revenue that will always be there at very volatile times at some level.
Keith Stanley: 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?
Tom Long: Yes, listen, that's obviously a very, very, very good question. We spend 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 NuStar, 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 kind of 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 accreted 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, so.
Mackie McCrea: You bet, yes, and won’t elaborate much more what Sun said or anybody that follows them, they kind of explained that 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 in potentially partnering up with them, so we are in discussions of possibly doing that, and if opportunities arise that are very beneficial and accreted to both of our partnerships, as we do with other at JVs, we look forward to catching those opportunities as time moves forward. Did that answer all your question there?
Operator: Our next question comes from Manav Gupta with UBS.
Manav Gupta: Hi, 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 of you over there would be very helpful. Thank you.
Tom Long: 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 hypotheticals. Let's just think, everything, the pause gets lifted, for example on LNG. We intend to own maybe 20%, 25% of that. That could start earlier that is probably not likely. But it just kind of depends on a Warrior. Does it pick up later in the year, 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, that kind of a spin rate wrong right now, at least through ‘25, that's pretty consistent. But we've got a number of projects I just alluded to in different segments that might begin quicker than others, and that would, of course, cue it one way or the other.
Manav Gupta: Thank you. A quick follow-up. At Marcus Hook, I think, on the last quarter call, you spoke about construction of the first phase of optimized and precision project that could add ethane refrigeration and storage capacity. Is there any update on that one? Thank you.
Tom Long: No update. We're excited about 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 Marcus Hook for many years to come.
Operator: Our next question comes from Michael Blum with Wells Fargo.
Michael Blum: Thanks. Good afternoon, everyone. 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 investor capital for an investment like this?
Mackie McCrea: Okay. Hey, Michael, this is Mackie. Yes, we will provide the natural gas for these with our own facilities. As I mentioned, the two 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 other. There's almost 9,000 hours in a year when we have run the economics and run them about 1,300, which we think will be significantly lower than what they will run. And that meets our rates of return hurdle that has no anomalies in it in regards to like a URE-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 law and things like that. So, like I said, 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.
Michael Blum: Okay, got it. Thank you for that. 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?
Tom Long: Pretty quick. No, probably by, we typically, I say typically a lot of changes over the last three or four 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 of 2026 at the latest.
Operator: Our next question comes from Theresa Chen with Barclays.
Theresa Chen: Good afternoon. Follow-up question related to the M&A topic. Related to your comment about wanting that wellhead to water strategy. So performance at 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?
Tom Long: 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 Nederland Houston assets to benefit those, as well as our downstream pipes with Bayou Bridge and our VLCC project. But certainly if there are any assets for sale, that can move more crude, for example, from Midland down to Corpus, we'll always look at those. But remember, those are our 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 us about. We're certainly open to that, but that's probably a better NuStar question related to Corpus.
Theresa Chen: Got it. And looking at the Dakota Access Re-contracting outlook and all the way through Bayou Bridge, just taking into account TMX now being online, shipping not just WCS West, but also fin crude, which seemingly has indirectly compressed Bakken just given the connection to mainline, what is your outlook for Dakota re-contracting coming up in a couple of years and balanced with the incremental barrels that you're getting from Crestwood?
Tom Long: Yes, we love Bakken, we love what we've done out of there, proud of the role we've played 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 re-contracting concerns on different assets, and that's just not one of them. We think long term there's slips 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, Dakota and into many of the mid-contract refineries, as well as through 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 it over for a long period of time or a period of time that makes sense to us. We may go year at a 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 of 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, we're already talking to some of them, but it's certainly not something we would sleep on.
Operator: Our next question comes from John Mackay with Goldman Sachs.
John Mackay: Hey, thanks for the time this afternoon. 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?
Tom Long: Yes, John, in fact, I thought I said it earlier, I probably didn't make it clear enough. Yes, these were first steps. There’re grid problems all over the country and Texas is no exception. A lot of people are moving in Texas, a lot of data centers, a lot of AI data centers, crypto miners are still coming in, industrial growth. I mean, it's just, we're so optimistic on, for natural gas fire generation. So it's something that we will continue to look at and we will, it'll be highly unlikely if we don't announce more of these than 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 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 in this mother of our bigger cryo complexes route around the state. So it's an area that we will continue to grow.
John Mackay: 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?
Mackie McCrea: Yes, we keep talking about how excited we are for all of our fossil fuel business, especially natural gas, and it's incremental on 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. Well, we retain an ownership of some level, very likely or possible, but what really drives us is, I'll give an example. One of these ammonia plants will deliver approximately 120,000 to 130,000 Mcf a day. At Lake Charles, we're looking at anywhere from maybe five to seven 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 terminal revenue. We'll be able to load it there. At Lake Charles, we see enormous growth for ammonia. Everybody probably knows that fertilizer is to feed the people of the world. It's going to be nothing but growth, 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 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 and the ammonia hub they bought. We see a big future in ammonia. And it's interesting, ET standpoint, as 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 on [inaudible].
Operator: Our next question comes from Elvira Scotto with RBC Capital Markets.
Elvira Scotto: Hey, good afternoon, everyone. 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?
Mackie McCrea: Yes, this is Mackie again. Certainly lean plays throughout the US. Marcellus with Utica in the Northeast, parts of Oklahoma, Panhandle, Texas, and East Texas, and certainly Haynesville. We've seen a slowdown. There's no if, and, or buts. When prices fall to about $50, $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've got to get a shoutout in our volumes group. And so, yes, we've got to be more aggressive. Our margins tightened, but we did a good job on our intra -states in North Louisiana. But yes, as far as our GMP business, we have seen it fall off. However, if you look at kind of what's happening, we saw a peak about six 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 can see a 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 demand jump in. We can see demand jump up by five or six Bcf overnight. And so you see these declines in Haynesville and 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 $3.50 or $3.60 by the end of the year. We think that possibly could be moved up, that we could see higher prices amid the latter part of summer with a hot summer, and if the LNG demand really picks up like we think it will. But yes, no doubt, that's been a tough report on some of the lean areas and Haynesville's one of those.
Elvira Scotto: 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?
Mackie McCrea: Yes, we are. We are all these, we're in conversations with anybody that wants to gas off our systems. A quick little story here. So two or three years ago we started a strategy, an agenda that anything within 10 miles of any of our intra or interstate pipelines we need to go connect. A lot of that was focused on power plants. So we've been doing that for a while. Our team, Beth Hickey and her team had done an excellent job of connecting to 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 laying a pipeline to a large chip manufacturer in Texas. And as well as that, we're believers like everybody else. The data centers, and especially around AI, it's going to happen. Whether that means over the next five or eight years, it's going to grow 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 seven or eight different power plants at least on fairly significant natural gas power generation expansions in Texas, and handful in Oklahoma as well. So it's just that common theme that Tom and I keep talking about during 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.
Operator: Our next question comes from Zach Van Evren with Tudor, Pickering, Holt & Co.
Zach Evren: Perfect. Thanks for taking my question, guys. Maybe just circling back on that last one on the data center side, I know you guys have probably one of the larger intrastate footprints between the Permian and call it Dallas. We've seen a lot of development and toxic development for the data centers in that area. Just curious on what is your ability to expand some of those intrastate pipes to maybe feed more of that power demand, whether it's in Dallas or Houston or other states?
Mackie McCrea: 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 various strategically located storage facilities, both in North Texas, near Dallas, and also in their [inaudible] because a lot of these AI, unlike the crypto miners, who a lot of times are making a lot of money off selling electricity and not running their computers, AI 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 tie at additional power plants to provide that electricity to help meet all the demands at the Dallas Fort area, including the AI expansion, we'll 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.
Zach Evren: 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 timeframe for when that would be commercially in operation?
Mackie McCrea: I guess I would say it like this, is that we believe that once we receive the draft EIS, that we're hopeful and 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. We have a high 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 cost for 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, whether anyway to finish the answer to your question just say hypothetically by second third quarter of next year we're ready to go. I believe we're looking at a two and a half three years. Yes, about two and half to three years before it would actually go in the surface.
Operator: This concludes our question and answer session. I would like to turn the conference back over to Tom Long for any closing remarks.
Tom Long: 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 y'all have in addressing those. Thank y'all.
Operator: The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
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