Thank you, operator, and good morning, everyone, and welcome to the Energy Transfer second quarter 2026 earnings call. I'm also joined today by Mackie McCrea, Dylan Bramhall, 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 morning. As a reminder, our earnings release contains an update to guidance and a thorough MD&A that goes through the segment results in detail, and we encourage everyone to look at the release as well as the slides posted to our website to gain a full understanding of the quarter and our growth opportunities.

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 details in our Form 10-Q for the quarter ended June 30, 2026, which we expect to file later this week.

I'll also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website.

Let's start today with going over our financial results. For the second quarter 2026, we generated adjusted EBITDA of approximately $5.1 billion compared to approximately $3.9 billion for the second quarter of last year.

DCF attributable to the partners of Energy Transfer, as adjusted, was approximately $2.6 billion compared to approximately $2.0 billion for the second quarter of 2025. These results were supported by strong performance in all of our business segments, including record midstream gathering volumes, NGL transportation volumes, NGL export volumes, and crude oil transportation volumes for the quarter.

For the first half of 2026, we spent approximately $2.6 billion on organic growth capital in the intrastate, midstream, NGL refined products, and interstate segments, excluding Sun and USA Compression capex. Turning to our 2026 adjusted EBITDA guidance, given our continued strong performance in the second quarter across all of our segments, we now expect our full year adjusted EBITDA to range between $18.8 billion and $19.1 billion, which is up approximately a half a billion dollars at the midpoint compared to our guidance range provided on last quarter's earnings call.

Let's go to the organic capital guidance. We now expect our 2026 organic growth capital expenditures to be between $5.6 and $5.9 billion, excluding Sun and USAC.

Our growth capital spend remains aligned with the major themes driving our business today, including the increasing demand for natural gas and natural gas infrastructure to support the growing needs for power generation, growth in the Permian, and the growing global demand for natural gas and natural gas liquids. As a reminder, the majority of these growth projects are contracted under long-term commitments and expected to generate mid-teen returns and considerable earnings growth over the next decade or more.

Beyond these projects, we have a significant backlog of opportunities that are expected to support future growth. Now turning to our results by segment for the second quarter, I'll start with NGL and refined products.

Adjusted EBITDA was approximately $1.3 billion compared to approximately $1.0 billion for the second quarter of 2025. This increase included record exports out of both our Nederland and Marcus Hook terminals in the second quarter, in part driven by new chilling capacity placed into service last year at Nederland.

In addition, we saw record throughput across our NGL pipelines related to higher Y-grade and NGL throughput, as well as higher throughput at our Mont Belvieu fractionators. Results for the second quarter also included an increase of $212 million from higher premiums from the sale of NGLs for both export and domestic supply, as well as increased margins from our product optimization and blending operations.

This also included gains related to our NGL and refined products inventory hedges, $27 million of which we anticipate will be offset in the fourth quarter of this year. For midstream, adjusted EBITDA was approximately $884 million compared to approximately $768 million for the second quarter of 2025.

This was due to record volumes in the Permian Basin, which increased 5% as a result of new processing placed into service and improved plant utilization. In addition, we saw an approximate $88 million increase due to higher NGL prices compared to last year.

For our crude oil segment, adjusted EBITDA was approximately $834 million compared to approximately $732 million for the second quarter of 2025. During the quarter, we saw continued growth across several of our crude pipelines, terminals, and gathering systems.

Results also included an increase of $106 million related to favorable market conditions, including pipeline and export arbitrage, higher crude oil prices, and Strategic Petroleum Reserve activity at our Nederland Terminal. As a reminder, in the first quarter of this year, we had a benefit of approximately $60 million related to our crude inventory value that was offset by hedge losses in the second quarter.

In the interstate natural gas segment, adjusted EBITDA was approximately $481 million compared to approximately $470 million for the second quarter of 2025. This increase was primarily due to increased parking, storage, and liquids revenue, as well as higher contracted volumes and utilization on several of our pipelines, including Panhandle Eastern, Transwestern, and Florida Gas Transmission.

For our intrastate natural gas segment, adjusted EBITDA was approximately $377 million compared to approximately $284 million in the second quarter of 2025. This was primarily due to an increase of approximately $113 million from wider basis differentials, as well as an increase of approximately $17 million from early volumes during the commissioning of the Hugh Brinson Pipeline.

This quarter's results once again demonstrate the quality of Energy Transfer's asset base and unique operating model and further strengthen our belief that the market fundamentally underappreciates the value of our business. Turning to an update on some of our major growth projects and starting with the natural gas side of our business, we are pleased to announce that our Hugh Brinson Pipeline is now in commercial service with progress being made toward placing the full Phase 1 capacity of 1.5 Bcf per day in service.

Hugh Brinson shipper contracts are coming online in stages based upon the contractually specified effective date in each agreement. We anticipate that Hugh Brinson will be capable of flowing the full Phase 1 capacity by September the 1st of 2026, assuming pipeline commissioning activities continue to progress as scheduled.

We continue to expect Phase 2, which includes additional downstream compression, to be in service in the first quarter of 2027 and to come in under budget. In addition, during the second quarter, we completed another 14-mile lateral off the Hugh Brinson Pipeline in Abilene, Texas, and is now ready for service.

During the quarter, we also entered into an agreement with Crusoe to construct the facilities required to provide natural gas to support previously announced 900-megawatt expansion at the AI factory campus in Abilene, Texas. Separately, we expect to see additional growth opportunities materialize in the region.

Next, we are making good progress on our Desert Southwest pipeline project. FERC recently completed six in-person and two virtual scoping meetings along the proposed pipeline route throughout Texas, New Mexico, and Arizona.

In addition, as a continuation of our comprehensive stakeholder engagement program, our teams continue to actively engage with elected officials, county leadership, landowners, and associated communities along the route with discussions remaining very positive. On our last call, we announced the Springerville Lateral, which is an approximately 120-mile extension of our existing Transwestern Pipeline and is expected to be in service in the fourth quarter of 2029.

This 30-inch pipeline will have a capacity of approximately 625 million cubic feet per day and extended south to natural gas power generation that is expected to replace two coal-fired plants. We have now locked in pipe and compression costs, and outreach is underway with tribal, state, and federal stakeholders.

In Oklahoma, the first of our four connections to serve new power plant loads went into service earlier this year. The next two are ready for service, with the remaining expected to be in service in the fourth quarter of 2028.

In total, these will provide approximately 300 million cubic feet per day of new demand growth. In addition, we are finalizing negotiations to serve approximately 250 million cubic feet per day of new power plant demand in Oklahoma.

Overall, we're now seeing interest from customers in increasing the commitments that they have previously made for our natural gas services to large data centers and power plants at or near these sites. This includes two customers in Texas who recently added a combined 100 million cubic feet per day to their contracts.

We expect this trend to not only continue, but grow in scale. We're highly confident in our ability to reach FID on many more of these type of opportunities, and remain in advanced negotiations with customers to provide significant volumes associated with our natural gas business in Texas, Oklahoma, Arkansas, Louisiana, Ohio, Illinois, and many other states along our pipeline network.

Now looking at the Permian processing expansions, our Mustang Draw 1 plant was placed into service in June, and we are already running near capacity for our Midland Basin processing complex. We continue to expect our Mustang Draw 2 plant to be in service in the fourth quarter of this year.

Looking at our liquids business, in June, we announced approximately 240,000 barrel-per-day ethane export expansion at our Nederland Terminal to meet additional customer demand. The project will also provide an incremental 55,000 barrels per day of LPG capacity.

In addition, we'll be expanding our Mont Belvieu to Nederland pipeline system to service the increased refrigeration capacity and two additional NGL ship docks. The project is expected to be placed into service in stages beginning in 2028, with the docks expected to be in service in mid-2029.

100% of the ethane export capacity has been committed under long-term agreements running into the 2040s, and 80% of these volumes are expected to be delivered to markets in Asia that are outside of China. Growth capital for the project is expected to be slightly over $1 billion, and this 2026 capital expenditure was previously included in our growth capital guidance.

In the second quarter, we completed upgrades to our Lone Star Express NGL Pipeline, which provides more than 90,000 barrels per day of incremental Permian NGL takeaway capacity on the pipeline system, and led to record Y-grade volumes out of the Permian for the second quarter. As a result of our total deliverability into Mont Belvieu is now more than 1.3 million barrels per day, and our Permian NGL takeaway pipelines are currently approximately 95% utilized.

Also in the second quarter, we signed long-term transportation and/or fractionation agreements for upwards of approximately 300,000 barrels per day on our Y-grade assets that extend into the 2030s. At Mont Belvieu, our fractionators remained fully utilized in the second quarter.

We expect volumes on our new Frac 9 to ramp up quickly upon its anticipated in-service late this year. Results for the second quarter were better than expected, with market volatility contributing to significant upside, in addition to the record volumes and strong base business performance.

As we have previously said, additional upside to our forecast is expected to be dependent upon the duration and impact of market disruptions, and our business is uniquely positioned to capture these benefits should they continue. We continue to expect the ramp-up of Mustang Draw, Hugh Brinson, and other projects to contribute to additional growth in 2026.

With Hugh Brinson now capable of commercial service and the full Phase 1 expected to be ready ahead of schedule, we expect it to provide significant future upsides and further establish Energy Transfer's natural gas pipeline business as the premier option for customers seeking dependable natural gas supply. With a large slate of growth projects under construction, we are extremely focused on project execution, as evidenced by Hugh Brinson.

Completing these projects safely, on time, and on budget remains among our top priorities. We also remain very focused on capital discipline, targeting a long-term annual distribution growth rate of 3% to 5% and maintaining our leverage targets of 4 to 4.5 times EBITDA.

Our unmatched connectivity allows us to move energy from every major supply basin to major trading hubs, power plants, data centers, city gates, industrial complexes, and other downstream markets throughout the US, as well as to international markets through our export terminals. This concludes our prepared remarks.

Operator, please open the line up for our first question.

Good morning, and thank you for taking my questions. First, I'd like to congratulate Mackie on his retirement.

Thank you, Mackie, for your many years of leadership. Looking at the fundamentals, if you wouldn't mind elaborating more on the drivers of the volumetric outperformance demonstrated across your segments in second quarter and how this outperformance helps frame the expectations into 2027 or second half of 2026 as well as 2027 plus, taking into account recent commentary from producer customers?

As we think about the remainder of this year, going back to Tom's comments about the factors that could drive the low to high end of guidance, can we get more color on the impact and duration of these market disruptions and which key variables are you looking at as you determine the effect of these disruptions on the remainder of your year?

Hey Theresa, this is Dylan, and let me try to address all that by taking us back and looking at the full first half of the year. As most of we increased guidance in the first quarter by $750 million, and that was really related to approximately $600 million in Q1 results and $150 million from just stronger performance that we saw continuing through the balance of the year in our business.

In this quarter, we were increasing another 550. The majority of this is strong beats across almost all segments this quarter.

Midstream, intra, crude were all about $100 million roughly beat and NGL over 200, as we really saw just strong activity across the board on the NGLs. Everything from stronger export and domestic sales, higher fees across the docks, stronger blending margins.

This is all setting up for a stronger second half of the year. Now, when we look at the plan, we expect the base business to remain strong.

We expect volumes to pick up and grow across all our segments as we go through the back half of the year. A number of projects obviously coming online here that are going to help drive this.

The early start to Hugh Brinson is super important to us. Very pleased to get that online, coming online as we are looking at that coming online early and under budget, which we think is really important because we need to remember this is the same team, these are the same folks that are going to be working on Desert Southwest.

We think this is a great precursor to what we're going to deliver on that project as well. Those contracts, those are going to step up here as we go through the balance of the year, and so we're really going to see the majority of that impact really starting January 1st as we get to full for all the Phase 1 contracts will be kicked in by then.

Mustang Draw 1 and 2, Mustang Draw 1 is on. We're hitting new records in the Permian almost daily there as we really push these assets to full, and so we'll see that impact through the balance of the year.

That'll pull through also into our NGL volumes. Mustang Draw 2 will come on late in the year.

We'll expect that to fill up very quickly, but pretty limited impact to 2026. That'll be a big '27 push, same way as the Hugh Brinson Pipeline.

Then Frac 9 additionally late this year, once again, we expect that to start filling up pretty quickly when that comes online, but it's happening late in the year, limited 2026 impact there. When you look at all these, the base business is strong, expect that to continue through.

Going over to the volatility we've seen, the wider spreads, the higher commodity prices that we all saw happen through Q1 and Q2, we don't really have much of that in our plan for the back half of the year. The more of this that continues to play out, I think, is setting us up to where with some of this volatility, we can very easily achieve that high end of the guidance range.

Thank you so much for that.

Hey, this is Mackie, Theresa.

Please.

Hey, Theresa, I'm sorry to interrupt. This is Mackie.

Thanks for your nice comments, but let me summarize a little bit what he just said. The first half of this year shows the extreme benefit and value that our assets have in every condition.

Our ability to move gas through our intra, interstate pipelines west to east, east to west, from all the major hubs, our ability to chill less ethane, more ethane, more propane, more butane. I think what happened, of course the war had a lot to do with it, but there's always weather variables, whatever, but I think it really showed the diversity of our assets and our ability to pivot and benefit from whatever is happening either domestically or internationally in a big way.

I think our assets and our people proved that the first half of this year.

Thank you. Just to clarify, Dylan, in relation to the commodity price environment, the volatility that we've seen over the past few months, is the takeaway that without a significant uptick in volatility, your revised guidance is very achievable, and if we were to see this volatility persist or tick higher, that would be additive to the updated range?

Yes, absolutely.

Great. Turning to your dry gas assets, great to see the progress on Hugh Brinson, Phase 1 really coming in ahead of your own expectations, it sounds like.

Can you provide some more color on how Desert Southwest is progressing, including permitting and overall project execution? Given the scale and visibility of this project, how has that development process progressed relative to your own expectations?

As you think about maximizing the value of that corridor in general, what opportunities exist to add incremental demand through laterals, power generation connections, data center load, and so on off of Desert Southwest and Transwestern over time?

Hey, Theresa, this is Mackie again. We were excited about Hugh Brinson, and we're equal as excited about DSW.

It's going to be a game-changer, especially for that part of the world. It remains to be seen how much new markets develop.

Even yesterday, we had a call from utility in southern New Mexico wanting to tie to us, we'll see kind of the upside to New Mexico. There's enormous growth in the Phoenix area and in Arizona.

Grant and his team have done a great job on government relations getting out in front of this to all stakeholders, all constituents, whether it's the indigenous folks, which are many different in that state, and then all the both local and state and federal agencies. We're on top of that on a day-to-day basis.

As far as our expectations, we're probably a little ahead of our expectations on survey permission and on making progress on getting this pipeline built. Everything is going exceptionally well.

As everybody knows, the steel was ordered a long time ago. The compression was ordered a long time ago.

We've got this same team, as Dylan mentioned, with Mike and what his team has done on Hugh Brinson. We expect the same on DSW, it's going to be a great benefit for our assets, for our partnership, for the southwest portion of the United States, and we're very excited and expect to bring that on time in the latter part of 2029.

Thank you.

Hi, good morning. Are you surprised that Waha basis has narrowed so quickly, and do you believe that there's still stranded gas in the Permian waiting to come online?

Again, congrats on getting Hugh Brinson online early.

I think it goes without saying that Waha's been hurting, and producers have been hurting. They've been hurting for quite a while, and everything's been bottled up there.

Boy, Hugh Brinson has unleashed it, and I know there's another pipeline also that's coming online, if not already. Common sense, when you have all of a sudden a Bcf growing to maybe 4 or 4.5 Bcf by the first quarter of next year, things are going to get better, and that's already proven itself.

This is not unexpected. It probably has narrowed quicker than we thought, which goes to the second part of your question.

There's a lot of pent-up volume, a lot of shut-in gas, a lot of DUCs that they bring online, and a producer has been holding back, and this is really going to unleash production in a big way. Oil for sure, but on the gas front and the NGL front, volumes are going to grow exponentially.

Who knows if we can really fill up 4.5 Bcf in the next year. We'll see, but we're very excited about bringing that on, and I know our customers are as well.

Very clear. Thank you.

Congrats on the recent ethane export expansion. Can you talk about how you expect that capacity to ramp?

I know you talked about when the docks are coming in, but are there other limiters like VLEC builds or just the time for the international ethane crackers to come online, or I don't know if those are new international ethane crackers, but any more you can give on how you expect that to ramp would be helpful.

Hey, yeah, this is Adam. We've timed it to where we expect the units to start up in mid '28 and then continue to ramp through mid '29.

That coincides with what our expectation is from our customer, which these are new build crackers. There will be a ramp reflective of them bringing two units online.

Very clear. Thanks, Adam, and congrats to you, Mackie.

Thank you.

Hi. Good morning.

There's a reference in the release to expecting new gas pipeline announcements later this year for power customers. Are you referring to larger backbone-type projects you're making progress on or more laterals for data center demand?

All of the above. We've got numerous opportunities, some you're aware of, some you're not, on laterals that are less than 15 or 20 miles, some just a few miles.

Then, yes, we are working on at least one large intrastate pipeline, and we're also working on another interstate pipeline. We're a little premature to talk about that, very optimistic we'll get those to the finish line, and hopefully we can talk more about those in November.

Great. Second question.

The Green Chile project for Project Jupiter for Oracle, is the plan now to reroute around the New Mexico state lands? Then looking forward for Desert Southwest, can you talk about regulatory strategy for New Mexico and how the process for Desert Southwest should be different than what we saw with Green Chile?

Hey Keith, this is Adam. I'll take the first half and let Mackie jump in on the second half.

On Green Chile, without getting into specifics, we've been very focused on that project and won't go through exactly kind of what the process from here on is, but we do and have been working with both the FERC and the BLM and all the stakeholders that are involved, and are very confident that they understand the importance of these data center projects and the importance on the ability to execute through the regulatory process to be able to bring these projects, which are very important to our industry and the country online. We're in constant communication with them and are very confident this pipeline will be put into service and will be ultimately successful.

I'll answer the second part of that. The answer is no.

We don't anticipate any similar-type challenges on DSW, primarily what the issue is it's the data center. As we know in this country for years and years there's been all these false beliefs about climate change, and the world's coming to an end, and a lot of those same environmental activists are also shifting over and now they're trying to stop data centers.

It's kind of become a four-letter word. We think Oracle has done a much better job of getting out the facts of how these are closed-loop systems, they're not using nearly as much water as being advertised.

This particular case, they've actually gone to Bloom technology, which is a lot less emissions. This we believe is much more of a data center-focused kind of protest activity.

As Adam just said, we're confident we're going to get there. Maybe delayed a little bit from what we first anticipated, but we're going to get there.

As I said, DSW is moving along very well.

Very helpful. Thank you.

Hi, good morning.

Morning.

Good morning.

Mackie, wishing you the best of luck in retirement, and appreciate all your perspectives over the years. Just want to go back to the Permian a little bit more, if we could, and as it relates to Hugh Brinson 2, if you could just help us think through, I guess, the rate of ramp there, just trying to think of when that's going to be fully capable.

Yes, we really haven't changed Phase 2. We still anticipate being on probably mid first quarter, maybe maybe as late as March 1st, but it could go sooner.

Like I said, Mike and his team has done such a great job, we don't put anything past them being early. Right now, kind of mid second quarter I'm sorry, mid first quarter.

Got it.

This could take commissioning flows in the fourth quarter, early like what we've seen with Phase 1?

The last phase is predominantly compression, and so as we get that in, we'll be starting to commission very likely sometime in latter part of January, early part of February.

Got it. That's helpful.

Thanks. Just one last one, if I could.

With regards to incremental Permian egress needs, how do you see things unfolding at this point as far as when the basin would need more egress, and where do you think that gas wants to go, and how is ET's strategy there?

What a great question for us. Where does it want to go?

You can't really ask a lot of companies that because they don't have the ability to get it to where people want it to go. A lot of the customers on Hugh Brinson are actually Florida customers.

We'll take volume to wherever our customers, our shippers want it to go, and we have such a vast capability of taking it from the Permian Basin, moving it to Phoenix, as we just talked about, moving it to South Texas, moving it to the Dallas-Fort Worth area, to Carthage, East Texas, of course to Katy Houston Ship Channel. We have enormous capabilities of moving it west to east, as we've alluded.

We also have a great capacity to move from east to west, which some of our customers, especially power plants and data centers, are wanting to source there from Katy and Carthage, which we can do and nobody else really can. We're set up very well in Texas, and likewise in Louisiana and going east.

We have the enormous capability of taking an MMBtu from a field in southwestern Pennsylvania and delivering it to a customer on the coast of Louisiana or even to Florida. The answer to that question is we will move volume and move MMBtus wherever the customers want it to go.

Got it. That's very helpful.

Thank you.

Hi, thank you so much for the time. First, you pointed to some NGL recontracting into the 2030s.

Was wondering if you could remind us what your recontracting exposure is through the end of the decade. Are you seeing downward pressure on rates or has the expected influx of gas and those associated NGL volumes impacted market pricing or created some type of more balanced supply-demand dynamic?

Hey, this is Adam. Progress that we made year to date on recontracting our Y-grade business out of the Permian.

We mentioned in our prepared remarks that in the last quarter, we signed 300,000 barrels a day of Y-grade deals, and this plus what we're expecting out of the growth in our midstream segment coming from our affiliates, we feel like puts us in a really great position through the balance of the decade on our Y-grade business, where we now can kind of turn our focus towards expansion at Mont Belvieu and looking at things like potential new fracs, additional new ethane exports, given that our Y-grade business really is what feeds the beast. The first part around rates, we are recontracting at market rates, and there has been more capacity brought online, but we do believe that we've seen the bottom of those rates, and that we expect going forward that all additional contracting will be at higher rates.

Got it. Appreciate that color.

Then I guess sticking on recontracting, Enbridge did note a rerouting of ML2, which does require capacity elsewhere relative to DAPL. Do you see other opportunities to leverage this asset with other projects being contemplated in Canada, and how does the 250 of open capacity kind of impact your conversations for recontracting on that pipeline from here?

This is Adam again. I'll start.

We still are believers in ML2, and we still think that project, as envisioned and as presented to the market, is ultimately going to win the day. I think what maybe we underappreciated was the regulatory complexity that's going on within Canada right now.

We're kind of looking towards the back half of the year to get some more clarity as those Canadian producers are in what feels like rather complex negotiations between them and the government, and we've got USMCA coming up. At the end of the day, DAPL is steel in the ground.

ML2 is a very executable project. As far as pivoting to what we're focused on on DAPL, we're in conversations with all the Bakken producers, and we're encouraged by how those are going.

We're really re-envisioning how the DAPL-ETCO system is going to be used going forward. Like I said, ultimately, we think ML2 comes back into that mix.

Don't forget that we previously announced the Southern Illinois Connector project, which moves 100,000 barrels a day of Canadian heavy for 15 years on the ETCO line. The work that we're doing to expand the ETCO line and to be able to facilitate that product movement allows us a lot more flexibility out of Patoka to the Gulf Coast to enable us to move PADD 2 volumes to PADD 3 volumes, and we expect to be able to optimize those flows and to capture incremental commercial opportunities through that Patoka South business.

Great. Thank you so much, and congrats, Mackie.

Thank you.

Congrats on a good quarter and the guidance raise. I quickly wanted to ask you about the Haynesville Shale.

There is a clear resurgence over there, some M&A activity also, but you also have some very strong Haynesville assets in the form of both Tiger and Gulf Run. Can you talk about ET's leverage to the resurgence in Haynesville Shale that we're seeing out there?

In the Haynesville. This is Mackie again.

Haynesville, as everybody knows, lives and dies on gas. Oil has nothing to do with it.

When we saw it peak at 17.5 or so Bcf a number of years ago and fall off to 14, that's why. It's coming back.

I think we and probably most of the industry are very bullish on gas prices as you look out three or four years and beyond. Ton of reserves in the Haynesville.

We're extremely well situated with all of our pipes. We actually have 4 42-inch pipes that run through northern Louisiana.

A lot of those cases we're selling some of that capacity at really good rates. It's a flexible system, we're actually move some gas from Perryville back into the marketplace and down Gulf Run to the south.

We're very well positioned with any kind of volume growth, and we think we're going to continue to see volume growth from the Haynesville for many years to come.

Thank you. My quick follow-up is more of a macro.

You remain very confident of the incremental nat gas demand. There's a little bit of a bearish thesis out there that gas turbines are taking longer to get delivered, permits are getting delayed, but from your initial comments, it appears that everything is absolutely intact, and the demand for nat gas for power remains incredibly strong.

Can you comment a little bit about that? Thank you.

This is Adam. We're just not seeing the slowdown.

Yes, we hear kind of the same things about permit delays and about some of these data centers getting delayed in building out. We alluded to it in our prepared remarks.

One of the trends that we're seeing and we think is really great for us and for the industry is that in areas that these data centers are being built, they're now expanding in those same areas. These are areas which are friendly, like Abilene, and with the Stargate 1 project and then the Stargate 2 project immediately adjacent in Shackelford County.

We expect more growth to happen in areas like that. You've seen the Meta announcement in Louisiana where they are increasing the capacity which they're building for their data center in an area that is obviously welcoming them.

We don't really see the slowdown. We do see some of the companies pivoting and looking more to where they're already building and they're already welcomed verse new greenfield sites.

This is Mackie. Let me add a little bit to that.

Thank

you. Let me add a little bit to that.

If you look at some of the projections, we're now seeing in LNG demand growing to early 2030s, 2031 to 36 Bcf. That's about 16 Bcf growth.

We know what's going on our systems with power plant growth as well as industrial growth. We're chasing markets like steel companies, two steel companies in two different states.

There's a lot of industry even in Oklahoma that we're chasing. It's not just demand for power plants, it's demand for LNG, it's demand for population growth in the South, it's demand for commercial business.

It's everything, and it's hard not to be bullish on natural gas growth over the next 10 or 15 years.

Thank you so much.

Hi, good morning. This is Andrew on for Julien, and thank you for taking the question.

Maybe just two on my front. One, with the data center interest that we're seeing, kind of in the Texas DFW corridor region, and also with the potential grid interconnection delays that we're also seeing, really as recent as last week with the legislative hearings, can you maybe kind of speak to the opportunity set that you guys are seeing in that region just given the connectivity that you have with Hugh Brinson?

Maybe more specifically, can you speak to kind of how are you seeing the competitive dynamic in that state? Kind of what differentiate you guys versus competitors, and do you expect that competitive dynamic could potentially deteriorate your return profile for these projects?

Thank you.

This is Mackie. Adam may add some.

We've said it before, years ago, a couple years ago, when data centers kind of started taking off, we looked at the maps, and then we looked at where a lot of the proposed data centers were going, and they were right on top of our pipelines. For one thing, we're just fortunate that we own so many big-inch pipes that traverse through much of the United States, especially the South.

We have a distinct advantage. For example, Abilene is really growing, and we think it'll grow into something very special from a market standpoint, but we just happen to have a 42-inch pipeline being built right by Abilene as all that kicked off.

Some of it we're just fortunate with assets are, but also we have great teams that are able to go in and negotiate a great deal for our partnership. We use a lot the unparalleled, unmatched capability of selling firm gas to these, because not only do we have big-inch pipe coming from multiple areas and multiple basins, even within Texas, but we also backed it up with storage.

We have 237 Bcf of storage in six states in the United States. Much of that is in the South.

We have enormous capabilities in very tough, volatile times to keep the gas flowing, which is critical to these data centers. Then as regard to any legislation, all that stuff, one thing that we've done, and I'm not aware of maybe corrected with Adam here, but if not all, the vast majority of the power plant data centers we do are behind the meters.

It really doesn't have anything to do with all this noise about if there's these 2,000 requests for interconnects on ERCOT, for example, in Texas, kind of irrelevant to our customers because they're not connecting to the grid. They're behind the meter.

They're going to provide their own electricity. They're not going to bother anybody or any of the customers, which is a lot of the noise that's out there.

Most, if not all of what we're chasing are behind the meter power plants for the data centers that were in gas to, and so that's really not going to be an issue for a lot of customers.

Gotcha. Exactly.

Thank you. Very clear.

I guess as a follow-up on your growth capex outlook, can you maybe kind of speak to the level of visibility that you guys have in potentially sustaining the current, let's say, mid to higher $5 billion of run rate growth capex, but at the same time maintaining that same internal return threshold that you guys have? I think in extension, from a natural gas perspective, can you maybe speak to kind of the geographic regions besides kind of the more obvious ones in Texas, Arizona, and Florida that you are seeing more constructive commercial discussions in?

Thank you.

Listen, I'll start off here, Andrew. It's a very, very good question.

As you can see from all of our conversations today, as well as all the other ones we've been having with you, we have a lot of opportunities here. It's a great place to be where we are right now, be able to see good, high-returning projects as we look out.

If you take not only the ones that we've announced and we're talking about, but also what we call the shadow projects that are sitting out there, they're just right on the cusp of getting to FID. I think you can see the 5.5, 5.6 to $5.9 billion that we have for this year.

If you looked at all the way through 2029, we have enough visibility that we expect that number to stay in that $5 billion, $5 billion plus all the way through 2029. I think you had a pretty broad question there.

I think as far as more on some of the geography, etc., and I'll look over toward Dylan a little bit here

to I think you're kind of touching on returns there. I think when we look at this opportunity set, we're not by any means lowering our return threshold.

In fact, I think when we look at these projects, our return threshold is probably going up because the opportunity set is just so great. These are excellent projects.

They're primarily demand driven, and we're building for customers to suit their needs. There's no forcing projects in.

It's just such a great opportunity set. There's no deterioration in the returns here.

I think, as Tom just said, we see this $5 billion $5 billion, $5 billion plus number going through the end of the decade here and at the same strong returns that we're seeing right now.

This is Adam. Maybe I'll just touch on the geographies that we're seeing these opportunities in, which really is all of them, but where our footprint is.

Specifically Texas, Oklahoma, Arkansas, Louisiana, Ohio, Illinois, as well as Florida. We're continuing to see opportunities on the natural gas side across all of these states.

Specific to data centers, there are certain states that are more friendly than others, and we certainly see more activity there. Like Mackie mentioned in one of his previous answers, a lot of this is reindustrialization, too, with factories onshoring here in the US.

We are seeing a lot of that. We're seeing a lot of expansions, and all those things need natural gas and need reliable, clean natural gas, and need the flexibility that our system can offer.

Gotcha. Very clear.

Thank you very much.

Thank you once again for all of you joining us today. As you can see, we've had a great quarter, great year, and a very, very bright outlook as we look out.

We really appreciate it. Thank you all, and we look forward to the follow-up questions you have.

Bye.