The Williams Companies, Inc. (NYSE:WMB) Q1 2024 Earnings Call Transcript

The Williams Companies, Inc. (NYSE:WMB) Q1 2024 Earnings Call Transcript May 7, 2024

The Williams Companies, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, and thank you for standing by. Welcome to The Williams First Quarter 2024 Earnings Conference Call. [Operator Instructions]. Please be advised that today’s conference is being recorded. I’d now like to hand the conference over to your first speaker today, Danilo Juvane, Vice President of Investor Relations, ESG and Investment Analysis. Please go ahead.

Danilo Juvane: Thanks, Andrea, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we released our earnings and press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, who will speak to this morning. Also joining us on the call are Micheal Dunn, our Chief Operating Officer; Lane Wilson, our General Counsel; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you’ll find a disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks, and you should review it. Also included in the presentation materials are non-GAAP measures that we reconcile with generally accepted accounting principles. And these reconciliation schedules appear at the back of the day’s presentation material. And with that, I’ll turn it over to Alan Armstrong.

Alan Armstrong: Okay. Well, thanks, Danilo, and thank you all for joining us today. Well, another first quarter and another strong start for Williams. So let me begin here on Slide 2 by calling out a few operational financial and strategic achievements we saw this first quarter. Starting here on the left of this slide, Yet again, we’ve set a record for contracted transmission capacity led by Transco, the largest and fastest-growing natural gas pipeline. And in January, we closed on our acquisition of a portfolio of Natural Gas Storage assets from an affiliate of Hartree partners for approximately $1.9 billion. The transaction included 6 underground natural gas storage facilities located in Louisiana and Mississippi, making us the largest owner of storage on the Gulf Coast.

Demand for natural gas has greatly outpaced natural gas storage capacity since 2010. And our thesis of this underinvestment is now being realized as this newly acquired storage is being re-contracted at rates above our acquisition expectations. In fact, storage rates have reached the point of supporting Brownfield expansions, and we are gauging interest from customers willing to underwrite potential expansion of these facilities in the form of long-term contracts. Also in the first quarter, we announced the expansion of the Southeast Supply Enhancement project to roughly 1.6 Bcf a day of capacity, and we prefiled this project with the FERC on February 1. We expect to make the official FERC filing later this year. And I’ll remind you that this project will serve both the Mid-Atlantic and the Southeast markets.

These markets are experiencing increasing gas demand from power generation and the reshoring of industrial loads. Since the time of our open season, the large utilities that we serve in this area have come back and provided dramatic increases to their generation needs based on data centers to be built in the region, as well as reshoring of industrial markets. So we believe that we are in the early innings for expansions in these Mid-Atlantic and Southeast markets. Our project execution teams also delivered an impressive list of accomplishments this quarter. In total, we have 20 high-return projects in execution across our business, including approximately 3.1 Bcf per day of expansion on Transco, which equates to a 15% increase in fully contracted long-term capacity that will be coming online over the next few years.

Within these Transco opportunities, a few noteworthy accomplishments to hit. First, we placed the Carolina Market Link in service and now began receiving the full revenues in this quarter. Next, we commenced construction for the Southside Reliability Enhancement and the Southeast Energy Connector projects, and we received the FERC order for the Alabama-Georgia Connector and the Texas to Louisiana Energy Pathway projects. And finally, we’re advancing a number of modest but high-return expansion projects on our MountainWest Transmission System. This is a period where we have a tremendous amount of large projects and sometimes it’s easy to overlook things as large as even the well deepwater project but happy to report to you that great execution by our teams there in some pretty difficult environments has that project coming in quite a bit below our original capital estimate on that project, and we do expect now this project to start up towards the end of this year.

So congratulations to our deepwater team that have been working on that project for about 4 years now, and pretty remarkable accomplishments to get that project in on budget and actually below budget. And then finally, our teams are well on their way to replacing 112 mainline compressor units with state-of-the-art low-emission turbines and electric drive units on Transco and Northwest Pipe. As a reminder, these projects will generate an incremental regulated return realized through a rate case or a traction mechanism that will begin in 2025. So again, a huge body of work there to go in and replace this compression that is well past its useful life, but the team is doing a great job. You can imagine the efforts that go into replacing that scale of operations.

But we have so much going on. It’s kind of easy to miss. So and we’re excited to see the earnings from that show up in ’25. So now turning to the highlights of our first quarter financial performance. We delivered quarterly EBITDA of $1.934 billion, which was 8% higher than last year, an impressive feat given the tough comp we were up against and the 25% year-over-year decline in natural gas prices and the lack of severe winter weather in most of our markets. An important takeaway from the quarter is that our outperformance occurred despite year-over-year lower earnings in the marketing and upstream segments, which reaffirms the strength and resilience of our underlying business, no matter the commodity price environment. To this end, we expect to deliver our EBITDA in the top half of our earlier guidance.

And to be clear, we think we can accomplish this with continued soft gas prices and without any further earnings contributions from our Marketing segment. Due to the ongoing steady growth and resilience of our business, we recently raised the 2024 dividend by 6.1% underscoring our confidence in our ability to continue this strong record of per share growth through even extreme low commodity price environments and with the slate of high-return growth projects under execution right now and in development. Williams remains well positioned to grow at this rate for many years to come. And with that, I’ll turn it over to John to walk through the quarter and year-to-date financials. John?

John Porter: All right. Thanks, Alan. Starting here on Slide 3 with a summary of our year-over-year financial performance. Beginning with adjusted EBITDA, we saw an 8% year-over-year increase despite natural gas prices that averaged less than $2 for the first quarter of 2024. Now included in that 8% overall growth is almost 13% growth from our primarily fee-based infrastructure businesses, excluding marketing and the upstream JV. As we’ll see on the next slide, our adjusted EBITDA growth was driven by strong growth from our core large-scale Natural Gas Transmission, Gathering and Processing and Storage businesses, including the expected favorable effects of our recent acquisitions. And it also included strong performance from our Sequent Marketing business, which had another strong start to the year despite falling a bit short of the extraordinary start they had to 2023.

Our adjusted EPS increased 5% for the quarter, continuing to grow off of the 19% ,5-year CAGR we’ve had for EPS for 2018 through 2023. And available funds from operations growth was just over 4%. Also, you see our dividend coverage based on AFFO was a very strong 2.6x on a dividend that grew 6.1% over the prior year. And our debt to adjusted EBITDA was 3.79x in line with our expectations for slightly higher leverage in 2024 before dropping back down in 2025 to guidance of 3.6x. So before we move to the next slide and dig a little deeper into our adjusted EBITDA growth for the quarter. We’ll provide a few updates to our financial guidance. Overall, based on our strong start to 2024, we are now guiding to the upper half of our 2024 adjusted EBITDA range of $6.95 billion to $7.1 billion and we are also well positioned for upside to drive towards the high end of this original guidance.

We also remain well positioned to deliver on our 2025 adjusted EBITDA range of $7.2 billion to $7.6 billion. Additionally, based on our improved adjusted EBITDA outlook and other changes, including interest expense and income assumption shifts, we now see our key per share metrics, adjusted EPS and AFFO per share coming in at the high end of their ranges for 2024, which in the case of AFFO per share would lead to a higher overall dividend coverage ratio as well. Now specifically for 2024, our transmission in Gulf of Mexico business is tracking a bit ahead of plan with a good first quarter and expectations of continued best-in-class execution on our many key high-returning organic projects, as well as immediate results from our Gulf Coast storage acquisition with strong performance expected going forward.

Our Northeast Gathering and Processing business was basically right on plan for first quarter with drilling in the higher-margin wet gas areas and inflation adjusters offsetting lower volumes in some dry gas areas. The West got off to a strong start in the first quarter, where DJ performance following our recent transactions along with all the hard work our teams did in preparing for winter allowed for excellent execution, especially across our Rocky’s assets. We see the West also tracking a bit ahead of plan, although we’re also embedding a bit more conservatism around Haynesville volume assumptions. For both the Northeast and West G&P assets, our guidance update today provides room for additional volume reductions and for upside movement toward the higher end of the range if those don’t occur.

For the Marketing business, we’ve had a strong overall start to 2024. But again, beating the midpoint of our full year 2024 guidance doesn’t rely on any additional help from Sequent at this point. And then finally, nice to see our upstream joint ventures off to a strong start versus our plan, again, supported by the preparation our team made for winter weather. So we expect our upstream joint ventures to perform well against their plan this year as well. So let’s turn to the next slide and take a little closer look at the first quarter results. Again, it was a strong start to the year with 8% growth over the prior year. Walking now from last year’s $1.795 billion to this year’s record $1.934 billion, we start with our Transmission in Gulf of Mexico business, which improved $111 million or 15% due to the combined effects of nearly a full quarter contribution from the Hartree Gulf Coast Storage acquisition, which is delivering as expected, following a flawless integration effort thus far.

Higher Transco revenues, including partial and service from the Regional Energy Access project, and also a full quarter contribution from the MountainWest Pipeline acquisition, which closed mid-February in 2023. The Segment growth was unfavorably impacted by last year’s Bayou Ethane divestiture and also some planned maintenance at Discovery. Our Northeast G&P business performed well with the $34 million or 7% increase driven by a $22 million increase in service revenues. This revenue increase was fueled by rate escalations that occurred after the first quarter of last year. Overall Northeast Gathering volumes performed roughly in line with our plan, down about 2% versus the prior year, with those decreases focused in the dry gas areas. Shifting now to the West, which increased $42 million or 15%, benefiting from a great start for the DJ transactions we completed in the fourth quarter of 2023.

Now the increase in the DJ Basin results was about the same magnitude as the unfavorable loss of hedge gains that we had in the first quarter of 2023. Additionally, last year, the West was significantly unfavorably impacted by the severe Wyoming weather and January processing economics at our Opal, Wyoming processing plant. As I mentioned a moment ago, much work was done by our teams to prepare for winter weather this year, and those preparations proved effective in getting us off to a great start for the West and also for our upstream operations in Wyoming. Overall, West gathering volumes performed roughly in line with our plan, up 5% on the benefits of our DJ transaction and better Wyoming volumes, which more than offset declines primarily in the Haynesville area.

And then you see the $41 million or 18% decrease in our Gas and NGL marketing business. As I mentioned a moment ago, it was another strong start to the year, but it did come up a bit short of the extraordinary 2023 start. Our upstream joint venture operations included in our Other segment were down about $9 million or 15% from last year. Our Wamsutter upstream EBITDA was actually up about $8 million with strong volume growth that was substantially offset by lower net realized prices. However, the Wamsutter increase was more than offset by lower Haynesville results from both lower net production volumes and net realized prices. So again, a strong start to 2024 with 8% growth in EBITDA, driven by core infrastructure business performance with continued strength from our marketing business.

And with that, I’ll turn it back to Alan.

Alan Armstrong: Okay. Thanks, John. And so just a few closing remarks before we turn it over to your questions. First of all, natural gas demand is not just growing now, it is accelerating. This period of low natural gas prices is reaffirming the great bargain that natural gas offers as a practical low-cost, clean energy solution and the power hungry world we live in is rapid turning to natural gas to generate this power. This compounded with the hard to miss growth in LNG exports and data centers as well as the continued drumbeat of electrify everything and resort it is accelerating demand and the expansions of our uniquely placed infrastructure will demand a premium. We have been betting on and setting our strategy around the benefits of natural gas for many years and have focused our investments in this space.

So if you want to invest in natural gas infrastructure, no one is more concentrated than Williams. We are the most natural gas-centric large-scale midstream company around today, and our natural gas-focused strategy will be relevant for decades to come, thanks to the accelerating natural gas demand we are seeing today. Our strong conviction of the strategy led us to the bolt-on acquisitions of strategic assets like MountainWest Pipeline, Hartree Storage and NorTex Storage. A couple of points on these acquisitions. First, these deals were quickly — sorry, these deals were directly in line with our strategy based on where we thought the puck was going. The synergies and commercial opportunities we expected are already being realized, thanks to clear plans and decisive actions.

And finally, I’ll reiterate our belief that Williams remains a compelling investment opportunity. Our conservative but distinct strategy continues to deliver steady, predictable growth and value to our shareholders and checks all the boxes that a long-term investor looks for in a durable and winning portfolio. We’ve now seen 11 consecutive years of adjusted EBITDA growth and an 8% CAGR of adjusted EBITDA since 2018 and I’ll remind you that, that is without issuing equity to drive this growth. In addition, we have recognized a 19.5% return on our invested capital during the same period, and our steadfast project execution has led to record contracted transmission capacity and will continue to drive growth in 2024 and beyond. On the predictability front, we have met or beat analyst estimates for 33 quarters in a row now and beat the estimate 2/3 of the time over this 8-year period.

And this year marks the 50th year in a row that The Williams Companies has paid a dividend. In closing, we’ve built a business that is delivering record profitability and strong financial returns in the present, but is positioned even better for the future. And with that, I’ll open it up for your questions.

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Q&A Session

Operator: [Operator Instructions]. Our first question comes from Spiro Dounis with Citi.

Spiro Dounis: First one, maybe to start with the guidance, two-part question there. So John, you’d mentioned leaving room for some volume reductions from here. Curious if you could provide a little more detail there and how to think about maybe the cadence as we go throughout ’24? And just given that you’ve left ’25 EBITDA unchanged. Sounds like maybe ’25 also contemplates some slower activity levels. So just curious to kind of get some confirmation around that?

John Porter: Yes, I’ll start and then Micheal can chime in as well. But yes, I think, overall, we are being cautious, obviously, with where natural gas prices are and especially during the shoulder months. So we started off with a plan that I think embedded a fair amount of cautious, I think, caution, and I think since then, we’ve taken a little bit more caution just given where things finished from the time that we were at Analyst Day, which was really mid-winter to where we finished the year. So hopefully, we will actually experience some upside relative to these assumptions, but we are going into the rest of the year with quite a bit of caution, especially around the dry gas areas.

Micheal Dunn: Yes. This is Micheal. I can add to that. Obviously, we talk to our producer customers quite often about their plans and they’re shifting, obviously, back and forth, depending on where prices are. We feel really comfortable where we’ve had predicted our results to occur in the second half of the year here with our guidance — confident. Based on the volume expectations that we have coming from the customers. And so just as a reminder, and I always say this, we have a lot of diversity across geography, customers and rich gas as well as dry gas. And obviously, that benefits us and having that diversity and so we’re still seeing some activity on the rich gas side, it’s benefiting not only our gathering but our processing business in the Northeast. And as I said, we feel confident about the volumes that we have embedded within our going-forward plans here in 2024.

Spiro Dounis: Great. Appreciate the color there. Second question, maybe going to data centers. Alan, your credit, you’ve been talking about data center demand for a few quarters now. It seems to be a bit more mainstream to say the least at this point. So curious to maybe get your updated thoughts on how you’re thinking about that data center demand going forward? And really what I’d love to know more about is when do you think we start to see tangible sort of commercial discussions start to take place and filter through?

Alan Armstrong: Yes. Great question, Spiro. And I do think that this is one that will grow over time. Each individual data center isn’t going to show up as a big pool and demand given the size and scale of most of these big transmission systems. So it is going to be the collective amount of data centers in these markets that’s going to show up. But there certainly is a lot of fury going on right now, I would say, both with our utility customers. And we certainly are working closely with them to make sure that we can serve their needs and the growth in their needs. I would tell you that it’s broader than even though data centers and AI gets all the hype, it’s actually broader than that in terms of a lot of reshoring of industrial loads that is occurring as well.

And part of that is because natural gas is so low cost here. If you think about the rest of the world and the energy cost expanding in the rest of the world and the U.S. sitting here on such a great resource of low-cost energy, it is reshoring industrial loads as well. And so I would say it’s a combination of those things that tends to center around low-cost power. So I would just say, first of all, this isn’t going to be a one-and-done kind of issue, it’s not going to happen maybe as quick as some people are expecting, but — because it does take a long-term planning to be able to serve the kind of ultimate loads that we’re talking to our customers about. But I do think it is going to be very sizable and very impactful. I just don’t think it’s going to happen quite as quick as a lot of people think it will, just because a lot of these areas, we are constrained on infrastructure.

And so it’s going to take some time and planning to be able to address that. But we are looking at it both with our customers, and we are also looking in terms of both direct serve as well, where all of the combinations of low-cost gas, land and communication capacity all come together. So I would tell you, we, as Williams, are working very hard. It’s a very high priority for us to make sure that we don’t let any of these opportunities slip by us, and we’ve got a great team assembled that’s working on that.

Operator: Our next question comes from Jeremy Tonet with JPMorgan.

Jeremy Tonet: Just want to dive a bit further into the natural gas market, if I could. It appears a bit oversupplied at this point in time. And just wondering any thoughts you could share, I guess, in how you see supply-demand balancing over the course of this year and into 2025 and I guess how that might impact Williams trajectory at that point?

Alan Armstrong: Yes. Great question, Jeremy. I firmly agree with the notion that the market is oversupplied right now. And it’s kind of a unique time because we’ve had the market in such strong contango here for quite some period. Putting a lot of value on our Storage. I would tell you we feel very fortunate to have bought the storage that we bought in the time frame that we bought and to pick up the contracts that Sequent had on storage as well. So a lot of in the money business around the storage business because of the strong contango. But that strong contango is also keeping rigs running that might not otherwise be running right now. And I think that’s adding to the oversupply situation. But we certainly are starting to see producers respond to that.

And we’re also starting to see the demand side respond to that as well. And I think we’ll see more of that this summer, and the market always finds a way to balance itself with low enough prices. But it’s definitely oversupplied right now. And I do think that once the demand materializes that we would expect in — starting in mid-’25, I do think that we’re going to start to see a big call on gas that will last for years to come. So it is going to be a period though of people having to be patient and waiting on the market. And it’s going to take some turn back, if you will, here in the short term, but I think people are appropriately looking to the future. And it is — the future is pretty clear and pretty transparent when we think about LNG demand, and we think about incremental demand from our customers on both power — traditional power generation is maybe as well as direct power generation as well.

So short term, we’re oversupplied. That’s causing a lot of contango in the market. But I think that contango is well-founded because there’s such a transparent and clear picture of demand for the future.

Jeremy Tonet: Got it. And then I just want to pivot over to LEG and I was wondering if you could provide any updates on project progress at this point given litigation other items in play? And any thoughts, I guess, on Basins in Southern Louisiana just given there seems to be a concern that, that could widen out without the infrastructure coming into service?

Micheal Dunn: Jeremy, this is Micheal. I’ll take that. I’ll start with a bit of a higher level in regard to pipeline crossings and generally, we have almost 26,000 pipeline crossings in the U.S. that have been built over the last several decades, just under 2,200 of those are with energy transfer. And for the most part, those are all being done by our operators in the field unless you have some design issues that you’ve got to get your engineers involved with. But for the most part, each of our companies work that out in the field until most recently. So we’ve been challenged in Louisiana and some other states by Energy Transfer and our ability to cross their pipeline. And I would say the tide is turning now on the legal issues.

We’re seeing the appellate ruling from the Louisiana court that overturned, the lower court ruling in the DTM case. We certainly think that’s going to be the same outcome that we’ll have on our cases, ultimately, it certainly is troubling that we’re having these difficulties with an industry peer. But ultimately, we’re going to get our pipeline project built out of the Haynesville, there’s definitely a need to move volumes to our gathering systems. To the demand centers in the Gulf Coast area and ultimately, we’ll get through the legal process. We’ll get through the FERC process, has now been initiated by Energy Transfer, certainly, this was a move that we expected Energy Transfer to do. And so it was anticipated, and that was established within our project schedule that I talked about at the Analyst Day.

So we still expect the second half 2025 in service date. And just in closing, we filed permitted and installed more FERC regulated pipelines in the U.S. than any operator, over the last decade. We fully know well when a project is when it comes to either being a designated gathering line or when it should be FERC regulated. And we’ve taken that certainly into consideration in the formulation in the design of the LEG project. And ultimately, we’ll get it built. And it’s unfortunate that we’re having these delays, but I’m very confident in our ability to finish this project as we’ve outlined in our most recent schedule. It’s going to be needed. The growth in the LNG demand in the Gulf Coast is going to happen. We’re certainly seeing the expectations of that occurring late this year and early 2025 when some of the new facilities are coming online.

And so we’re as I said, very confident about the project and looking forward to getting the legal issues behind us and getting on with construction.

Operator: Our next question comes from Manav Gupta with UBS.

Manav Gupta: Congratulations on a very strong quarter. I only have one question. When we look at your 2025 guidance here, can you help us elaborate the growth CapEx, like key projects that you’ll be looking to spend the money in 2025 to grow your EBITDA from ’25 ahead? But can you help us identify some of those key projects that the good spending will be done on?

John Porter: Yes, absolutely. So when we look at 2025, we’ve got really quite a bit of spend expected on the Louisiana Energy Gateway project that Micheal just referred to. So that would be in the category of gathering and processing expansions. And by far, the biggest in the gathering and processing area would be the Louisiana Energy Gateway pipeline project. We do have some new Energy Ventures investments that we’re expecting to begin to spend some money on, including our first Carbon Capture and Sequestration project, which is at the terminus of the Louisiana Energy Gateway project. So it’s related to that LEG project. But we also have some solar projects that we’ll be investing in. We will have some of our contributions to our upstream JVs, those are typically smaller amounts of capital.

But then finally, you can see the long list of transmission projects that we have on Transco and MountainWest that are still in execution. Obviously, we’re wrapping up regional energy access this year, but you’ll see many, many that will continue to have a spend going into 2025 as those reach their in-service dates in 2025. So that would be the main pieces of the growth capital for 2025.

Alan Armstrong: And Gupta, I would just add in terms of drivers for growth in ’25. We have a number of large deepwater projects that we’ve already spent a majority of the capital, those will be coming on towards the end of this year and into next year. So we’re really excited about the big step-up in deepwater growth and how well we’re positioned out there for what we think is going to be a lot of continued growth in that area. So — but in terms of drivers for growth, that’s one additionally, drivers for growth would be the rate case on Transco. And so the benefit of all the money we’re spending right now on the emission reduction projects will show up. The benefits of that will show up when we start charging our new rates in March of ’25. So those are some of the other drivers for growth.

John Porter: Yes, I didn’t do a great job of connecting that to growth. So thanks, Alan. Just specifically, we have 6 Transco growth projects that are in service between the second half of ’24 and 2025, and 5 major Gulf of Mexico projects, that are in service as well as well as that Transco rate case that Alan mentioned. And — but in many cases, those are projects where we’ve already spent the capital. Or in some of the cases of some of the deepwater projects, there were no capital requirements at all.

Operator: Our next question comes from Praneeth Satish with Wells Fargo.

Praneeth Satish: Maybe let me start with a data center question here. So most of the expansions on Transco over the last few years have taking place in the Northeast. But if we start to see large AI data center build-out or even some of the reshoring that you talked about in other regions along Transco’s path like the Southeast and that the bottleneck for more capacity shifts south on Transco. Just trying to think about how that impacts things. Is there more opportunity for maybe higher return compression expansions on the southeastern part of Transco or just more available capacity there? Or do you think expansions anywhere along Transco are kind of uniform in terms of return?

Alan Armstrong: Yes. Good question. Yes, the first evidence of that, even though it really was before the data center load became quite so evident, is our Southeast supply enhancement project. We’ve announced that and now filed it in the first quarter for 1.6 Bcf a day, and that does serve both the Mid-Atlantic and the Southeast markets. Since that time, as I mentioned, those utilities have come out and said that they were missing their growth targets by many multiples. In fact, I think Southern companies came out and said they missed their original growth for power generation by 17 times. So lots going on in those markets. In terms of our abilities to serve those, we’re extremely well positioned to serve that. Again, Southeast Supply Enhancement project is the first initial example of that, and that will serve projects along Transco to the Mid-Atlantic and Southeast, starting at Station-165, and we’ll take advantage of supplies coming in from the Mountain Valley Pipeline at 165.

In terms of the future, continued ability to expand along system and ability to restore pipeline pressures on systems that have been derated over time due to population encroachment in the areas. So lots of ways for us to expand along that existing capacity. And believe me, there is a lot of work going on right now with our teams and with our customers in those areas, figuring out the very best solutions to serve their growth needs in that area. And there’s a lot going on in that front that we’re not in a position to talk about yet. But a lot of — a lot of expansion in that corridor. And again, Transco is extremely well positioned to serve that with the expansions of our existing systems.

Praneeth Satish: Got it. That’s helpful. And then I just had a couple of questions here on the Washington Storage Transition to market-based on Transco. Can you just help frame maybe how much of an uplift you expect for moving that from — to market base from, I guess, cost of service? How much difference in rates could you see there? And then how much of that capacity do you need to go through an open season now? And how much of that capacity do you think third parties could take versus Sequent? And then finally, is this shift to market-based rates and the upside is that reflected in 2025 EBITDA guidance at all?

Alan Armstrong: Mike, do you want to take that?

Micheal Dunn: Yes, I’ll take that. So yes, to answer your last question first, that is embedded in our guidance for 2025. So the process where it stands now. FERC has approved our settlement with the customers, the customers have a choice to take a tranche of capacity on a term that they so desired. So they’re making that decision now between now and the end of May. So ultimately, they’ll decide upon how long of a term they want and there’s already a pre-determined rate for that was embedded within the settlement. And so once they make that decision, that will be effective as of April of 2025. So that’s when those rates will go into effect. So we definitely embedded what our expectations are with where we think the customers will end up in regard to their choices of selection.

Ultimately, we think that we fully subscribed by existing customers. It’s a really good project for them. It’s a great project for us. The storage is in high demand. We don’t expect anybody to turn back any of that capacity at this time.

Operator: Our next question comes from Gabriel Moreen with Mizuho.

Gabriel Moreen: A quick one on your Gulf projects. I think there’s been some talk about there about Shenandoah being delayed, maybe half a year plus or minus. Can you talk about whether you’re potentially seeing that? Or whether that would impact project economics or would just demand fees kick in regardless?

Alan Armstrong: Yes, Gabe, I would just say our part of that project is on schedule. We’re not really at liberty to get into details of the contracting details in that. But remain confident in what we have in the forecast for that project. So anyway, we’re not going to speak for the producer. Our part of that project and our work there is on time and team’s doing a great job of executing on that, and we’ll be ready to serve when we were supposed to be ready to serve on that project.

Gabriel Moreen: Understood. And then maybe if I can just talk LNG a little bit. There’s a stake in the facility LNG export facility under construction that I know you’ve looked at pretty hard over the course of time. Are you interested in potentially looking at that stake? And just how it may or may not fit into a broader LNG strategy that you may be pursuing over time?

John Porter: Gabe, are you referring to Port Arthur?

Gabriel Moreen: I am.

Unidentified Company Representative: Chad, do you want to take that?

Chad Zamarin: Yes. I think in general, we’re focused on high-return projects that we operate — we build and operate. And so we continue to look at how we can connect our customers to the most attractive markets. LNG markets are obviously an important destination for U.S. natural gas. And so we’re going to continue to look for ways to connect our customers and our value chain to those international markets. But we’ve typically not been looking for non-operated positions in infrastructure projects. We’ve got so many opportunities to invest in our kind of organic projects, that’s been our primary focus. But again, if we find opportunities that come with our ability to connect our customers to better markets, we’ll look at them, but that’s certainly not the primary focus of our LNG strategy.

Operator: Our next question comes from Neel Mitra with Bank of America.

Indraneel Mitra: I wanted to follow up on the [indiscernible] expansion in your conversations with your big three utility customers there. You had an interesting slide at the Analyst Day where you talked about those utilities having quotes about not recurring enough natural gas and kind of underestimating power. When they made those quotes in your conversations, did that reflect the AI team. So do you think that the project that you’ve contracted so far has some AI components in it? Or is it just general electrification so far that’s being reflected in that demand?

Alan Armstrong: Yes. To answer your question, our work on that in terms of developing that project, obviously, was even further ahead of when we announced that. And so you kind of have to remember that as you think about the timing of that. And to answer your question very simply, the degree — the kind of incremental demand that we’re talking about is not reflected in the [indiscernible] project. There might have been some expectation for that. But in terms of the large incremental growth impacts that customers are now starting to reflect in their integrated resource plans. Those are somewhat, I wouldn’t say perfectly incremental, but certainly, a big chunk of that is incremental to the load that we’re serving on [indiscernible].

Indraneel Mitra: Okay. And then I wanted to follow up on some of your producer activity. I know one or more of your customers are delaying sales til gas prices get better. Do you have any updates on that? And then how do you factor that into ’25 guidance if you just have a lower base going into ’25 if those don’t get turned in line?

Alan Armstrong: Yes. Well, first of all, there’s a lot of productive capability in these fields. And the ability to ramp that up and respond to the market. And I think the producers are managing their business in a way that they will be ready to respond to respond to it, as I mentioned in my comments earlier around gas supply demand balance, that’s certainly what we’re seeing is producers being willing and able to commit to what they need to on their end to be ready to respond to that. So I think there certainly will be some upside to our business in ’25 as the market and supply start to respond to that. But it is typically a very long lag period and very difficult for the market to be able to respond quickly. I do think, however, this time, and I hate to be the guy calling it’s different this time.

But because there is such strong contango in the market right now, we are seeing a different response and a different positioning from our producers than we typically see in this situation. And again, I think that’s because there’s such confidence in both the fundamentals and the visibility to the forward market that’s suggesting that that’s how they should behave at this point.

Operator: Our next question comes from Theresa Chen with Barclays.

Theresa Chen: Alan, I’d like to go back and touch on the comments of strong contango benefiting your storage assets. Can you give us a sense of what you’re seeing in changes in storage rates as contracts come up for renewal? And is this largely due to the current contango? And as we come out of the contango, do you think these economics are durable?

Alan Armstrong: Yes. Good question, Theresa. I’ll give you my comments, and I’m going to ask Chad to give you a little more detail on that. But I think over time, we have seen the value of storage, and we’ve certainly seen it with our own Sequent operations. We’ve seen the value of storage in these volatile markets and markets that are having to respond very quickly to shifts in demand continuing. I think it’s also pretty visible to see that both with an increase in renewable power on the market as well as more and more LNG as that comes on LNG is going to need to be a little more responsive. It’s not going to run at 100% load factor when the LNG is more — is closer to meeting the more mature demand from that market. So I think those are a lot of the drivers for the increase in storage capacity.

As Micheal mentioned earlier, we certainly have seen a pretty strong response from our customers and making sure that they don’t lose the benefits of the Washington storage facility and the flexibility of their business. And I think as the market turns to more and more hourly type service, and pipelines tighten up on the flexible services and no noted services that they previously offered. I think that’s going to continue to put more and more pressure and more need for the storage business. And I think that’s becoming pretty evident to the gas marketing business. In terms of contango driving the value, it’s certainly one of the elements of value that is driving that. But I think it’s a little broader than just the contango in terms of what’s driving the pretty rapid increase in storage rates.

And I’ll let Chad talk a little more specifically about what we’re seeing in rates.

Chad Zamarin: Yes. I think it’s a really important theme to keep an eye on what both the ability to set up our infrastructure to benefit from volatility and price that supports extraction value. But also importantly, we’re seeing the transition. We’ve been talking about it for a while, increased volatility in power markets, Alan talked about the power demand that we’re seeing — I mean we talk often — I mean, PJM numbers themselves say that by 2040, peak demand will more than double. That’s a significant — from a set of infrastructure that’s already full. And so assets like storage will not only be driven from a value perspective by dislocations in price over time, like the contango we’re seeing in the current market, but we are seeing an evolution and a recognition that you’re going to need those assets for reliability.

Power — produced power companies will need storage LNG companies. We’re seeing much more variable demand coming in the future. And so not only will we be set up for storage to have value in the near term when there are price dislocations like we’re seeing with the contango in the market, but we’re also seeing an evolution of the market to recognize that storage value will increase even when there may not be apparent price dislocation, there will be a need for reliability in backup, both in supply and the ability to put gas into storage when upset conditions occur. So we’re set up really well to benefit from both the value dislocations you see in the current market and the long-term fundamentals around the need for storage for reliability. So all that to be said, I don’t think that the contango in the market is the only necessary driver for long-term storage value.

We see long-term storage value both in markets where there are dislocations from a price perspective but also because of the long-term need for reliability and the important role that storage plays in providing reliability.

Operator: Our next question comes from Tristan Richardson with Scotiabank.

Tristan Richardson: Alan, just maybe switching back to the thematic for a moment. At the Analyst Day, you and some of your guest speakers talked a lot about sort of that general need for permitting reform and how critical gas supply is to power sort of this increased demand we’re seeing in electricity. How critical is sort of permitting or form or at least a more amenable regulatory environment for energy supply to kind of meet this accelerating demand growth you guys have talked about today and the slide you talked about with sort of the 3x demand you’re seeing over the next decade?

Alan Armstrong: Yes. I would just say as the world turns off of coal, as the reliable baseload and is shifting more and more and more to natural gas as the base load, as Chad mentioned, that reliability issue is going to be really key and us continuing to stretch and deny the amount of capacity we really need in these markets, is going to become a louder and louder drumbeat. You’re hearing it from the ISOs already. You’re hearing it from — starting to even hear from the utility commissions about how important it is that they have access to natural gas. You’re even starting to hear it in places like Connecticut that are upset that they don’t have low-priced gas into those markets because Governor Cuomo stopped a number of projects coming across the state.

So it’s unfortunate. It’s kind of like sometimes it’s a terrible situation as we think about long-term infrastructure and politics, but the two don’t meet very well together, unfortunately. And sometimes the bridge has to fail to people to realize that we have to spend money on maintaining and keeping our bridges safe. And I would say similar situation on gas infrastructure. We are heavily under-invested in gas infrastructure right now in terms of keeping up with this growing need. The good news is, I think the screen is going to get pretty loud and it’s not just going to be from the gas industry when the tech industry is really struggling to get adequate supplies for data centers and power, I think that both the utilities are going to get loud on this.

I think the tech companies are going to get loud on this. And hopefully, it doesn’t come to a catastrophe in some of the markets, but it’s amazing to me how quickly people forget how close we got last — this last winter, how close we got to losing parts of the Northwest markets due to a couple of very small failures on some of our competitors’ pipeline serving into us that caused a shortage as well as distorted at one of the big storage facilities up there. So we’ve been able to manage. We’ve been able to keep the gas service on, but we really haven’t experienced a situation in these big heavily populated areas where we’ve lost gas service because people, I think, tend to think just like losing your power and it just clickers off and comes back on.

That’s not the way gas service works. And it will be a pretty catastrophic event. So thank you for asking the question because we certainly try to make it clear that we’ve got to invest adequately in our infrastructure, and it is going to take permitting reform to do that. I would say we’re hopeful that we’re getting more and more the moderate left engaged on this issue and understanding how important this is for their constituents as well. So I do think we’re making progress on it, but it is a very large issue if we hope to keep up with demand. We’re going to have to get better at building out infrastructure here in the U.S.

Tristan Richardson: Appreciate it. And then maybe, John, just a smaller one. You appreciate kind of laying out sort of some of the puts and takes in the [indiscernible] segment year-over-year. But is there a number we can think of as what was the organic growth in the quarter? Just thinking about Hartree contributions as well as sort of a partial anniversary of MountainWest?

John Porter: Yes. I think we think the acquisitions as it relates to Hartree and MountainWest Pipeline have tracked very well to the announcements we made in terms of the valuation and the multiples that were involved there. So I think you can — you can rely pretty much in terms of sizing those impacts as to the announcements we made at the time of the acquisition. Obviously, with MountainWest Pipeline that closed on Valentine’s Day in 2023. So that kind of allows you to size the relative size of the uplift in ’24 versus ’23 for MountainWest Pipeline. With Hartree, it closed very early in the year. So we pretty much had a full quarter of Hartree. So I think that I would just say size those two pieces. It was a strong quarter for Transco.

No doubt, they did have the nice uplift from partial and service of Regional Energy Access, but they had some good seasonal revenues as well. And we did mention a couple of things that work the other way though, the Bayou Ethane divestiture that we had last year, and I think we put some information out about that — the size of that divestiture as well. And then we did have some planned downtime at Discovery, which was an impact as well.

Operator: Our next question comes from John Mackay with Goldman Sachs.

John Mackay: Maybe to keep it in the gas demand policy front. You guys have also talked a lot about coal plant retirements on your footprint, you kind of framed up maybe an upside number at the Analyst Day earlier this year. Just be curious, any thoughts you can share on the recent EPA updates around power plant carbon emissions? And how that’s playing into your forward view?

Micheal Dunn: John, this is Micheal. Yes, obviously, we’re watching that closely and the fact that these new gas-fired power plants have to have some kind of sequestration on them in the — in the midterm, I would say, is certainly taken into consideration by the utilities that are building these plants. I think ultimately, we’ll probably be tempering of that. That’s my opinion that whenever you see the EPA power plan come out with a new rule, it’s certainly subject to litigation as they happened several times now, and I suspect this one will be no different. But that will be a challenge, I think, for the industry to respond to a lot of that sequestration requirement in regard to these combined cycle power plants. I mean it’s technology that is available but it is going to be expensive.

It’s going to be expensive for the end user and the consumers. And I certainly think utilities will take that into consideration in their plans. But we’ll definitely see some coal plant retirements accelerating. And I think the rub there is, will they be able to meet demand with the acceleration of coal plant retirements with the AI boom that we’re seeing. And I think that’s going to be a big base in the boardrooms for the utilities to come.

Alan Armstrong: Yes. And I would just add to that, the issue around sequestration, if you think about how difficult it’s been to build sequestration pipelines in South Dakota and Iowa, in serving those markets. And if you think that we’re going to be able to take sequestration to a new level in areas where there isn’t good underground resources for sequestration along the East Coast. And pipe that through heavily populated areas. I just think that is very unrealistic perspective right now. And so I think this is a place again where politics and the popular notion of politics and good old-fashioned hard physics are not matching up. And to have the Sierra Club fighting a CO2 pipeline in Iowa that’s going to sequester carbon, is really, I think, a forewarning about the practical nature of being able to sequester large volumes of CO2 in these heavily populated areas.

John Mackay: I appreciate all that. Maybe just zooming back in on you guys specifically quickly. Appreciate the frame up of the gas storage opportunity. At the very beginning, you mentioned the rates have come into making brownfield economics work. I guess I’d just be curious like, how much do you think you guys can add on a Bcf basis across your existing footprint from a Brownfield perspective?

Alan Armstrong: Well, I mean, the fact is we have the right away through those areas. And so there’s a very large number, but it’s not as simple — it’s not a finite number by any stretch of imagination and it has its economic limits. And so said another way, it may not have its physical limits because we have the right of way through there, but it certainly has its economic limits. And so obviously, the easiest thing to do is to add compression in the area. And then next is replacing lines that are — that we’ve had to derate over time.

Unidentified Company Representative: I think it’s about storage.

Alan Armstrong: Sorry, on storage. Sorry, I thought we were back on Transco sorry about that. I’ll let Chad take that forward.

Chad Zamarin: Yes, sorry. Just on storage. We do have quite a bit of capacity at the salt-cavern facilities that we acquired in the Gulf Coast. And so — and those expansions that we’re looking at would likely come in kind of 10 Bcf tranches at each facility. And there is a lot of capacity to expand. I think we’re going to be thoughtful about how to do that incrementally as the market kind of recognizes the need. And we’re seeing that evolution, but we need to see storage contracts shift from short term to long term for us to support that kind of infrastructure expansion. But it would look like kind of 10 Bcf cavern expansions at those salt-cavern facilities.

Operator: Our next question comes from Sunil Sibal with Seaport Global.

Sunil Sibal: So I wanted to start off — a little bit big picture question. So it seems like you’re executing pretty well on the guidance, the ’24 and ’25. So I was curious if your actual performance comes out to be above the top end of your guidance ranges? What’s the best incremental use of the cash flows in the current environment, especially if this permitting constraints continue?

Alan Armstrong: Yes. Well, that is a great question and one that gets a lot of debate both and this team and within the boardroom as well. And it’s a very astute question because if you look at the math, that starts to build on us pretty quickly, we saw the outlook — positive outlook change coming from S&P on our Credit Rating. And so that we think will meet the conditions for that here through the balance of the year. So only so much more value, I would argue to be added in that regard. But I would say, certainly, our dividend policy is one lever, share buybacks, another and acquisitions of bolt-on transactions that have continued to add a lot of value and ones that we’re really excited about the way our teams have performed on taking these assets and extremely quickly extracting the synergies that we expect out of them.

And so we have been very purposeful about building the capabilities within the organization to be able to act quickly and decisively on those kind of bolt-on transactions. And so we’ll keep our eyes on that. Certainly, we’ve seen — so far, we’ve seen a lot of value that we can add by being the operator on those kind of assets to make them immediately accretive transactions. And so we’ll sort of keep our eyes open for those kind of bolt-on, very tightly aligned with strategy acquisitions as well.

Sunil Sibal: And then in the Northeast, it seems like MVPs really start up pretty soon. And I was kind of curious in the current gas price environment, how do you think that impacts the producer reactions and then what kind of operating leverage you have in your systems to kind of benefit from that in the near term?

Alan Armstrong: Yes, great question. I think right now, as we sit here today. The power gen loads will be pretty strong this summer if the weather predictions that are out there are accurate right now. I think we’ll see some pretty strong pools and that pipe and those gas supplies serve that will be capable of responding to that. And that’s probably the extent of what we would see here in the immediate term for that, as our expansions that we’re working on like the Southeast supply and expansion, system come on in the years ahead, that will start to take full advantage of those incremental supplies. And we’ll see areas where we gather the volumes upstream on that benefit from that. But importantly, our ability to expand Transco is a lot lower cost and a lot higher margin for us if we have supply coming in there at 165.

And so that’s a huge positive for us to have high-pressure supplies coming into our system right there at 165. And so we’ll see. I’m fairly confident we’ll see some fairly significant additional expansions from 165 and take advantage of that on the Transco system.

Operator: This concludes the question-and-answer session. I would now like to turn it back to Alan Armstrong for closing remarks.

Alan Armstrong: Okay. Well, thank you all very much. We’re very excited to deliver another record at the company and not just for the quarter that it produced in terms of the present a lot of people are talking about what they’re going to do in the future. We continue to deliver in the present. But we also have a very strong future ahead of us and are extremely well positioned for not just the next couple of years, but for the next decades, as we were contracting for these major expansions on our system. So very excited to see a strategy that we’ve stuck with for years now really coming home and all the benefits that we thought natural gas had to offer the market start to be realized by others and putting a lot of demand on our infrastructure.

So very excited to see this turn here in the quarter and very thankful for all the extraordinary efforts of the employees and the leadership of this company and the management team that I get to work with for continuing to deliver such great results. So thanks for joining us today.

Operator: Thank you for your participation in today’s conference. This concludes the program. You may now disconnect.