Williams Cos Inc (WMB) — Q3 2024 Earnings Call Transcript

Thank you, and good morning, everyone. Thank you for joining us and for your interest in the Williams Companies. This morning, we released our earnings, press release and the presentation that our President and CEO, Alan Armstrong will kick-off in a moment. Also joining us on the call are John Porter, our Chief Financial Officer; Micheal Dunn, our Chief Operating Officer; and Chad Zamarin, our Executive Vice President of Corporate Strategic Development. In our presentation materials, you'll find the disclaimer related to forward-looking statements. This disclaimer is important and integral to our remarks and you should review it. Also included in our presentation materials are non-GAAP measures that we reconcile to generally accepted accounting principles. And these reconciliation schedules appear at the back of today's presentation materials. So with that, I'll turn it over to Alan Armstrong.

Great. Well, thank you, Danilo, and thank you all for joining us today. A lot of positive updates to walk through with you this morning as we delivered another record quarter of adjusted EBITDA, driven primarily by our natural gas transportation expansions and Gulf Coast Storage acquisition. In fact, our better-than-planned execution on growth projects and higher-than-expected performance on acquisitions along with core business strength gives us the confidence to once again raise our guidance midpoint for 2024, which John will detail in his remarks. The returns of our projects and acquisitions have been strong enough to overcome what has been a very challenging natural gas price environment and a fairly impactful hurricane season, so I am very pleased to see the way our entire portfolio responded in this environment. In fact, a recent Wells Fargo note on mid-stream return supports our view that Williams has delivered one of the best cash returns on invested capital in the sector, generating a 22.9% return for the 2018 through '23 period, nearly double the sector median of 11.9%. Now looking at Slide 2, I'll start by noting that the strong cash returns expected within the suite of our recently completed projects, will lead to a visible five-year EBITDA CAGR of over 7% at the midpoint of our 2025 guidance, all without equity issuance and while improving our credit metrics during this period. Additionally, this pace of growth has been right into the headwinds of low gas prices and production curtailments this year. The drivers of growth for next year are clear and fully contracted. These include the following projects where the CapEx and construction risk are behind us. And in fact, in August, we placed Transco's Regional Energy Access into full service ahead of schedule and under budget, ensuring clean and reliable natural gas is available to serve the Northeast region for the upcoming winter heating season. We were also successful in placing a portion of the Southside reliability enhancement project in service as well as completing our MountainWest Uinta Basin expansion. And in the deepwater, we've completed all of our construction for the very large well project and we are excited to see Shell begin ramping up production in December. And as we mentioned on our last call, there are now two new fields on our Discovery system that started up in the third quarter. Chevron's large anchor development and Beacon's Winterfell 5-well program are all fully connected and will help drive a large increase in EBITDA in 2025 as these programs also begin to ramp up. Beyond these drivers for '25, we already have a total of 5.3 Bcf a day of contracted gas pipeline projects that will drive a high rate of growth for the next five years. These include the following: First, on Southeast Supply Enhancement Project or SESE. We filed the FERC application for its 1.6 Bcf a day expansion of existing Transco capacity in Virginia, North Carolina, South Carolina, Georgia and Alabama. SESE is fully contracted and will provide a record EBITDA contribution from a Williams transmission project that demonstrates how valuable contracted capacity is going to continue to be in the next wave of demand growth that we are just now starting to see the benefits of. And as we mentioned before, this singular project will generate EBITDA greater than our entire Northwest pipeline system. And in fact, by itself, SESE would be the equivalent to the tenth largest long haul pipeline in our nation on its expected EBITDA contribution alone. This project is a good representation of some of the amazing growth opportunities that will continue to drive growth well into the future. Utilities across the Mid-Atlantic and Southeast markets have come out saying they missed their growth targets for power generation and we are extremely well positioned to serve these customers with projects like SESE, starting at Station 165 and delivering volumes south as they take advantage of the new supplies coming in from Mountain Valley Pipeline. Moving down the list, we received our FERC order certificate from the MountainWest Overthrust Westbound expansion, and that is a project that will add approximately 325,000 dekatherms of fully contracted firm transportation service on this MountainWest system by the fourth quarter of '25, and we began construction on several key projects, including our Louisiana Energy Gateway Gathering System, where we were pleased to receive the FERC order in late September that confirmed this system is exempt from FERC's jurisdiction, so we are full steam ahead with an expected in-service date in the second half of next year. Construction is also well underway on Transco's Commonwealth Energy Connector project in Virginia and I'm pleased to announce that we've entered into binding agreements with three new expansion projects on the Northwest pipeline, recently totaling roughly 260 million cubic feet a day of firm capacity. These are small projects, but individually very strong in terms of the collective returns that these projects will generate. So really nice to see the very strong signs of growth showing up now in the intermountain region on both Northwest and on our MountainWest acquisition. For some time now, we've talked about just how attractive the current macro environment is in supporting the long-term growth in our businesses as the line of sight to LNG exports, coal to gas switching, industrial reshoring and data center demand becomes clearer and clearer. The recently signed precedent agreements for an expansion of the existing Dalton Lateral that will serve Northern Georgia is a great example of this. Just like SESE, this is another project that leverages off of our existing system to provide high returns and demonstrates the path we are on to deliver many more fully contracted transmission projects that will provide attractive earnings growth beyond the end of this decade. And finally, we recently signed commercial agreements with Lakeland Electric, a Florida-based utility, who we will partner with in the development of a 75 megawatt solar farm. The project, which will be designed and built by Williams, is cited on land that's been owned by Williams for decades and was unsuited for traditional real estate development but is an ideal site for solar and energy production in an area that has got a tremendous amount of demand growth. Our list of prospects beyond these newly contracted deals continues to grow fast and the environment for demand-driven projects is much better than the environment that has driven the 22.9% cash return on invested capital and the over 7% CAGR of growth across our business. So we really want to stress that while we've had a great run here in the last five years of growth, the environment that is in front of us right now and the kind of opportunities we're seeing is much stronger than what we've seen in the period that's generated these kinds of opportunities. So we are really excited to be able to deliver up against the demand that is growing very rapidly in the space we're in right now. And with that, I'm going to turn it over to John to walk through the third-quarter financials. John?

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 about a 3% year-over-year increase where once again, for the third quarter, in spite of low natural gas prices, our resilient business continued to grow even as producer customers continued significant temporary production reduction measures. And we also saw a greater hurricane impact for the third quarter of 2024 versus 2023. As we see on the next slide, our adjusted EBITDA growth was driven by strong growth from our large scale natural gas transmission and storage businesses, including the favorable effects of our recent acquisitions, but also unfavorably impacted by asset sales. And of course, we don't include gains from asset sales in our adjusted performance metrics, adjusted EPS, adjusted EBITDA or available funds from operations, and we did have a $127 million gain in the third quarter of 2025 from the sale of our Aux Sable interest and about $130 million of gains last year on the sale of the Bayou ethane system. Year-to-date, our adjusted EBITDA is now up about 5%. And year-over-year, you see that adjusted EPS growth is lagging our adjusted EBITDA and AFFO growth and that delta is due primarily to a step-up in non-cash depreciation expense from our recent acquisitions. But again, looking to 2025, we would see the delta in growth rates close back up as the non-cash depreciation charge flattens back out. For the third quarter, available funds from operations (AFFO) growth was about 4.5% and 4% year-to-date. But looking through 2025, we see a five-year CAGR of 7%. Also, you see our 3Q dividend coverage based on AFFO was a very strong 2.22x on a dividend that grew just over 6% over the prior year and 2.33x coverage year-to-date. And our debt to adjusted EBITDA was 3.75x in line with our expectations for 2024 before dropping back down in 2025 to guidance of 3.6x or better. So before we move to the next slide and dig a little deeper into our adjusted EBITDA growth for the quarter, we'll provide an update to our financial guidance. We are pleased to increase the midpoint of our adjusted EBITDA by $125 million from the original guidance of $6.95 billion to now $7.075 billion, reflecting a new range of $7 billion to $7.15 billion. Additionally, as we mentioned before in our prior calls this year, based on our improved 2024 adjusted EBITDA outlook and other changes, we see our key per share metrics, adjusted EPS, and AFFO per share coming in at the high end of their ranges for 2024. So we've now shifted the 2024 guidance for those metrics to a midpoint of $1.88 and $4.35, respectively, and we see improvement in the leverage guidance from 3.85x to 3.8x. Finally, we are reaffirming our 2025 financial guidance as originally issued, but we plan to provide an update when we release our full year 2024 results in February. So again, very pleased with the financial performance of the company for 2024 and our ability to raise guidance even though it looks like 2024 Henry Hub natural gas prices will likely be around 15% lower than the January 1 strip prices that we set our business plan on this year. So let's turn to the next slide and take a closer look at those third-quarter results. Walking now from last year's $1.652 billion to this year's $1.7 billion, we start with our transmission in Gulf of Mexico businesses, which improved $76 million or just over 10% due to the combined effects of a full-quarter contribution from the Hartree, Gulf Coast Storage acquisition, which is delivering as expected, following a flawless integration effort, higher Transco revenues, including from the Regional Energy Access project. Now in the Gulf of Mexico, we saw total hurricane-related impacts of about $10 million unfavorable there, and segment growth was also unfavorably impacted about $9 million by last year's Bayou ethane divestiture. The Northeast G&P business was flat versus last year and also basically flat in total against our original 2024 plan. We've seen volumetric underperformance in the dry gas systems, with some offset from rate escalations on those same systems, and we've seen growth in our rich gas systems, which has also provided a strong favorable offset. The 3Q Northeast results also reflected the sale of our interest in Aux Sable on August 1, 2024. Shifting now to the West, which increased $15 million, benefiting from the DJ transactions that we completed in the fourth quarter of 2023. Segment performance was also favorably impacted by higher NGL services results, including higher Overland Pass pipeline volumes where low natural gas prices have supported greater ethane recoveries. Overall, West gathering volumes were lower as a result of those temporary producer reductions primarily in the dry gas Haynesville area. And then you see the $12 million lower marketing results and those were in line with our business plan for the third quarter. Our upstream joint venture operations included in our other segment were down about $23 million from last year due primarily to lower realized prices. So again, it was a third quarter that was in line with our business plan, proving once again our ability to grow our business in spite of a tough natural gas pricing environment, the impact of Gulf of Mexico storms, and portfolio asset sales. And with that, I'll turn it back to Alan.

Okay. Well, thanks, John. So just a few closing remarks before we turn it over to your questions. I'll start by emphasizing what a truly compelling story we've been able to share with you this morning. Despite the low natural gas price environment we're in, we've exceeded our own financial expectations each quarter this year. And our teams continue to excel in executing large-scale expansion projects to serve the growing natural gas demand that is really ramping up both in this year and as we look to the future, certainly. Not only do we have a clear line of sight to a full roster of projects that are in execution, but we continue to commercialize vital high-return projects across our footprint. And don't forget, this is an issue that I think people are probably missing as they think about the forecast of our business right now that we've been able to deliver these in the face of quite a bit of production curtailment on our systems, which really does provide a loaded spring as a very strong catalyst for earnings growth as natural gas prices rebound. So really, the environment we're seeing today is a very strong long-term bullish position for natural gas as all of the demand that we're connecting on our transmission systems will begin to pile up. But our gathering systems are really going to get a big pull through when that demand comes on. Importantly, very little capital is required on our part because a lot of it is just production curtailment or drilling without the producers turning it into line on existing pads. So a pretty powerful catalyst sits out there when we do see the call on this gas to support all the growing demand we're seeing. So all of this activity does underscore the accelerating demand for natural gas transmission capacity in the United States, particularly in the growing regions where we operate. We are confident in the role our valuable natural gas infrastructure will play in meeting both today's energy demand as well as the projected growth from power generation, reshoring of energy-intensive manufacturing, and LNG exports. As the most natural gas-centric energy infrastructure provider with access to the most prolific U.S. basins, Williams is the best positioned to serve steadily increasing domestic needs for clean and affordable energy while also helping unlock vast U.S. reserves for the global market. In closing, we've built a business that is delivering record profitability and strong financial returns in the present, but is positioned for even faster growth in the future. And with that, we'll open it up for your questions.

Thanks for the insights shared during the call regarding the gas market situation. I would like to revisit this topic, particularly concerning discussions with producers and expectations for 2025. How much of an increase might we anticipate if prices remain favorable? Additionally, I want to highlight that there is available capacity on some of your pipelines. What kind of operational advantages do you foresee if we see greater demand from some of the secondary or tertiary basins, where you wouldn't need to invest significantly, but the pipelines could still reach full capacity?

Yes. I'll hit the last part of that and I will ask Michael to hit the question of what kind of response we could see on our gathering systems. On the pipes, I would just say, our systems for the most part are completely loaded up. But the ability to expand our existing systems through addition of interconnects between pipes like MountainWest and Northwest pipeline, which we've got some projects that take advantage of the combination of those assets are a way that we're seeking out some additional capacity out of the systems. And in general, obviously, a lot of these systems have the ability to be expanded at a pretty low cost. A recent project that we just did this quarter adds compression in the Clay Basin area on Northwest pipeline and gets some more very critical capacity in between the Piceance and the Opal and Kern River markets, which obviously is in demand these days. And so that's just an example of a pretty small amount of capital relative to the value of that project, and those are the kind of things that are occurring in the West right now. And Michael, I'll turn it over to you to talk about the gathering operating leverage we have.

Jeremy, there's definitely a lot of opportunity to increase production on the producer end coming into 2025, and it will certainly be somewhat price responsive. We have about 4 Bcf per day right now, it is either shut-in from what was originally flowing or ducts or wells that have been completed but aren't flowing and have been connected to our systems. And so that's between the Marcellus and the Haynesville. So there's definitely an opportunity to increase some gathering volumes through our systems as prices rebound. And we've actually seen some of the curtailments come off and the producers are now flowing gas that has been once curtailed earlier this summer. So we are encouraged by the opportunity to be able to increase the volumes pretty rapidly through our systems. In some of these, it's just the operation of turning about to bring on some of these volumes very quickly. So it can respond very quickly when prices do rebound, which we expect them to do. There's going to be some demand growth next year on the power generation side. We've seen that over the last several years, the year-over-year growth from power generation and I don't see that deciding at all with all the coal plants that have been taken offline, still even with this growing power demand markets that we're seeing in virtually all of our markets. And I am encouraged by that.

Maybe pivoting to the industry at large, Williams has done some bolt-ons in recent years, nicely adding to the portfolio. We have seen broadly in the industry entity consolidation steadily continue. Just wondering, how Williams thinks about industry consolidation in the future? Would entity level consolidation never make sense? Or do you see more bolt-ons? Or there's not really attractive opportunity there?

Yes, certainly, that has been a driver of growth for a lot of players in the space. We've been very fortunate to have a lot of organic growth within our mix. And obviously, that's always what we're comparing when we look at any kind of acquisition, and obviously, we do look at acquisitions on a pretty steady basis. But really the hurdle that we always have to overcome there is the amount of growth that we have in our base business. And frankly, that is a process of constantly updating it these days with the level of growth that's accelerating, it's pretty hard to keep up with, frankly, seems like as soon as we get one plan done, it's outdated with the kind of growth we're seeing in other areas. So that's really the issue from a Williams perspective is just the very strong growth that we have off of our own business and to the degree that's not fully valued in our stock makes that acquisitions and tough things to do. So the good news is we have a lot of capacity and debt capacity that we're growing as our EBITDA grows so rapidly and that is providing for us to be able to do bolt-on transactions on assets that we think are kind of where the puck is going, our acquisitions on storage, a great example of that where we kind of got ahead of the market a little bit on where that is going. And that has turned into a very solid performance for us. And in fact, it's one of the things that helped us overcome the low gas price environment we've had this year. So I would just say, I think bolt-ons will continue for us and we'll be continuing to think about where the puck is going and acquisitions that will be strategic for us down the road. So that's kind of the way I see things in our space right now.

Obviously, there's a lot of demand from data centers, power generation. I guess with all the increased competition for pipeline space and capacity, are you seeing upward pressure on rates as existing contracts come up for renewals? Is there an opportunity to kind of increase the rates there? And then secondly, are you seeing opportunities to shift more capacity from your cost of service or recourse rates to negotiated rates at higher rates as this competition intensifies?

Yes, that’s an excellent question. The challenge for us is that any available capacity on our system is extremely valuable, and everyone is aware of this in relation to the cost of new capacity. In the past, when we had any capacity become available, the only way for anyone to stand out in their bids for that existing service was based on the term, which was 84 years. What we're noticing now is an increased length in the terms when capacity is available. We can't really adjust the pricing on that if it was part of the original base capacity offered to our utilities. This capacity is only released when it's turned back, which is quite rare. In fact, that was a situation from about five years ago. Capacity doesn’t often turn back because people recognize how incredibly valuable it is. Unfortunately, I don't see much opportunity to raise prices in that area. However, I believe our opportunity lies in expanding along our existing system where we have strong leverage. The Dalton Lateral expansion is a prime example; we anticipated potential for expansion when we built it. Thus, when the opportunity arises for that expansion, it offers very high returns because the cost to build it is relatively low compared to the value of the new capacity. We will continue to see these low-cost expansions along our existing system, which yield high returns.

And just looking at the opportunity set in front of you, it's large, it seems like it gets larger each quarter. And it seems like there's potentially billions of dollars of spending here on gas expansions at good returns over the next few years. I guess how are you thinking about the potential to increase CapEx spending over the next few years if you kind of sanction some of these projects? And would you consider moving closer to kind of a free cash flow neutral after dividends stance to capture more of these opportunities?

Yes. I mean the challenge is when you're doing sub-four multiple projects, you just keep expanding out your capacity. So that's a very high-class problem. But in fact, we're really not chewing up capacity when you're doing projects that have that kind of expansion, especially as these high-return projects. If you were having to load the ship up and you're having to wait for four years for those to come through, that would be one thing, but things like the deepwater are coming on now, things like regional energy access are coming on now. These are very high-return projects. And so we've kind of already got the train rolling there, and it's pretty hard to chew up capacity when you're generating those kind of returns on projects. And so that's really the picture for us that is a very high-class problem to have is that we're continuing to generate so much incremental capacity with these high-return projects.

I wanted to put a finer point on maybe the shut-ins and delay turn in lines that you're seeing. I think last quarter you said between the Northeast and the Haynesville, there's about 2 Bcf a day between the two combined. Wondering how that's trending in the third quarter now that we have similar gas prices to where we are in the second quarter?

Yes. We're currently producing about 4 Bcf today split between the Marcellus and the Haynesville, with approximately three Bcf coming from the Marcellus. In the Northeast, about one-third of that is shut-in gas. It's roughly a 50-50 split with the Haynesville. Most of the gas in the Haynesville is back online, primarily from ducts and delayed wells. However, in the Northeast, about 25% of the gas remains shut-in today. We are starting to see some of that come back online. EQT recently announced that they have restored all their gas production, indicating that some producers are responding to the increased prices in the Northeast.

My second question, SESE obviously went to market first and delivering market to the southeast utilities. Now you have a lot of peers proposing projects to go from essentially Louisiana with an endpoint to Georgia. I know it's early in the process with SESE, but over the longer term, how do you see Transco competing for additional Southeast demand going forward? And where do you have an advantage or disadvantage versus your peers and competing for some of that load?

Yes, the project that has been announced recently, a lot of that is effectively a bigger distribution system in Georgia and hits a lot of the southern markets and South Central markets that Transco is not positioned in. So the Transco runs through Atlanta and cap and up through the northeast part of Georgia. And so a lot of the projects that we're capturing are going to be the large-scale power generation projects. And I think the system expansion is positioned to deliver a more distributed gas into the south and central parts of Georgia as it's configured. So I think from our perspective, we like where we're positioned, but our big high-pressure transmission system that can access gas out of the Appalachia is super critical. And I do think that that's a bit of the station that's going to occur here is where the supply is coming from and what that availability is. So if you think about Marcellus and Utica supplies capable of serving both the Mid-Atlantic and Southeast markets from that area and then you think about the Mississippi Crossing project that has been proposed to supply the system, that's more going to be Haynesville based supplies. And so that's really the difference between those two projects. I think certainly, Transco has the ability to distribute Haynesville production as well. But in terms of those two projects, that was the major distinction there, is kind of where the supply was sourced on.

Yes, I would add, Alan, to that. A lot of these projects that are being proposed coming over from the Haynesville are going to pile up a lot of gas at Station 85, which is actually going to be beneficial for us to expand transfer the northward out of that area as well. So that will be a benefit to us to paint those projects given FID.

My question relates to Slide 20. I could not help but notice two more additions at the bottom, the Wild Trail project and Dalton natural expansion. Can we get some more details about these two new additions on the slide deck?

Yes. The Wild Trail project is one of the ones that Alan mentioned on the Northwest pipeline system. This is a project to move gas, basically grow the White River Hub, which in the Piceance area up to the Opal market area in Southwest Wyoming. It can also move capacity from the White River hub down to the Four Corners area as well as the way it's been proposed. It's a greenfield compressor station in Northeast Utah, which will give us a lot of opportunity to increase our deliverability and takeaway from the Clay Basin storage facility, which is on the MountainWest system, but it has an interconnect to Northwest pipeline and Northwest pipeline has capacity in Clay Basin. So a great opportunity to have connectivity to storage there and also move gas to markets in the fourth quarter here, as well as Southwest Wyoming, and a very efficient capital project. It's a greenfield compressor facility. We'll be a 7c application to the FERC. So that process takes between a year and 1.5 years to get permits or something like that and about a year for construction ultimately program we filed. As far as the other projects that we have for the Naughton conversion, that is a coal plant in Southwest Wyoming that is partially converted to gas usage from coal, and our project there is to expand that further for the other two units that are moving from coal to gas over the next several years. So a very capital-efficient project there basically requires metering modifications and then something like capacity that the shipper has taken on. And same with the Stanfield project, metering modifications, and those last two projects, which we have prior notice at FERC. So typically, those are a much quicker process.

And then he asked about the Dalton Lateral.

Yes. So the Dalton Lateral is near Atlanta. So it's just west of Atlanta. It was built about six years ago. It's a 115-mile-long lateral. It's a partnership with AGL, so we're 50% partners on that with them. And this project would be really a fairly simple scope. It's about 23 miles of 24-inch loop. It's a brownfield compression, just over 40,000 horsepower and then greenfield about 40,000 horsepower on that lateral. So from a scope standpoint, fairly simple. And the 2029 in-service date is what we're contemplating now; that's based on the desired in-service date from the customers that we're talking to. We have an open season that closes today for the remainder of that capacity, but we have an anchor shipper already in place for 460 million a day. We believe we could reasonably expand that to 500 million cubic feet per day or a little higher, depending on how the open season turns out, that like I said, will close today.

A quick follow-up here is your balance sheet is in a good position. Any strategic priority to further simplify the JV structures, whether it's Brazos, Blue Racer, anything on that front?

Yes. Chad, do you want to take that?

Yes. This is Chad. We continue to look at whether or not it makes sense to tuck in JV interest. Alan mentioned the capacity that we have bolt-ons. We like those kinds of transactions because we know those assets, they come with low risk and high kind of integration capabilities. But it really is, also, as Alan mentioned, just a matter of capital allocation, making sure that those tuck-ins work from a returns perspective. So yes, we continue to kind of look at how we can optimize the portfolio. You saw that earlier in the year when we did the Discovery acquisition with P66 and bought in that interest while at the same time, we sold our small interest in Aux Sable. So we will continue to look at those, but they'll have to compete with the attractive kind of organic growth projects that we're seeing.

Maybe turning back to the macro. Alan with the tailwinds behind you and the environment in front of you, following the election results, what are your views on how the Trump victory impacts your business and what it means for the energy infrastructure industry in general?

Yes, I would say that if the house and the Senate are controlled by Republicans, we can expect a very positive tax outcome, particularly in terms of bonus appreciation, which would significantly enhance our current guidance and plans. From our perspective, this is likely to have the most immediate financial impact on us. Regarding the macro environment, we are currently facing a lot of growth opportunities and if the economy keeps expanding, these factors may compound. I'm optimistic that with more Republican control, the permitting challenges will be addressed in a meaningful way, which would benefit all industries, especially the power and energy infrastructure sectors, by potentially easing some constraints. However, I recognize that addressing these issues will be challenging. I'm feeling more positive about this possibility with Republican leadership in both the executive and legislative branches. Thus, I have an optimistic outlook on infrastructure development. As an investor, it's important to consider the effects of taxes, given that we have had to restrain our outlook and hold back on our dividend coverage due to these tax considerations. This could lead to a significant change for us. Therefore, this is something we are closely monitoring at this time.

And turning to the fundamentals. At this point in the fourth quarter, would you be able to provide some color on your gas marketing activities, how that's trending and what your expectations are from here?

Chad, do you want to take that?

Yes, sure. This is Chad. Many of our marketing activities occur in the first quarter of the year. Winter is definitely a period we're prepared to leverage if we experience volatility or disruptions, but we have noticed less volatility this year compared to the previous couple of years. Therefore, I would say we are positioned to expect positive results for the remainder of the year, and we are also well prepared for any winter events or volatility. However, primarily, we anticipate that the outcomes of our marketing efforts will be reflected in the first quarter of the following year.

You mentioned that you're tracking in line with your long-term growth rate of 5% to 7%. Alan, you've also talked about potential opportunities to exceed that growth going forward. Can you spend a minute or two discussing what specific factors you are considering that might lead you to reevaluate that target and what we should be watching for moving forward?

Yes, great question, John. Well, I would certainly say as we look in the longer term, the higher returns on these projects and large amounts of new projects that are showing up as opportunities for us right now would drive that. We're obviously not going to call that until we've got that business contracted that will drive that growth. But just the large amount of stuff we already have that's contracted is a bit unusual to have this much growth contracted already without the benefit of other growth that would come on. And so if you kind of roll the clock back on that and you think about the acquisitions we've done, we do not have any bolt-on acquisitions or anything like that built into our growth, even though we'll have plenty of capacity to generate on that. So that's one thing I would highlight. Said another way, we've already got the business contracted that will help drive that kind of growth already. And so the capacity and new opportunities that have not identified themselves over a horizon are the kind of things that will drive that growth. Additionally, we really don't have built in the loaded spring that you heard Michael talk about in terms of a lot of this production springing back on. That's a very large catalyst for us. And so those are probably the things that are pretty evident to us as a team right now: converting a lot of the opportunities that we're looking at right now to contracted business in a way that we would start to include it in our guidance and our growth.

As a quick follow-up, now that you've had several conversations over the past couple of months, could you outline what some of these data center opportunities look like? Is the behind the meter aspect part of the discussion? How willing are they to offer returns that are better than what we've seen previously? Any insights on how those discussions have evolved compared to our expectations at the start of the year would be appreciated.

Yes, it's certainly a combination of both behind the meter initiatives and significant conversions. If you examine the current Integrated Resource Plans, particularly Duke's recently approved plan for 9 gigawatts of gas-fired generation, you can see the large power generators in the MountainWest region are discussing substantial power generation demands. When you factor in coal conversion projects like Naughton and Jim Bridger, the numbers become quite large when you combine conversions with growth. This growth is primarily driven by the demand from data centers in those areas. Many state governors we work with are actively advocating with their planning commissions to ensure they have sufficient power resources, as this is becoming increasingly critical. We are collaborating with these states, as many are concerned about missing out on these opportunities. The grid prospects are really expanding, and projects like the Dalton Lateral expansion are being fueled by this growth and the reshoring of industrial and manufacturing activities, as energy costs in places like Europe have pushed some businesses back to the U.S. The availability of low-cost energy here is a major factor in that shift. Additionally, there are detailed discussions underway with various stakeholders regarding behind-the-meter solutions. Some discussions focus on just supplying gas, while others involve joint ventures to provide comprehensive power generation. Our primary aim is to advance the gas transportation business, but we are exploring opportunities where our existing land and infrastructure can support data centers. Overall, the opportunities are quite broad. It’s difficult to predict how much will materialize as this is new territory for us. However, compared to where we started at the beginning of the year, the prospects have become much clearer and more optimistic.

I wanted to ask on LEG. Can you remind us how much of the capacity has take-or-pay commitments at this point? And were you surprised by some of your competitors moving forward just because now we're going to have three large Haynesville greenfield pipes getting built at the same time?

First of all, the vast majority of our capacity is contracted on that. In fact, it is take-and-pay contracting that we've done on that. And in terms of the other project, I'm not too terribly surprised if you look at the balance of where gas is going to have to come from and particularly gas that can meet the LNG specs and low nitrogen specs that are going to be required. I'm not too terribly surprised just because of how much demand growth we're seeing that's going to have to come from somewhere, and it's starting to mount up pretty big. So I'm not too terribly surprised by that, frankly. I don't know how well contracted those other projects are. I assume they're well contracted like ours is. But if they're not, I would be surprised. But assuming they're well contracted, I think it's just a sign that people know that there's gas for this incremental demand that's going to have to come from somewhere.

Yes, this is Chad. I'd also add that the Haynesville historically was plumbed to move gas to the East and Northeast. And so there's even going to be volumes that will want to move existing volumes that will want to move south to the LNG markets. But to Alan's first point, I mean, models not ours but even third-party models are showing over 10 Bcf a day of growth out of the Haynesville by the early 2030s to meet LNG demand. And so that's a lot of gas that's going to need to find its way to those LNG markets.

Yes. I think all the filings have been made in regard to the DC circuit actions and we made our application for a temporary certificate as well. And so we're awaiting FERC action on that. But as of now, we're flowing gas. The pipeline is operational and all that work is complete from a mechanical standpoint, we're just waiting for the legal action to take place. And I would say I was pretty encouraged by the response that FERC provided in regard to our renewing request with the DC circuit. And it looks like FERC is very firmly standing behind their decision and we're very confident, ultimately, that we'll have a certificate to operate REA.

I'd like you to comment on how the significant growth profile you have ahead of you will influence the dividend growth policy. Where do you see yourself having enough balance sheet capacity to handle what's in front of you here?

Yes, Rob. We definitely will, as I mentioned earlier, since these projects offer such high returns. Now that we have started with the big deepwater projects and regional energy access, many of the transmission projects we've previously invested in have laid the groundwork for these high-return opportunities. Once we get moving on that, we are not using up much capacity because we're generating significant EBITDA growth simultaneously. So, there is no concern about needing to reduce the dividend at all. In fact, I would say the opposite is true as we are considering what to do with the excess capacity and capital we have. So, that issue hasn’t come onto our radar.

And then I want to go back to the presidential administration question, what might change here. Speculative, obviously, but one of the things we could speculate about is, we might be adding growth on growth. So that tends to inflation risk arguably. So how are you protecting yourselves and your project returns from the potential of inflation risk?

Yes. We automatically incorporate our gathering business into the contracts. When looking at the operating margin on these projects, it’s quite high. The primary factor influencing the rate is the initial capital investment, and we approach this conservatively, ensuring we either understand the inflation risks or lock in costs like steel prices and other inflationary factors. Therefore, the main risk lies with capital rather than our operating leverage. Additionally, our rates within the pipeline operate under a five-year rate case filing schedule. Unlike many competitors who haven't filed recently due to over-earning, we can adjust our rates for inflation based on our business structure. Thus, the only significant risk to us is the capital side, which we account for in our estimates.

Last question, I'm just curious with respect to your storage position, given how much you've done in recent years, should there be a medium to large-size acquisition in the storage area, how important would that be to you from a strategic point of view?

You're saying if somebody else acquired?

Yes, while there was something for sale that had some pretty significant scale.

Yes, I think it depends on the price and how well it aligns with our strategy. We're very optimistic about storage right now, but we also recognize that we are currently in a favorable position where pricing supports mainly brownfield expansions from our standpoint, yet offers much higher margins than what we have paid for the assets. We've seen storage cycles before, and as positive as we are about the demand for storage, we want to avoid overbuilding that could lead to a decrease in pricing over time. That's something we are monitoring closely.

Yes. And I think it's important to note that not all storage is created equal. If you think about what we focused on Clay Basin in the Rockies is really an important storage asset to bridge against critical markets between West demand and East production. Nortex and the Dallas-Fort Worth area and that power complex. The Gulf Coast Storage transaction, our ability to integrate those assets with Transco for both injection and deliverability. So we will look at storage but not all storage is created equal. And so we're constantly looking for, as Alan mentioned earlier, what might be next and what might be needed and is there something that fits kind of the fundamental setup.

Just going back to the question around Haynesville pipelines and LEG, with those additional projects being announced, is there still a need or a want to potentially expand LEG in the future?

Yes, I would say there's definitely an opportunity to do that. As Chad talked about earlier, there is an expectation that Haynesville production would grow by 10 Bcf over the next decade or so or even quicker depending upon the LNG appetite there. So I think there's definitely an opportunity to economically expand the LEG project either by additional compression or by looping a portion of the projects so that's certainly not foreclosed by anybody that's entering market today.

And then maybe one on Transco with SESE ongoing right now. Can you remind us, is there a certain amount of time you have to wait just with respect to those customers before you announce another large project along the mainline? Or are you able to do that if the appetite is there?

Yes. I would just say, the Dalton Lateral is a great example. That comes right off of that capacity and is within the path of that. And so that's a great example of something that has no overlap whatsoever with the capacity that we're building there, yet it's still along in that same region. So I'd say I think this issue has been a little bit overblown and perhaps from my own comments on the topic, it is an issue when you talk about permitting, it is an issue once you file, and once you're down the road on if you're doing something within that same work area that would have an environmental impact, that is a risky proposition to add another project on top of that because they might get combined from a permitting standpoint and drag the other. And so we're very sensitive to that because we have customers that are very dependent on us delivering these projects on time, and we take that very seriously and particularly Duke has been very clear with us about not putting any risk on timing for that because they do need that gas so badly. So we're going to protect our customers' interests in that regard and not put things at risk. But it doesn't mean you can't expand the pipeline in that area. It just means that you're doing it within the same regions of impact; if you were to expand to lose or try to make a look larger than you originally called for or expanded it into a wetland, those are the kind of things that could drive a project and have it combine back to another. And those are the things that we're sensitive to. It certainly does not mean that we can't expand the pipeline, while another project starts an expansion of that pipeline while projects are going on, it's just not in the same work zone.

And I would say the key to that, though, is making sure you have distinct supply and demand customers identified and I've got a great example where the sell-side reliability enhancement project and the Commonwealth Energy Connector are really in the same corridor where we're actually installing compression at the same site for both of those projects, but they were separate and distinct projects, FERC evaluated and analyzed them separately but allowed us to do those projects simultaneously, if you will.

This is Jack Wilson on for Neal. Just a quick question around near-medium-term flexibility around Transco. Are there scenarios where small data center-driven pipes could relatively soon be tapped into? And will this require much change to compression or other equipment?

Yes, we can expand Transco in certain areas, and we're currently exploring a few options for that. The feasibility really depends on the size and scale of the facility in question. For instance, expanding for a hyperscale facility would have a different setup compared to a smaller facility needing around 180 to 200 megawatts. We can definitely accommodate those types of projects.

Okay. Well, thank you all for your interest. I really appreciate plugging in. We are really excited about the environment we're going into and really pay close attention to what happens here with the house as it relates to tax benefits as well as perhaps some pretty comprehensive permitting reform that would provide for a lot of expansion of infrastructure here in the U.S. that we think we'd be a beneficiary of. So excited about where we are today and really excited to see what the future holds for our own forecast as we see some of these changes roll suit. So thank you for joining us today.