The Williams Companies, Inc. (NYSE:WMB) Q2 2024 Earnings Call Transcript

The Williams Companies, Inc. (NYSE:WMB) Q2 2024 Earnings Call Transcript August 6, 2024

Operator: Good day, and thank you for standing by. Welcome to The Williams Second Quarter Earnings 2024 Conference Call. [Operator Instructions] Please be advised that today’s conference is being recorded. I would 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, and good morning, everyone. Thank you for joining us and for your interest in The Williams Companies. Yesterday afternoon, we released our earnings press release and the presentation that our President and CEO, Alan Armstrong; and our Chief Financial Officer, John Porter, will speak to this morning. Also joining us on the call today 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 integral to our remarks, and you should review it. Also included in the 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.

Alan Armstrong: Great. Well, thanks, Danilo, and thanks for joining us today. The story that John and I get to lay out for you this morning is one of consecutive growth as Williams continues to deliver on a long-term trend of per share growth and resilience regardless of the macro environment. In fact, we delivered record second quarter results, driven by the strong performance of our Transmission and Storage business this quarter, even our Gathering and Processing business held up very well despite challenging natural gas prices. The good news is that a meaningful increase in natural gas demand that continues to exceed our expectations will take advantage of these abundant supplies driving growth for years to come, and the supply side is poised to respond with over 1 Bcf a day of volumes from delayed TILs and temporary shut-ins to return to our gathering systems.

And before we get deeper into the financial metrics, I want to hit on a few key themes from the quarter, namely our crisp execution of key projects that are positioning us for continued earnings growth and the ongoing focus we are optimizing our portfolio and ensuring sustainable operations. So starting here on Slide 2. Our teams have executed on an extraordinary amount of strategic priorities, including placing projects into service in the Northeast, West and the Deepwater, Gulf of Mexico. Just to run down the list quickly here. Last week, we placed Transco regional energy access into full service ahead of schedule and under budget once again, ensuring clean and reliable natural gas is available to serve the Northeast region for the upcoming winter heating season.

And while the DC Circuit Court did issue a decision last week to vacate the FERC certificate for ARIA, we believe the court’s concerns about the FERC process is once again flawed and will be fairly easy for the FERC to resolve. In the meantime, we are taking the necessary legal and regulatory steps to address the court’s concerns, and ensure that this much-needed firm transportation capacity continues to be available to serve the needs of our customers without interruptions. I’ll remind you that our industry has seen court rulings in the past with projects such as Sabal Trail as well as fires expansion. With both of these projects operating today, we see limited risk on a eruption REA operations and are prepared to help the FERC in reaffirming the merits of this important project.

Other notable expansions, we’ve recently completed include the Marcellus gathering expansion that serves Southwestern rich gas zone in the Marcellus and the fully contracted Basin transmission expansion. In the Deepwater, there are 2 new fields that will increase EBITDA in the third quarter on our Discovery system, which we now fully own. So we’re excited about the acquisition of the additional interest in Discovery, and we’re really excited about the kind of growth that we’re seeing both here in the near term and the long term. So first of all, Chevron’s large anchor development and Beacon’s Winterfell 5-well program are both fully connected and will drive a large increase in EBITDA for 2025 as well as for the balance of this year. Additionally, brought on their prospect on June 25 that will grow EBITDA on our Eastern Gulf assets.

We were also active on advancing construction for several key projects. We initiated construction activities on the Louisiana Energy Gateway gathering, treating and carbon capture project as well as Transco’s Texas to Louisiana Energy Pathway project, which we call TLEP. TLEP project provides our anchor shipper EOG resources with access to the LNG corridor in higher-priced markets on the Transco Pipeline and specifically all the way into the Louisiana market. So we’re excited about getting started on that fairly significant project for us. And then recently, we also signed a precedent agreement on Transco’s Gilles West expansion. This will bring new, reliable and low-cost supplies to CenterPoint Energy Houston area markets from Louisiana, so this is effectively a backhaul on Transco, helping CenterPoint to reduce their dependence on the Texas intrastate gas pipeline systems.

Importantly, this quick turn project will add meaningful EBITDA with very little capital required on our part to place it into service. I also want to call out the significant emissions reductions and cost savings accomplished in the quarter as part of our system-wide emission and emission reduction program. Thus far, we have replaced 57 transmission compressor units and are on track to meet our goal of 112 units to be replaced by the end of this year, so that we can begin recovering on these investments in our listed rates. And on that note, we will file our new rates on Transco at the end of this month and the new rates will go into effect in March of ’25. So incredible amount of work going on by teams to replace a lot of these very old units with modern low-emission equipment on the system.

And a lot of times, those kind of projects kind of get overlooked, but tremendous amount of effort and great execution going on by the teams on that front as well. Looking at the second column, we continue to take steps to optimize our asset portfolio. We sold our stake in the Aux Sable joint Venture and an attractive gain and consolidate our ownership interest in the Gulf of Mexico Discovery system and an attractive value given both the very near and long-term growth on this asset. From a financial perspective, we remain on track to achieve the top half of ’24 EBITDA guidance and we also reaffirm our expectations for 2025, which translates into a 5-year EBITDA CAGR of 8%. More importantly, the growth in our per share metrics will be just as strong over this 5-year period with AFFO per share CAGR of 7% and our EPS CAGR of 12% over this 5-year period.

Of note, the fundamentals to sustain and even improve on this industry-leading earnings and cash flow growth beyond ’25 actually continue to improve. Our Southeast — our project is just of a few projects we expect from the secular end of increased demand for power generation, and we remain in the best position to secure additional infrastructure solutions in and around our Transco pipeline footprint. And finally, we continue to prioritize being a responsible operator in all that we do. And this is clearly outlined in our 2023 sustainability report that we published last week. This report is really a deep dive on how we focus on doing business the right way, and one area I’ll call is our efforts in progressing on our decarbonization goals. We are focused on proving up that the natural gas industry can play an even more important role in providing affordable and reliable energy while also continuing to reduce greenhouse gas emissions here at home and around the world.

And so with that, I’ll turn it over to John to walk through the second quarter financials. John?

John Porter: 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 3.5% year-over-year increase, despite low natural gas prices that fell about 5% versus 2Q ’23, averaging close to — for second quarter of 2024. And that 3.5% adjusted EBITDA growth is over a second quarter last year that had grown about 8%. So in spite of low natural gas prices, once again, our resilient business continued to grow even [indiscernible] customers employed pretty significant temporary production reduction measures like not completing drilled wells and/or not turning in-line wells that now stand ready to flow as prices improve. As we’ll 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.

Year-to-date, our adjusted EBITDA is now up 6%, so inline in the middle of our long-term growth target of 5% to 7%. For Q2, our adjusted EPS was up 2% and year-to-date EPS is up about 3%. So a bit slower EPS growth in ’24 as compared to the 19% 5-year CAGR that we’ve seen through 2023. But as Alan mentioned, looking through ’25, we do see a 5-year CAGR that will be in excess of 12%. For 2Q, available funds from operations, AFFO growth was 3% and 4% year-to-date. Similar story here with this slower ’24 growth is following an 8% 5-year CAGR through 2023. And when you look through 2025, we see a 5-year CAGR of 7%. Also, you see our 2Q dividend coverage based on AFFO was a very strong 2.16 on a dividend that grew 6.1% over the prior year and 2.38x coverage year-to-date.

And our debt to adjusted EBITDA was 3.76x, which is in line with our expectations, slightly higher leverage in 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. In general, our second quarter update is unchanged from what we provided in our first quarter earnings presentation. Based on our strong start to ’24, we guided to the upper half of our 2024 adjusted EBITDA range of $6.95 billion to $7.1 billion, and we indicated that we were well positioned for upside to drive toward the high end of this original guidance. We also shared that we remain well positioned to deliver on our 2025 adjusted EBITDA range of $7.2 billion to $7.6 billion.

And that based on our improved ’24 adjusted EBITDA outlook and some other changes, we saw our key per share metrics, adjusted EPS and AFFO per share coming in at the high end of their ranges for 2024. So again, no major shift to that first quarter update, except perhaps to say that we are increasingly comfortable that we can clear the $7 billion level for 2024 adjusted EBITDA while still not counting on any additional help from Sequent. And of course, we also wouldn’t include the around $150 million gain we expect to have on Aux Sable sale in there as well as we exclude gains and losses on asset sales from our adjusted EBITDA measure. So let’s turn to the next slide and take a little closer look at our first quarter results. Walking now from last year’s $1.611 billion to this year’s $1.667 billion.

We start with our transmission and Gulf of Mexico business, which improved $64 million or just over 8.5% due to the combined effects of a full quarter contribution from the Hartree Golf storage acquisition, which is delivering as expected, following a flawless integration effort. We also had higher Transco revenues, including partial in-service from the Regional Energy Access project, and segment growth was unfavorably impacted by last year’s Bayou ethane divestiture and also some planned downtime in the Eastern North of Mexico. Now the $36 million unfavorable variance for the Northeast G&P business is really against a strong quarter last year that included the effect of a onetime $15 million favorable gathering revenue catch-up adjustment.

However, we did see lower Northeast gathering volumes that were driven by those temporary producer reductions that were basically roughly in line with our plan for the year. And partially, those volume reductions were partially offset by rate escalations across several franchises in the Northeast. Shifting now to the West, which increased about $7 million, benefiting from the DJ transactions that we completed in the fourth quarter of 2023. The increase in the DJ Basin results was about the same magnitude as the unfavorable loss of hedge gains we had in 2023. Segment performance was also favorably impacted by higher NGL service results, including Highland Overland Pass pipeline volumes where low natural gas prices have supported greater ethane recoveries.

Overall, West gathering volumes were also lower as a result of temporary producer reductions primarily in the dry gas Haynesville area. And then you see the $2 million lower marketing loss that was in line with our plan based on the expectation that our natural gas marketing will typically have a loss in the second quarter. Our upstream joint venture operations included in our other segments were up about $2 million from last year. So again, a second quarter that continued to beat our business plan, proving once again our ability to grow our business in spite of a challenging natural gas pricing environment and also giving us further confidence in our ability to beat $7 billion of adjusted EBITDA in 2024. And with that, I’ll turn it back to Alan.

Alan Armstrong: Okay. Well, thanks, John. Just a few closing remarks before turning it over to your questions. I’ll end where I started with my remarks, and that is to emphasize what Williams has been able to deliver in the current environment and how well positioned we are for the future as natural gas demand continues to grow. As we think about our long-term strategy, 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 and LNG exports. We are seeing demand grow at an unprecedented pace and expansions of our uniquely placed infrastructure will demand a premium. Simply put, there is no other midstream company today that is set up better than Williams to capture this demand growth.

We are the most natural gas-centric large-scale midstream company around today, and our natural gas-focused strategy continues to deliver growth on top of growth quarter after quarter. And to that point, we’ve now seen 11 consecutive years of adjusted EBITDA growth and an 8% compound annual growth rate of our adjusted EBITDA since 2018. In addition, we have realized a 19.5% return on our invested capital during the last 4 years, and our steadfast project execution led to record contracted transmission capacity and will continue to drive per share growth in 2024 and beyond. In fact, our current projects in execution have higher returns than this prior 4 years. So 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 — for an even faster-growing future.

And so with that, we’ll open it up to your questions. Thank you.

Operator: [Operator Instructions] Our first question comes from the line of Praneeth Satish of Wells Fargo.

Q&A Session

Praneeth Satish: Maybe I’ll start with data centers here. So you mentioned that you’re looking is just the first and maybe a handful of other data center projects. I guess 2 questions here. Can you give us a sense of the size and scope of some of the other projects that you’re looking at in the backlog? And then how do you think about the returns on future projects for SES, I mean, we’re estimating around a 5x EBIT Delta. Do you think that some of the future data center projects that are in the backlog could earn similar types of returns?

Alan Armstrong: Yes. Well, first of all, Praneeth, thank you for the question and important issue. First of all, on actually, our return is even better than that, probably, as we’ve mentioned, the best return we’ve ever seen on a large-scale project on Transco and actually any of our transmission expansions over the long history for Williams. So pretty extraordinary return opportunity there. In terms of the data center load, we are right in the throes of that. We have a very long backlog of projects. And I will tell you that particularly in the Southeast and Atlantic, those expansion opportunities that we have, we frankly are kind of overwhelmed with the number of requests that we’re doing and we are trying to make sense of those projects.

Obviously, we’re not going to start or announce another expansion project on the top of because obviously, that would force a combination of projects. And so it doesn’t make any sense for us to be making any announcements when we’ve got a large project that we’ve committed to our customers to do everything we can to get that permitted cleanly and push that ahead. So extremely critical expansion for our utility customers in the Mid-Atlantic and the Southeast, and we understand that. And we’re going to make sure that we deliver on that first to our customers. But despite the fact that there’s a lot of attention there in the Southeast and the Mid-Atlantic, we’re actually seeing strong demand response, a lot of projects that we’re dealing with and trying to figure out how we can respond to in the Rocky Mountain states, particularly in Eastern Washington, the Quince area, in Idaho, in Salt Lake City region.

So a lot of demand going on everywhere. And frankly, the big developers that we’re working with are looking to find where they can — because the time is of the essence, probably more than we can even imagine in our business. And so they are looking to where the permitting regime is right, where there’s access to abundant natural gas supplies and frankly, where expansions on our systems are available. And so — this has moved from being one of where people have been very focused previously in cloud-based data centers. They’ve been very focused on the latency issue or in other words, the connection into the — into very fast and broadband networks to where they are now focused on the latency being less of an issue, not — I wouldn’t say it’s not an issue, but less of an issue and the speed to market for power generation and gas resources being available to power that are coming front and center, along with the local air permitting issues associated with that.

So I would just tell you, it is kind of an exciting time for us and even for me personally to be in such a steep learning curve on how we are going to make the very best use of our assets, but there certainly is not a dearth opportunity for us in that regard. In fact, as I said, it’s a little bit overwhelming, and we’re going to have to just make sure we make the very highest use of our assets because there obviously is as we expand the lower-cost expansions drive very high returns, but we only have so many of those. And those are precious, and we know that — and so we’re making sure that we make the various high return associated with the expansion around our assets. So we’re not going to put a number on it because I hear people putting a number on it.

And frankly, that’s a very large guess. And in a time frame frankly, that’s out there so far that — and if you’re not speaking to the returns that you’re making on the project, I’m not really the purpose of quoting those kind of numbers when you’re not really talking about the economic or financial impact to your business, and we’re not ready to lay that out. But I can tell you that if anybody else has more opportunity than we do, I wish them luck because we’re going to have a hard time keeping up with the opportunity in front of us right now. So hopefully, that gives you some color, but I would tell you, I think it’s not all that meaningful to quote volumes on expansions if you’re not talking about returns and you’re not talking about the time frame for those opportunities.

Praneeth Satish: Got it. No, that’s helpful. That’s great. And maybe just switching gears, can you help us understand what the next steps are for REA following the DC Circuit Court’s decision? I guess, have you filed for an emergency petition to keep the pipeline in service? And is there gas flowing today? Just trying to understand whether this impacts the early in service at all?

Alan Armstrong: Yes. Well, first of all, yes, gas is up and flowing, and kudos to our team for being able to respond so quickly to that. Just incredible project execution on that project in a difficult area. And I’m going to turn it to Lane Wilson, our General Counsel, to speak to the label proceeding.

Lane Wilson: Yes. So I think the next step will be speaking at temporary certificate. This is not new to FERC. They’ve dealt with this issue before. We fully anticipate they’ll be defending the certificate. We’ll be seeking rehearing on a timely basis, and that’s probably about 35 days out at this point, maybe 37, 38. But we don’t have any concerns that we’re going to be able to continue to operate. Don’t have any concerns about getting a temporary certificate and ultimately don’t have any concerns about defending what FERC has done on this project.

Operator: Our next question comes from the line of Jeremy Tonet of JPMorgan.

Jeremy Tonet: Just want to look at the guidance here and what the current thoughts are with regards to producer production expectations over the — I guess, the balance of the year and into 25 years is the expectation that we’ve kind of hit the lows and there’s kind of a growth from these points? Or just how you see production trending across your gathering assets?

Micheal Dunn: Jeremy, it’s Micheal. Yes, I think right now, we feel good about where we’re at in regard to our current forecast for the production profiles coming from our customers. You’ve got to look at it between the rich basins and the dry gas. And obviously, the dry gas is challenged by pricing now. So producers are making a month of decision on gas volumes that they might shut in. I think you probably saw Cutera’s announcement where they were shutting in $300 million for the month of August. And it’s really a month-by-month decision for all the producers out there. But right now, we’ve anticipated this, as you’ve probably seen through the first half of the year. The team did a really good job anticipating where the production shut-ins would occur and the delayed tills and ducts.

I would say right now, we’ve got over a Bcf of delayed TILs in the queue right now between all of our customer base, meaning that the producers have drilled the wells and completed them, and we’ve connected to them, and are ready to go when the price signals are there. And there’s over 1 Bcf as well of us, so they’ve been drilled but not completed on our systems. So there’s definitely a lot of opportunity to bring on gas as a producer, we see a price signal. And so I’d say our risk basins are still outperforming. We’re seeing good pricing netbacks for the producers there, and that certainly buffers the dry gas situation that we have right now. But all in all, we feel good about our end-of-year forecast. And certainly, 2025 is going to be presentative as well.

The Golden Pass LNG facility, you probably saw the announcement yesterday that they’re going to be an end of 2025 in service, it appears. And so that should have been anticipated already by the market. It looks like with the forward curve. And producers will be making decisions on these curves. And when prices elevate, obviously, they’ll hedge into that and keep their volumes flowing is what we anticipate. So we’re really comfortable with where our current forecasts are.

Jeremy Tonet: Got it. That’s very helpful. And I just wanted to pivot towards LEG, if I could. And I just wanted to see your latest thoughts on moving forward there. With regards to FERC requesting more information, just wondering if you could update us there on how you think about that?

Chad Zamarin: Yes. We’ve responded to the FERC data request, and we fully anticipate that FERC is either going to dismissed this matter or find a LEG as a gathering system. We don’t — really don’t have any concerns there. And so there’s really nothing for us to do right now except to continue down the current road, which is in construction. Again, we feel pretty confident about where we are in this project.

Operator: Our next question comes from the line of Spiro Dounis of Citibank.

Spiro Dounis: Alan, I want to go back on your closing comments there and maybe if we could tie power generation demand with how you’re thinking about the EBITDA outlook longer term. So one of your slides, Slide 17 points to 10x the amount of electricity demand grow over the next 10 years versus the last 10 years. I think you mentioned in your comments there, you guys have been able to grow at about an 8% CAGR historically. So as you think about the go forward here, you guys have that 5% to 7% growth target out there. Is it sort get about that as maybe potentially moving higher in this environment, which I don’t think you contemplated when you sort of laid that out there.

Alan Armstrong: Yes. Spiro, it’s a great question actually. And I do think that there is plenty of potential, even in the face of just the law of big numbers and continuing to put an absolute level of growth against a bigger and bigger number, that’s as you know, has grown faster than we’ve expected over the last 3 or 4 years. But I do think that given the strength of the return on our projects and the kinds of opportunities that are coming at us right now, I do think that, that is a fairly high profitability that we could expand beyond that. And particularly, as we get into the ’27-’28 time frame, and because I do think that people thinking that, for instance, data center load and power gen load — for us, that’s going to result in capacity sales on our transmission systems.

And that is going to take time to — we’re completely contracted out on our existing capacity. And so that is when we take time to build that out. But I do think as we get into ’27 and ’28, we’re going to see a very strong impact from the kind of demand that we’re seeing right now. The good news is for us, and I think a little bit uniquely, I think, is the number of projects we already have coming on in ’25, ’26 and ’27, give a great runway of growth. And I don’t remember a time when we’ve looked out and thought we’ve got this kind of accelerating growth into that past the next 3 or 4 years. So I do think that we just got done with our long-range plan and strategic planning. It was a very encouraging look at what our business looks like for the future with the kind of demand that we have coming in.

And frankly, I would say we’ve been pretty conservative in marking that into our plan at this point. So yes, I do think that we certainly — there’s very high profitability that we’ll be able to exceed that over the next 5 years.

Spiro Dounis: Great. That’s helpful color. Second question, just going to M&A. Was hoping for an update on the landscape. And if you’re seeing the same value proposition you saw over the last 2 years or maybe if we could expect you to look a little bit more inward now and consolidate some of these other JV positions?

Alan Armstrong: Yes. I mean there’s certainly an inventory of opportunity. Obviously, the discovery joint venture that we bought in here in — just recently, obviously, is one of those that was important for us and particularly where we’re seeing the growth. And certainly, as we look at the free cash flow that this business generates, we are looking for places to make wise investments with that capital. And so that certainly represents a target opportunity for us in terms of the joint ventures that we — I would say, we were very fortunate to have great partners like the Canadian investment — Canadian Public Investment Fund that helped us in the OVM area and helped us really expand that area pretty dramatically. And we’re excited to have them as partners, but there will be a time perhaps where they would want to monetize that.

So a good example of one where it worked out perfectly well and now provides an inventory investment opportunity for us in future. But I would say we’re going to be patient about that, and we’re going to have to have a willing seller on the other side to want to go and execute those.

Operator: Our next question comes from the line of Manav Gupta of UBS.

Manav Gupta: Quick follow-up a little bit on the lines of Spero. It looks like you bought some stuff from PSX. I know as a part of a partnership, about $170 million you paid for it. So help us understand the strategic thought rationally if buying at this point and buying from PSX? And obviously, I think PSX is in market with some other assets would you be interested in those also?

Chad Zamarin: Yes. This is Chad Zamarin. I’d say, again, we owned 60% of the Discovery joint venture with Phillips 66, and they’ve been a great partner for us. But — you’ve heard a lot about our offshore growth. And so it’s certainly a core part of our business and a very attractive growth profile ahead. And so we very core for us, I think you’d probably hear not core for PSX. So as Alan mentioned, where we have joint venture interests, we understand the operations of those facilities. It’s a low-risk investment for us. We see growth coming. In this quarter, if you think about Discovery, we were able to acquire that at what we think is a low multiple on a go-forward basis, as you’ll see the growth in Discovery really ramp up remainder of this year and even more impressively into 2025 and beyond.

And are stable on the other hand, again, an asset that we’ve owned for a had a great relationship there, but not core to our business, and Pembina has been consolidating their ownership in Aux Sable and the Alliance pipeline system. And so we’re able to sell that we saw pretty high mobile and. And you think about the difference in those cash flows, Aux Sable is a more volatile commodity-exposed set of cash flows discovery contracted asset that’s going to grow. So I don’t think that, that should be translated to other assets that PSX may own. It really is us, I think, rotating and optimizing our portfolio in a way that’s going to create incremental value. And that’s really the strategy when we look at any transaction, where do we have a unique opportunity to turn something into more value by owning or consolidating that interest.

Manav Gupta: Perfect. My quick follow-up is, obviously, we get a lot of questions on storage. So what is your thought process on current storage rates and expansion opportunity? You could talk about the set of opportunities as it is to storage?

Chad Zamarin: Sure. Yes, this is Chad again. We’ve only owned the Hartery storage assets for just 6, 7 months, and we’ve already seen really attractive recontracting of storage at rates that have exceeded our expectations. We have been in the test whether or not we’re seeing those rates and the tenor of terms approach expansion economics. We’ve seen the storage market certainly growing in value. That’s why we acquired Nordex, the Gulf Coast storage. We acquired Clay Basin in the largest storage asset in the Rockies as part of the MountainWest acquisition. And in all cases, we’ve seen an increase in value in storage over the last few years. I’d say that we’re still climbing the curve towards what we think makes sense from an expansion perspective are, I think, approaching the rates that are required for both brownfield and potentially greenfield expansion, but we’re still needing to see a bit more depth in erosion rates for us to put large capital to work in expanding those facilities.

But all signs are — we’ve shaped the fundamentals. We haven’t grown stores as a country at all over the last 10 years, while gas demand has been and will continue to grow significantly and importantly, we’ll grow in more volatile markets. And so we have a lot of confidence that storage will continue to increase in value and we will, at some point, reach the point at which expansions it makes a lot of sense.

Operator: Our next question comes from the line of Neal Dingmann of Truist Securities.

Neal Dingmann: And my first question, just on the gum, especially. Could you talk about the continued upside there. Specifically, it’s interesting. It seems like you have a lot of opportunities for additional projects. I mean, I think you all mentioned the 2 to 0 CapEx tiebacks that you announced after in that acreage dedication. So I’m just wondering sort of not even for the remainder of this year, but in ’25, how are you sort of looking at upside potential there?

Alan Armstrong: Yes, great question. A lot of exciting things going on in the Deepwater. And again, we’ve got so much activity going on. I think it’s easy to overlook the amount of execution that’s gone on, on projects like Well, which were — Shell is working the way at most of our work has retired on that at this point. And so there’s a little bit of remaining commissioning but for the most part, our work there and the risk of our work has been retired. So we’re excited about seeing that project come on. And that by far is the largest. The second largest is Chevron’s Ballymore project, and that’s actually been accelerated a little bit, from our original plans in terms of the timing on that will take a shutdown on the in faith platform that feeds into us here in the back half of this year.

But exciting project coming on there as well. And a great example of one where very large project kind of like anchor, but no capital required on our part. Those are very favorite projects in terms of adding incremental value in the business. And there’s a lot of drilling activity going on and — in and around our assets that we think is going to continue to drive value. One of the things that’s really changed in the Deepwater is, if you roll the clock back 15, 20 years ago, people were building these mammoth platforms — floating platforms, deepwater platforms that were an incredible engineering feeds. But it took a long time, a lot of uncertainty and a lot of risk. And today, what we’re seeing is producers working hard to find reserves and develop reserves around their asset base and their existing infrastructure.

And with that comes extremely high incremental returns for us because we’re not having to build out to that new infrastructure. And so I would say in the Deepwater, that is one of the really powerful things for us is the fact that we built a lot of this infrastructure with latent capacity in it and add that — just because it costs so much to lay a line in that depth of water way. And as that latent capacity fills up, we’re getting very high incremental cash flows off of that. So — but we are continuing to see a lot of activity and the producers happen to be. We’re very fortunate that a lot of the activity happens to be centered around our asset base in the Deepwater. And it really goes not just in the Western Gulf where there’s a lot of activity.

The Central Gulf, which we talked about today with both Anchor and Winterfell and Shenandoah is the next to come on. Next year, we spend a lot of time and effort getting prepared for Shenandoah because it is a fairly large prospects that will be coming on to our discovery system that will be coming on next year. And then in the Eastern Gulf, of course, you heard me mention the Hess project, it’s a tieback Gulf Star as well as the Chevron’s Ballymore prospect. So a lot of activity going on could be happier to have the really strong competitive advantages that we have

Neal Dingmann: Fantastic details. And then just one quick one on West. Specifically, you’ve been — there’s been quite a bit going on in the DJ with — around the acquisitions there. I’m just wondering can you talk about potential near-term upside around what you see for those acquisitions?

Alan Armstrong: Sorry, me on Curtin and our Rock?

Neal Dingmann: Yes.

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

Chad Zamarin: Yes. I would say that area continues to perform and, frankly, outperform. We really like the positioning that we have. We’ve got not only are we seeing more integration value in being able to optimize processing and gathering in basin. But because we market and transport the NGLs, we see a lot of margin from that growth further downstream. And so — yes, I think you’re already seeing some of the important contributions, and we do expect that to continue to grow for a long time to come. So we expect our performance

Operator: Our next question comes from the line of Zack Van Everen of TPH & Company.

Zack Van Everen: Just shifting to the Northeast. You mentioned rates on the Susquehanna and Bradford ticked up this quarter. I know you have cost of service contracts, at least on the Bradford side. Was that part of dynamic? Or was this something else? And is this kind of a good run rate going forward? Or is this kind of a onetime revenue makeup like we saw last year?

Micheal Dunn: Well, this is Micheal. With the cost of service agreement we had in Bradford has reverted to a fixed fee for the contract terms. So that has been finished and completed and negotiated with all the customers on the Bradford. And so I would just say, we did have a onetime drop last year that obviously affected the comparable for this year. But other than that, you should expect to see this as a run rate. Fee with obviously escalation being the variable there going forward. And then any expansions that we do would be negotiated as well through the capital that would be invested in those expansion opportunities there in Bradford.

Alan Armstrong: Probably the main thing that you see in the numbers you’re looking at a the fact that when we see more and more activity in the rich gas like we’ve been seeing, you see our margins in the rich gas are almost double what they are in the sometimes more than that. And so as the drilling moves into some of these rich gas developments like in the Utica and in Southwestern PA and West Virginia, you will see our average rate increase as the more and more of the mix moves into the rich gas. In addition to that, though, we have the inflation adjuster that hits every spring as well. And so that picks up those rates as well. So a lot of positive momentum on rates. And importantly, as we’ve said in the past, when the dry gas area is challenged, typically, we see the rich gas respond, and we make somewhat higher margin on the rich guest because of all the services we provide on it that tends to offset declines in the dry gas.

Zack Van Everen: Got you. That makes sense. And then maybe shifting to the Rockies. One of your peers announced they’d be converting their crude pipe out of the Bakken that flows into Wyoming into NGL service. Probably a little bit far out, but is there a space on Overland? And would you guys be interested in able to take those volumes if they were to approach you on that?

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

Chad Zamarin: Yes, sure. This is Chad. There is based on Overland Pass and we do see that as an opportunity. And I think good, frankly, for the Bakken producers that are some takeaway diversity, and we’re certainly focused on making sure we’d be a good option to receive NGLs from the Bakken and from the Powder River Basin. So yes, we do think there’s an opportunity there. We’re not going to get too far ahead of that, but we’re hopeful to see those barrels fighting south. And yes, we’ve got capacity in one pass that would be available.

Operator: Our next question comes from the line of Robert Catellier of CIBC Capital Markets.

Robert Catellier: Understanding that you flow rates by the end of the month on Transco. Could you give us any insight into the progress you’re making there in the likelihood of a settlement? And also your interpretation of shipper appetite to support modernization investments in light of your new methane intensity targets?

Micheal Dunn: Yes. Thanks for the question. Yes, we would love to see a settlement there. We’ll obviously get our rate case filed at the end of the month and then work on seeing if we can get to a settlement. We’ve obviously been talking to the customers for quite some time about the modernization efforts that we have underway. And there should be no surprise to them when we make our filing and they see the amount of investment that we’ve made there. And so we do think that will help possibly grease the skids for some type of modernization tracker with them so that we could smooth out some of these increases going forward on the Transco assets, just like we’ve done on the Northwest pipeline. Rates with our last rate case that we settled there.

So that is the intent going in as hopefully, we can get a modernization tracker, not just for our emissions reduction program, but for some of our pipe replacements that are needed some of the growing population centers there. We have a significant amount of pipe that we derated over the last several years and decades that we could upgrade and we will be doing that, but it would be better to do that through a modernization tracker as well. So that is the intent. But we’ve had a pretty good opportunity to discuss and alert the customers as to what to expect in this rate case. And once we get it filed, we’ll start the settlement opportunities. But — as you probably well know, the rates will go into effect on March 1 of next year, subject to refund once we either get a settlement or fully mitigate the outcome on the rate case.

Robert Catellier: Okay. And then next question here is just on the — what’s going on in the legal realm. How does the DC circuit decision in REA and also the Chevron difference case reversal impact how you’re approaching permitting?

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

Lane Wilson: Yes, it’s Lane Wilson. On REA, well, I mean, first Chevron difference. I don’t think anybody really knows for certain — how that’s going to play out, except that it will likely force the administration and subsequent administrations to stick more closely to what Congress has set out in laws and probably means fewer pendulum swings. I think that’s probably good for the industry on the whole. And in terms of REA, what was your specific question?

Robert Catellier: Yes. I’m just wondering if that decision changes how you approach future permitting activities?

Lane Wilson: Yes, I don’t think so. I mean, I think we feel like FERC active certificate order that was very defensible. It’s — the decision is unfortunate that the DC Circuit did what it generally does in this situation to kind of lay out a path for the FERC to fix the certificate, and that’s what we expect to happen. I don’t think that the Chevron case, Lower has any real impact on the way we’ll approach certificates in the future.

Operator: Our next question comes from the line of Tristan Richardson of Scotiabank.

Tristan Richardson: Just a question on the Gillis West project, a small project, but can you give out maybe some of the key differences between this project is a Transco expansion versus, say, a LEG from a permitting standpoint, right-of-way standpoint? It seems like this is certainly a smaller project, but offers quite a few efficiencies from a capital and permitting perspective.

Alan Armstrong: Tristan, thanks for the question. And the reason this is important is because that CenterPoint has been plagued with a number of very high price spikes in the Texas intrastate market for various reasons. And this allows them access to gas supplies that are more associated with the Henry Hub from a pricing point and gives them reliable access to supplies from Louisiana without being dependent on the volatility that some of the Texas intrastate pipes and markets have imposed on them, both for power generation and for normal residential loads. So we think it’s a great project for CenterPoint and important for us, really, all we need to do there is primarily just an interconnect and that will allow for us to provide gas supplies coming into the Louisiana market, places like Giles, which is becoming obviously an important pooling point for supplies.

And this will allow them access to those supply points from places like the Haynesville and diversifies their supply and again, kind of moves them away through volatility. So for us, it’s a great project because it’s effectively. We’re getting paid for transportation capacity flowing back to Texas and requires variable capital on our part, mostly just the interconnect there. So — exciting and I think a meaningful improvement for Texas and the volatility they’ve had to deal with there from some of the suppliers into that market. And — but in terms of — this is just basically transmission quality gas coming out of Giles that will help supply directly to their markets there down the Transco corridor. So pretty simple on one hand, but pretty important on the other.

Tristan Richardson: I appreciate it, Alan. And then maybe just on the last line of questioning a broader question about the regulatory environment. It’s been 2 years since we’ve had a full board of commissioners and we’re here at a time where you’re seeing meaningful demand in the Southeast Mid-Atlantic. Can you talk about what you would like to see on the permitting side from a streamlining or just anything to be able to better accommodate the demand you’re seeing?

Alan Armstrong: Yes. It’s a great question. I think the primary issue with the permitting, it’s not really the FERC. FERC, I think, has been very responsible agency, particularly under Chairman Philips leadership. And I think they’re trying to do the very best to see responsible infrastructure get developed, and they realize it’s very clear to them the kind of challenges that we’re going to have on the grid if we don’t have natural gas supplies available to provide incremental power supplies on the one hand and backing up renewables on the other. That is not lost on them at all. They face that responsibility as a commission and an agency, and I think they take it So that’s not really where the problem. The problem really revolves around the NEPA process and the handles that it gives to environmental opposition to take up issues that have very little to do with the pipeline construction, but have to do with their own fight against fossil fuels.

And because the NEPA process allows them to kind of grab hold of projects and appropriately the NEPA reform is probably the most important thing and really excited everybody has been talking about the Chevron deference, which we think is important, but you also saw the Supreme Court agreed to take up a review of the NEPA process as well. And I’m actually really excited to see that. That could really reform permitting in a way that’s meaningful and really stop people from being able to just arbitrarily stop projects and they’re tracking cause lawsuits in the process, which is the NEPA process that we know today. And so anyway, that’s important to the 401 water quality certificate that the states are allowed that gives them a right to just stop projects is important to see that turned around and as well as the judicial standard for the way that a court would review a complaint against the permit.

So those are really the 3 primary things that we’re looking for. And I actually were pretty normally not very optimistic about seeing anything happening on the permitting reform, but really excited to see the Supreme Court taking on the NEPA review. So we could see some. It’s not going to be quick, but we could see some relief there down the road.

Operator: Our next question comes from the line of Theresa Chen of Barclays.

Theresa Chen: Based on what we’ve seen in the market very recently as far as the data center related or data center-driven brownfield expansion on natural gas transmission. The implied rates seem to be far above several multiples of existing tariffs and economics. Is that consistent with your expectations as you move through the process of addressing the sheer number of requests you have? And is that a key hurdle in getting these projects done in addition to speed to market?

Micheal Dunn: Theresa, this is Micheal. Yes, I would say we’re still going to be seeing negotiated rate contracts as we’ve been doing on our transmission businesses that are in excess of our base tariff rates believe that’s what your question was. And as Alan said, there’s a lot of opportunities that we’re exploring, not just on Transco at on Northwest Pipeline or MountainWest Pipeline and Overthrust pipeline that we’re considering and allocating resources to all of the analyze has been a bit of a challenge. And so redeploying some of our engineers and project development teams to really focus on this has been a critical activity over the last several months. But I would say we’re going to see really good multiples on our projects.

We aren’t doing 6x multiple projects on any of our transmission businesses. And in fact, none of them have a 5 handle anymore. So I think that is a trend will continue because, as Alan said, the speed to market is incredibly important for these data center loads. And the fact that they need to be online quickly as their biggest priority as opposed to what their energy appears to us. And so that does certainly give us some leverage in the workplace especially with the I think it gives us an incredible opportunity to serve these new loads.

Theresa Chen: Got it. And a follow-up on the regulatory front. As we approach the election season in the fall, what are your latest thoughts around that as it pertains to assets within your business? Any key considerations on your mind as we move through the next few months on this front?

Alan Armstrong: Yeah, well, that’s a big, hairy topic, but I’ll just try to address it quickly. First of all, the taxes is probably are the most important thing, and it’s very real to us in terms of the ability to continue to invest in these high-return projects that we have as an opportunity in front of how the tax impact on our business and the amount of free cash flow. So it’s pretty obvious to us that delta and something we’re keeping a close eye on. Beyond that and you have to remind people this that even during the prior Trump administration, we had major projects get stopped like Constitution and Nesi because of the 401 water quality certificate that allowed to stop project without really an ability for the government to solve that.

And so I think it’s great that there will be a bigger push. I actually think paying more attention to how Congress turns out and the legislative front is actually a bigger push because that’s actually where we might see some reform in the law in a way that allows us to build out the pipeline infrastructure that we need. And so we saw recently the Manchin, Barrasso Bill did really nothing for the pipeline. And while we are very thankful to both Senator Mansion and Senator Manchin to Senator Barrasso and what they’ve done for our industry. In this case, that was really a throw to the transmission side of the business and really didn’t do much for pipelines. And so we think there’s got to be some — and we did that. That’s the state of the current Congress and the way the numbers stack up in there today.

I think they both would like to do more, obviously, for pipelines if they thought that was possible. And so we do think that watching to see how the legislature turns out could be an opportunity to see some serious reform on the permitting front. So I would say we’re paying a little more attention to that, frankly.

Operator: Our next question comes from the line of John Mackay of Goldman Sachs.

John Mackay: I wanted to go back to the conversation quickly if we can around data centers. Just on the comments around speed to market. I was just wondering if you could flesh that out a little bit more for us, but that would actually look like? Is that the location on Transco? Is that something non-FERC jurisdictional? Anything you can bring up there would be helpful.

Alan Armstrong: Yes. Well, John, thanks for the question. I would just say that what we’re seeing is a shift because I think that the developers are realizing that they’re kind of up against a brick wall right now in terms of extracting more generation off the grid. They realize that that’s pretty well exited. And so they’re going to look to areas where both natural gas resource is available. The capacity for it is available and as well as the permitting allows them to go build out some very significant power generation behind the meter on the one hand. We still are seeing a lot of growth on the utilities as well, more for the conventional data centers and the cloud-based data centers, a lot of growth continuing as well as just general electrification of load.

Sorry, that is driving that as well. But in terms of the hyperscaler and their approach right now, we are seeing them look all the way back into areas where the gas resource is abundant and the permitting allows for getting on with developing the infrastructure that they need to have reliable and affordable power into those markets. But as Micheal — I think the — in my earlier comments, the speed to market seems to be the thing that is most top of mind for the big, big hyperscaler developers. And so that’s where we think there’s going to be opportunity in places like Wyoming where we have a lot of gas resource available and a lot of wind resource available as well. And so I think we’re going to see that. But we’re also going to get a lot of indirect load from our utilities in these other areas as both the conventional data centers and electrification continues to grow in those markets.

John Mackay: I appreciate that, and I acknowledge we’re at top of the hour. I’ll squeeze one more in. It’s relatively small, but pretty interesting. I guess we’ve had a lot of conversations around trying to get gas out of Texas into Louisiana given the LNG ramp. I guess I’d just be curious your perspective, is this a macro trend kind of shifting? Is this kind of more of a maybe one-off with this customer? Anything you can kind of frame up from a kind of Louisiana demand-ramp perspective would be interesting.

Alan Armstrong: Yes. Well, I would just say, if you think about all of the supply that the Haynesville has available and some of the resources even south of Haynesville that we think will get developed in a pricing environment that’s coming forward right now. We think that having access to those Louisiana supplies the diversity of supply, is really important. Again, as I’ve mentioned in my comments, if you think about the pain that has been inflicted on some of the Texas utilities from the Texas intrastate market where they didn’t have us to a more diverse supply. We think this is a trend. I mean, it only makes sense that they’re going to look to see what’s been imposed on them from a pricing standpoint and look for more liable loss supplies to be available.

And to me, that’s the important thing about this is then recognizing that, that fluctuation did not occur in places like Louisiana and really only incurred on the Texas intrastate markets, and this gives them access to a more diverse supply. So that is the keynote to take away from that project.

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

Alan Armstrong: Okay. Well, thank you all very much for joining us today. An exciting time for us here at Williams as we continue to deliver the long list of projects that we have in execution and that continues to mount growth for us. and importantly, how strong the future is in terms of the demand that we are excited that we have an opportunity to help address, but an exciting challenge for the organization that we’re excited to show what we’re made of on that front. So with that, thank you very much for joining us today.

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