Kinder Morgan, Inc. (NYSE:KMI) Q2 2025 Earnings Call Transcript

Kinder Morgan, Inc. (NYSE:KMI) Q2 2025 Earnings Call Transcript July 16, 2025

Kinder Morgan, Inc. beats earnings expectations. Reported EPS is $0.28, expectations were $0.2799.

Operator: Good afternoon, and thank you for standing by, and welcome to the quarterly earnings conference call. [Operator Instructions] Today’s conference is being recorded. If you have any objections, you may disconnect at this time. It is now my pleasure to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.

Richard D. Kinder: Thank you, Michelle. Before we begin, as usual, I’d like to remind you that KMI’s earnings release today and this call include forward- looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities Exchange Act of 1934. — as well as certain non-GAAP financial measures. Before making any investment decision, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

In previous quarterly calls, I’ve emphasized the positive attributes of the natural gas story, concentrating primarily on the rapidly growing demand in America. But as we all know, the gas market is international in nature and a great deal of the growth potential for U.S. production is driven by that worldwide increase in demand. So I thought today, I would spend a bit of time sharing some thoughts on what’s driving that overseas growth. Chief Economist of a major oil company recently estimated that global gas demand is expected to increase by 25% over the next 25 years. And I don’t believe that, that projection is unreasonable and it affirms my belief that natural gas will inevitably remain a key source of energy for the long term around the globe.

The factors underpinning that growth are pretty easy to understand. Demographers project continued substantial growth in worldwide population over that time period in the range of 2 billion additions by 2050. A great bulk of that increase will occur in the emerging markets of Asia and Africa. where the need for energy is particularly acute as large portions of the population move into the middle class, which drives additional energy consumption. Because there is a lack of local production and an inability to access gas by land-based delivery in most of those nations, it will be LNG, which will satisfy the bulk of this additional demand, and I think it will grow faster than the overall demand for natural gas. Now what’s the impact of all this international growth on the U.S. Energy segment?

I believe that American exports of LNG will play a critical role in supplying this international LNG demand. The U.S. has been the top global producer of natural gas for 15 consecutive years and the world’s top exporter of LNG since 2023. I believe the U.S. role becomes even more important in light of recent developments in the Middle East. Customers on the receiving end want security of supply without undue worries about disruptions caused by military actions, and this benefits the position of U.S. supply. This makes us confident that a major portion of the LNG required will move through America’s rapidly growing liquefaction terminals. Consistent with this view is the recent estimate of S&P Global Commodity Insights that LNG feed gas demand in America will increase by 3.5 Bcf a day this summer compared to summer of 2024 and that it will more than double by 2030.

Q&A Session

That should be a real positive for Kinder Morgan in as much as we move about 40% of all the feed gas for those facilities. When you add the international LNG growth to the robust need for gas to satisfy U.S. domestic power and industrial demand, examples of which are reflected in the new expansions that Kim and the team will be discussing on this call, it signals to me that the positive natural gas story has legs and will last for decades to come. With that, I’ll turn it over to Kim and the team.

Kimberly Allen Dang: Okay. Thanks, Rich. Our financial results for the quarter show strong growth over the second quarter of ’24 with adjusted EBITDA increasing by 6% and adjusted EPS increasing by 12%. For the year, we currently expect to exceed our original budget, which already reflected very nice growth by at least the contribution from the Outrker acquisition. It’s an amazing time to be in the natural gas industry. This is certainly the best opportunity set I’ve seen during my 24 years in this industry. The underlying market fundamentals are strong with U.S. natural gas demand expected to grow by 20% between now and 2030 by WoodMac estimates. The federal permitting environment has improved. The U.S. Army Corps of Engineers is issuing permits very quickly.

We’ve seen some recent FERC action, which is helpful, including a 50% increase in the prior notice limit and a 1-year waiver of the 5-month waiting period between the time — before you can start construction — between the time the permit is issued and you can start construction. So the Supreme Court ruling on NEPA should help narrow the scope of the NEPA reviews and make nuisance lawsuits more difficult. The recent budget reconciliation bill delivers nice tax benefit, including incentives for investment and expanded interest deduction. As a result, we expect significant cash tax benefits in 2026 and 2027 and do not expect KMI to be a material cash taxpayer until 2028. The one fly in the ointment is tariffs. However, at this point, we still do not believe that the tariffs will have a significant impact on project economics.

For our large projects, MSX, South System 4, Trident, GCX and Bridge that together comprise almost 2/3 of our backlog, we currently estimate that the impact of tariffs to be roughly 1% of project cost, which has not changed from our estimate last quarter. Our project backlog increased from $8.8 billion to $9.3 billion during the quarter. We added $1.3 billion in new projects and placed approximately $750 million of projects in service. The projects we added included Trident Phase 2 and the Louisiana Line Texas Access project, which include moving natural gas from Katy, Texas into the Louisiana LNG market. We also added 2 NGPL projects to serve power plants. All these projects are underpinned by long-term contracts and have attractive returns.

We also approved approximately $500 million of CapEx for KinderHawk, which is supported by life of lease contracts to accommodate a significant volume ramp-up by our customers. Currently, approximately 50% of the projects in our backlog will serve power demand. The multiple on the backlog is around 5.6x, slightly improved from Q1 as the projects we placed in service were at a lower — that we placed in the backlog were at a lower multiple than the projects we placed in service. Overall, despite $6 billion in project additions to our backlog in the past year, we continue to see very nice future investment opportunities. As Tom Martin said to me the other day, we aren’t in the first inning anymore, but we are anywhere near the seventh inning stretch.

Our strategy remains unchanged. We own and operate stable fee-based assets, which are core to the energy infrastructure. We use our significant cash flow generated by these assets to invest in attractive return projects, and we return money to our shareholders, all while maintaining a solid balance sheet. With that, I’ll turn it over to Tom.

Thomas A. Martin: Thanks, Kim. Starting with the Natural Gas business unit. Transport volumes were up 3% in the quarter versus the second quarter of 2024, primarily due to LNG deliveries on Tennessee Gas Pipeline as well as new contracts and LNG deliveries on our Texas Intrastate system. Natural gas gathering volumes were down 6% in the quarter versus second quarter of ’24 across most of our G&P assets, the biggest impact being in our Haynesville system. Sequentially, total gathering volumes were down 1%. Our one — our producer customers are still ramping back up after lower gas prices in the second half of 2024. For the full year, we expect our gathering volumes to average 3% above 2024, but 3% below our ’25 budget. We anticipate gathering volumes will grow over the balance of the year given the higher price environment than in 2024 and the need for increased production to meet LNG demand growth that is ramping up throughout the remainder of the year.

Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation and storage capabilities in support of the growing natural gas market. In our Products Pipeline segment, refined products volumes were up 2% and crude and condensate volumes were also up 2% in the quarter compared to the second quarter of 2024. For the full year 2025, refined products volumes are forecasted to be approximately 2% higher than in 2024 and flat to our budget. In our Terminals business segment, our liquids lease capacity remains high at 94%. Market conditions continue to remain supportive of strong rates and high utilization at our key hubs at Houston Ship Channel and the New York Harbor.

Our Jones Act tanker fleet is fully leased today and through the remainder of 2025. Assuming likely options are exercised, the fleet is 100% leased through 2026. and 97% leased through 2027. We have opportunistically chartered a significant percentage of the fleet at higher market rates and have extended the average length of our firm cotton contract commitments to 4 years. The CO2 segment experienced slightly lower oil production volumes at 3%, higher NGL volumes at 13% and lower CO2 volumes at 8% in the quarter versus second quarter of 2024. For the full year, oil volumes are forecasted to be 4% below 2024 and 1% below our 2025 budget. With that, I’ll turn it over to David.

David Patrick Michels: Okay. So we’re declaring a dividend for the quarter of $0.2925 per share, which is $1.17 per share annualized and 2% up from our 2024 dividend. For the quarter, we generated net income attributable to KMI of $715 million, which is 24% above the second quarter of 2024. We generated EPS of $0.32, up $0.06 from last year. Some of that benefit was due to favorable mark-to-market on unsettled hedges, which we treated certain items. But on an adjusted net income basis, which excludes certain items, we generated $619 million and adjusted EPS of $0.28, up 13% and 12% from last year, respectively. So even excluding the favorable certain items, we still experienced nice double-digit growth from last year. Our growth was driven by greater contributions from our natural gas expansion projects, the Outrigger acquisition and attractive multiple — excuse me, attractive natural gas capacity sales and other services, driven by favorable demand on our assets.

We also received greater contributions from our Jones Act tankers. On the balance sheet, we ended the quarter with $32.3 billion of net debt and a 4.0x net debt to adjusted EBITDA ratio. That 4.0x is down from 4.1x from the first quarter, which was right after we closed the acquisition of Outrigger. We expect to end the year with net debt to adjusted EBITDA that rounds up to 3.9x. Our net debt has increased by $623 million from the beginning of the year, and here is a high-level reconciliation of that change. We generated cash flow from operations of $2.811 billion for the first 2 quarters. We paid dividends of $1.3 billion. We’ve invested total capital of $1.42 billion. The Outrigger acquisition was approximately $650 million, and all of our other items were a use of cash of about $65 million, and that gets you to the $623 million increase for the year.

As Kim mentioned, we expect to exceed budget by at least the contribution from the Outrigger acquisition. Our budgeted 2025 adjusted EBITDA growth from ’24 was 4%. Just including the Outrigger acquisition, our EBITDA growth would increase to 5%, and our adjusted EPS growth would remain at an attractive 10% from 2024. Most of our 2025 budgeted growth comes from expansion project contributions, and we remain on target to place those expansion projects in service on time and on budget with only minor variances. The largest expansion contributions come from Evangeline Pass project and our South Texas to Houston project, our Texas Intrastate system. Both of those are now in service. So in my final items, in June, Moody’s placed our credit rating on positive outlook, and they joined S&P who put us on positive earlier in the year.

Our credit spreads have already improved some as a result. So we’re off to a good start for the year tracking to beat our budget. We’ve sanctioned additional attractive projects that will add to our future growth and expect meaningful cash flow benefits from tax reform. I’ll turn it back to Kim for Q&A.

Kimberly Allen Dang: Okay. Michelle, if you’ll come back on, and we will take questions.

Operator: [Operator Instructions] Theresa Chen with Barclays.

Theresa Chen: Congratulations on the progress in the commercial backlog under what seems to be fierce competition. Do you think the commercial landscape has changed with these demand tailwinds on a structural basis? And what do you think has allowed Kinder to win many of these projects? And what kind of learnings can you share that might shape your strategy going forward on the heels of these commercial wins?

Kimberly Allen Dang: Okay. A couple of points on that. One, I think what — part of what allows us to be competitive is the existing asset footprint that we have. We’ve got an outstanding footprint. And so we are very competitive where we can build off of that footprint and/or use the existing footprint to deliver volumes to customers. I’d say the other things are, I think people trust us to be able to build projects and get them delivered. And so if they’ve got a significant investment that they need natural gas delivered, they don’t want to be waiting on those molecules. When they get that project in service, they want to be able to have the supply there. So I think our track record in building and delivering projects is helpful.

And then I think the way we operate and the customer service that we provide in terms of trying to make sure that if we have maintenance or other items that our customers need to know well in advance, trying to make sure that we perform that maintenance at times when our customers would be least impacted and trying to find times when our customers when we can find alternative delivery for them. So I think that’s some of the things that go into the commercial discussions and allow us to win projects. And I think as you can see from what we’ve added to the backlog, we’ve been very successful.

Theresa Chen: And looking forward on additional projects to come potentially in the backlog. As far as the expansion of Westwood from the Permian, what is the progress on building additional natural gas infrastructure on that front? And what would something like copper state connector amount to in terms of cost economics as well as the potential for subsequent brownfield expansions down the line?

Kimberly Allen Dang: Okay. Well, let’s not get too far ahead of ourselves. On Copper State, there’s clearly a need in Arizona. I think the utilities have need for more natural gas. I think there’s the potential for data centers, and we’re having conversations on those fronts. Obviously, that would be a large project. There are other Copper State wood. I mean there are other smaller projects that we have that we’re looking at. but it is a competitive process on copper state and constantly changing tariffs make things more challenging on these larger projects where we’ve got to come to agreement with multiple different shippers. And then any project that we do on this front, the project is going to have to meet our return thresholds. And so we’re going to be very disciplined about how we deploy capital on this. But I mean, a project could be anywhere from $4 billion to $5 billion-ish.

Operator: Our next caller is Michael Blum with Wells Fargo.

Michael Jacob Blum: How do a capital allocation question really between gas pipelines and gathering investments. You talked about this big opportunity set on the gas pipeline side. Your average multiple is between 5 and 6x. So how do we think about a $500 million investment in KinderHawk? Does that mean this change on investment is generating an even higher return than that given the higher risk profile? Just kind of things all that.

Kimberly Allen Dang: Okay. Sure. So let me start by saying no change in the way that we make our investment decisions or in our approach to investment or investment returns. The way we’ve always done it is we look at the risk reward. So you’re looking at — on the risk side, you’re looking at how stable are the cash flows. And so that gets into, okay, is it a take-or-pay contract? Or is it a life of lease dedication. Does it have — if it’s a take-or-pay, is it a 5-year contract? Or is it a 20-year contract? What’s the credit on that? And so when you have longer contracts with higher creditworthy partners, and their take-or-pay, then within our return threshold range, you’re going to skew to the lower side of that range. And when you have things that have commodity exposure or volume exposure, then you’re going to look for a return at the higher end of our target range.

Michael Jacob Blum: Okay. Great. And then I just want to see an update how you’re thinking about behind-the-meter opportunities. I know you’ve talked about maybe having something in place with partners or — so wanted to see where that stands and how meaningful a driver of future CapEx that could be?

Kimberly Allen Dang: So I think when we think about where we’ve seen the most action on the data center front, if you will, is really from regulated utilities. I mean that’s where we’re seeing most stuff get done. So a regulated utility is able to put it in their rate base. They’re going out and they’re getting a PPA with the data center provider. We have not seen a lot of IPPs that have announced projects at this point in time. But obviously, we are talking to them, and that is — that’s a reasonable possibility because I think if IPPs can get contracts, they’ll be able to build as well. But I’m going to turn it over to Sital and he can talk a little bit more about our strategy there.

Sital K. Mody: Yes. So one of the things, as we look at the landscape on data centers, speed to market is key. And so as we look at the opportunity set, as Kim said, our focus has thus far been on the utility side and helping them with their power needs. We are looking at kind of a broader structure such as where we’ve got some key partners that specialize in their respective fields. Our expertise lies in bringing supply to the point. We bring storage and then we let the other folks do what they do best, including hyperscalers that know how to build data centers. And so I think the concept is we are looking at a few key sites in different areas and seeing if we can kind of pull together a bigger, broader project, specifically tied to behind the meter.

Operator: Our next caller is John Mackay with Goldman Sachs.

John Ross Mackay: Going to pick up on this project thread, of course, maybe just talking about the backlog on the gas side. You mentioned about 50% power utilities at this point. That’s arguably a larger share than power has and kind of the go-forward gas demand growth we’re looking at relative to LNG, I suppose. Maybe could you just talk a little bit about how you’d expect that 50% to kind of trend from here? Would incremental projects on the horizon, maybe putting aside copper state for a second, start leaning more LNG, I mean we need to wait more FIDs. Maybe just frame up like how that mix looks over the next couple of quarters or years?

Kimberly Allen Dang: Yes. I mean I’d say it’s hard to project exactly what that mix is going to look like. Obviously, the biggest driver of demand growth, both in WoodMac’s projections and in our internal projections is LNG, and there’s a doubling of — expected doubling of LNG. As we’ve said a number of times, those LNG projects, I mean, generally, when they get sanctioned, there’s an initial project that is sort of a mainline from the facility to the nearest liquid point. But then generally, as they move forward with their development, they’re looking to find more competitive supply and diversified supply. And so that leads to additional projects, additional projects down the line. One of the things that we’ve consistently said and that we consistently see is — and this is especially true in the WoodMac numbers is we don’t think that the Wood Mac numbers accurately reflect the growth that we think we’re going to see in power demand.

And that could be a difference between the volumes that they expect to flow and what we expect to sign up in terms of long-term take- or-pay contracts. But the demand, the breadth and the scope of the power demand is very enormous. And so I mean, we’re seeing power demand in Arkansas, Louisiana, Georgia, South Carolina, Arizona, Wisconsin, I mean, Texas. And so — I mean, the amount of power demand, I think, and the projects that we’re going to see on that front are — when you look at that relative to the expectations for demand in power, I just think there is an alignment there.

John Ross Mackay: That’s helpful. That’s a good thing. And maybe for my next question, you come on the new tax rules should open up some incremental cash flow for you guys. I guess just wondering if you can kind of put a bit of a number around the incremental cash kind of looking forward. And then on a related point, does it change how you think about your ability to go after projects your kind of implicit cost of capital? I know you’re kind of defending the return profile you want to get, but does an incremental tax framework change that at all?

David Patrick Michels: John, it’s David. For the tax reform benefit, we’re not quantifying it any more specifically than just saying we’ve got nice benefits from it beginning in 2025. It’s not material in 2025 to our forecast, but we’ll see some benefits this year because it was retroactive to the beginning of the year. We are seeing substantial benefits in ’26 and ’27. So as Kim said, we don’t expect to be a material federal income taxpayer in either of those years as a result of the tax reform. We see nice benefits there after, but we’re not quantifying those. And it also depends a little bit on when we put new projects into service because the full expensing provision is really the biggest piece of the benefit that we’re getting from tax reform.

Kimberly Allen Dang: And I would say having that incremental cash flow doesn’t change our investment strategy. So we’re not moving our return thresholds because we have incremental cash flow available. I think our view is and continues to be that for good return projects, there’s unlimited capital, and we will find a way to finance them. So Obviously, we’ve got a lot of cash flow available more now than we did before. We’ve got room on our balance sheet. And I think with the projects that we’re doing, they’re attractive projects. And so if we ever needed to, we can bring in outside capital.

Operator: Our next caller is Jeremy Tonet with JPMorgan.

Jeremy Bryan Tonet: Want to turn to Arkansas, if I could. We’ve seen recent reports of hyperscaler activity there and I want to double click on your Texas, Arkansas Power project. Noticed a binding open season there and given the 400 already prearranged there, it seems like that could support 2 gigs, very nice size for the project right there. But do you expect more to come along at that point? Do you see the possibility for more demand beyond that? Or really, you kind of have a fit-for-purpose pipe rate here and ready to go? And anything you could provide as far as incremental details there would be helpful.

Sital K. Mody: Yes, Jeremy, this is Sital. So I’ll back space on that and tell you that it’s — that project is supporting power. But broadly, when you think about the opportunity set, we are seeing incremental opportunity set not only in Arkansas, Texas, but along the that Midwest corridor. We do see incremental demand on the power side, where the utility ultimately uses it. That will be up to the utility. As we talked about, we’re looking at our own behind the meter opportunities. And so I think there is a robust pipeline of opportunities that we are trying to pursue, specifically in Arkansas and really broader across the network.

Kimberly Allen Dang: And I’d say we don’t always know if the power is going to a data center or what exactly so that they’re using it for. So we don’t always have clear visibility through — our customer is typically the power — is typically the power plant.

Jeremy Bryan Tonet: Right, right. Understood. Just the size of it there, it could support some nice power for the utility, not for Kinder, understood there. But I’ll leave that there. And just wondering, post the Georgia Power IRP filing here, does this impact, I think, the opportunity set as you see it in the Southeast? Could there be upside, I guess, to your current expansion plan scope to make those expansions larger?

David Patrick Michels: Yes. Look, I mean, as we’ve alluded to on previous calls, I think there is a broader opportunity set. We’re early in our discussions there. But the fundamentals look sound and the opportunity set looks good. Obviously, we’re positioned well with the network there, including the latest set of expansions. And as we alluded to on the last call, I think Rich said, we’ve got ancillary expansion opportunities to layer on top of that, we will pursue those as they present themselves.

Operator: Manav Gupta with UBS.

Manav Gupta: It looks like you have increased the size of Trident from 1.5 to 2 Bcf. And as I remember, you did this with Mississippi Crossings also the pipe got announced at 1.5 and got scaled up very quickly to 2.1 million. I’m trying to understand what’s driving this incremental demand. You come in, you announce a project and very quickly, you’re able to size it up so help us talk through those dynamics a little.

Kimberly Allen Dang: Yes. I mean on Trident, the incremental demand is associated with LNG. And it was a fairly easy expansion because there, all we needed to do was add some compression. I think when you go to a Phase II, then that would require some looping. So that’s a little bit that’s a little bit bigger nugget to take on. And so that would require more volume to do Phase II. But that pipeline is in a great, great location and to be able to get molecules from Texas all the way over into Louisiana is something people have been trying to do for a long time. And the combination of Trident and KMLA does that.

David Patrick Michels: Yes. In terms of the timing piece, Manav, I mean, really, it’s when we get the executed contracts to get us the returns that are sufficient. We know we have other customers that are interested we will FID the project if it makes sense, and then we continue to try and build upon it. That’s been the strategy.

Manav Gupta: Perfect. And it looks like the backlog also benefited from the NGPL new projects. Can you talk about — a little more about these projects? It looks like the power plant-related projects. So if you could help us understand that this incremental projects from NGPL that added to the backlog in this quarter?

Kimberly Allen Dang: Yes, they’re both power projects to serve power demand, one in Arkansas, one in Wisconsin essentially.

Sital K. Mody: Yes. That’s probably all we can tell you at this point.

Operator: Our next caller is Jean Ann Salisbury with Bank of America.

Jean Ann Salisbury: I just wanted to follow up to Kim’s answer to John’s question earlier about when LNG projects sign up for their gas pipeline needs vis- a-vis when they get sanctioned. You’ve obviously had a ton of LNG contracting activity over the last quarter. I think you’re probably still to come this sort of large wave of sanctioning. So I guess my question is if you believe that those projects have kind of already signed up for the gas takeaway that they would need or if that’s basically coming as the sanction of the projects over the next year?

Kimberly Allen Dang: Generally, what we see, and Sital will jump in here, is that when a project gets to get a project in FID, they need to get their financing and put their financing in place. And so to put that financing in place usually they’ve got to have a gas supply. And so that’s when the initial project, as I’ll call it, from the facility to the nearest liquid point gets sanctioned. And then generally, what happens after that is as they continue and they’re starting to get closer to in-service. They decide, okay, and they’re thinking about really how am I going to supply this on a daily basis. Then they start looking at, okay, that liquid point is very competitively priced. I might want to get some cheaper molecules and/or what happens if a pipe goes down or something, maybe I also need some diversification. So that happens more over time between the time the project gets sanctioned and before it gets put in service.

Richard D. Kinder: And let me just add to what Kim says that given the fact that this demand is occurring primarily along the Gulf Coast, where our system is so extensive. This kind of opportunity just lends itself to a structure like we have. I think we cannot overemphasize the benefit that we have from the infrastructure that already exists and the ability to expand it on a reasonable basis.

Jean Ann Salisbury: That’s very clear. And then as a follow-up, I wanted to ask about some of the dynamics of Permian gas pipelines. We’re very tight on egress capacity today, but something like 5 Bcf/d comes online next year, including your own GCX expansion. And I think there are a few other possible projects out of the Permian that seem to be progressing. So I guess the question is, if there’s some concern that this could put pressure on rates for Kinder Morgan later in the decade if some of those initial pipeline contracts begin to roll off. Can you just kind of talk about how you would frame that risk of Permian overbuild?

Kimberly Allen Dang: Sure. So the GCX and PHP are 2, I think those 10-year contracts expire in ’29 and ’30. What I would say is given that those were some of the first pipelines built out of the Permian to the Gulf Coast, they have very attractive rates on them. And so 2 things. One is, I think they are lower rates than where new projects are getting priced. So there’s going to be some of the cheaper transport out of there. And then the — I forgot what the second point I was going to make. But Sital, go ahead.

Sital K. Mody: Yes. So I mean, the other thing, as we think about the 2 pipes that we have, if you’re talking about kind of recontracting risk, et cetera, those pipelines fit very well in our network, and we have the ability to extract probably, in my view, better values once those — if those aren’t recontracted. And so we view that risk is low. When we think about the X project out of the basin, we’re going to be very prudent as we think about our focus has shifted to demand pull when you think about the projects that we sanctioned over the last couple of quarters. So if there is another producer-push project, it would obviously have to be very well contracted and for a longer term.

Kimberly Allen Dang: So those pipes go into our Texas intrastate system. They feed contracts that we have in the Austin market. So we have in-use demand attached to that, and that’s something that we can offer shoppers and customers that other people can offer. And then the other thing I was going to say is that when we run our economics in order to be conservative to make sure we get good returns on these projects, we assume generally, we assume a step down in rates whenever contracts roll. Not saying that that’s going to happen here. But that’s part of how we make sure that we get the returns we’re expecting to get.

Operator: Our next caller is Keith Stanley with Wolfe Research.

Keith T. Stanley: I wanted to start on the $500 million Haynesville gathering project. When would the expansion capacity be in service? And what’s the projected time line for the volume ramp to get to returns? And then relatedly, how do you think, if at all, about potential Haynesville takeaway pipelines given all the Louisiana LNG projects we’re seeing and your expanded gathering presence?

Sital K. Mody: Sure. So on your first question, we plan on getting all of our facilities in by the end of the fourth quarter next year. And so we do see volume ramping up along the way. Really, we’re adding treating capacity and we’re adding incremental pipe loops just to get — unlock some of the hydraulics there. Look, as we think about the outlook in the Haynesville, you’ve got a very productive basin that’s very close to the demand centers that we’ve been talking about. And so there’s a definite need to get incremental molecules to those consuming basis — they’re consuming — the consumers, right? We got to get the physical molecule there. So as far as the build-out, the existing build-out that’s there, given the growth that we see on the Gulf Coast, I think all that does is creates incremental opportunities for us in both our interstate and intrastate networks to be able to connect the dots.

You’ve got a lot of convergence at Gillis right now. We’re exploring opportunities downstream of Gillis to connect the market to that supply that’s aggregating at Gillis. And if there’s an opportunity, we could even consider tying in some of that Kinder Hawk production on another takeaway project out of the basin. But once again, all of that’s got to be contracted for, and it’s got to make economic sense.

Keith T. Stanley: Great. Second one, I wanted to follow up on some of your opening comments, Kim, on the permitting improvement and the order 871 and no longer having to wait the 5-month waiting period before starting construction. When you think in aggregate about those improvements that you’re seeing, could this meaningfully accelerate the time line on some of your larger projects versus original expectations?

Kimberly Allen Dang: So the answer is it depends. So this is a — on 871, it is a — it’s 1 year, but they’ve got it out for notice and comment. And I think our expectation is that they likely make this permanent, but we’ll just have to wait and see. And so right now, with respect to the 1-year extension, not a lot of benefit for us. But if they make it permanent, then yes, there will be benefits to our major projects. And so it’s going to depend and the reason it depends is it depends on the procurement schedule. And so when we get the pipe and when we get the compression. So there are certain projects that we will be able to move up by about 5 months and take advantage of, and there are others that we won’t. The other thing I’d say is on the prior notice.

That has increased by 50%. So now it’s $61 million. That means you don’t have to file for a 7c for projects that are less than $61 million. So the permitting process is much quicker. And so we will definitely benefit from that increase in the prior notice limit. The other thing I’d say on the bigger projects is we’ve actually filed for a waiver for 871. So we’re not waiting on the notice and comment period to be complete. We’ve asked them to decide independently on our big projects, South System 4 and MSX. And I think we view the likely outcome of that favorably at this point.

Operator: Our next caller is Zack Van Everen with TPH.

Zackery Lee Van Everen: Just going back to the Haynesville expansion real quick. Can you guys speak to the volume or capacity that you’re adding there? And then is this mainly from your larger customers? Or are you seeing demand from some of the privates that feed your system as well?

Kimberly Allen Dang: It’s both. So it’s from the larger customers and it’s from the private and somebody may be able to speak to the capacity. But I mean they are ramping up significantly. If you look at our supply numbers and Tom, help me with this because you talk to the Board about this today, but we are expecting — Wood Mac is expecting a doubling in the production coming out of the Haynesville. So I mean it’s increasing by, I don’t know, from 13 to 26 — 26 by 2034. So I mean, that gives you a sense of the type of volumes that we are talking about.

Zackery Lee Van Everen: Got you. That makes sense. And then maybe one on the LNG side. I know Tennessee Gas feeds the Plaquemines facility and VG continues to talk about potential further expansion at that site. If they were to do that, does Tennessee Gas have the ability to expand more to feed LNG in that area?

Thomas A. Martin: So first, if they were to do that, I think it further creates opportunities for us with these projects that we’re bringing across. I think ultimately, it could — Tennessee is already full in multiple directions, but we’ve got the bottleneck — debottlenecking capability as we bring this incremental supply from West to East that I’ve been talking about on the last few calls. We talk about Texas Access project, which is kind of continuing on the theme. We talked about Trident and we talked about the header and now we’re actually extending into Texas to take volumes across to Louisiana. That helps debottleneck. And so if Plaquemines were to further expand, we would look at opportunities to bring incremental gas to the basin to that area from not only but some other — from some of our other pipes in the area, including potentially looking at accessing the Haynesville in a different direction, right?

And so when we talk about Gillis and kind of the directions that these pipes may head, one of those may be going that further eastward direction to kind of help fill that incremental need.

Operator: Our next caller is Jason Gabelman with TD Cowen.

Jason Daniel Gabelman: The first one I wanted to ask was on the Bakken, given the Outrigger deal has been closed for quite some time. I think you are at least 6 months and H is close to ramping up here on the conversion. So just wondering what the strategy is on gaining volumes there and kind of securing potentially higher rates that, that region has to offer versus other basins?

Sital K. Mody: I’ll take that. So one, the integration, as we talked about has gone well. We’re looking at incremental network and bottlenecks to be able to gain further efficiencies out in the basin. But as far as it goes — as far as Highland Express goes, we just continue to work with our customers there. I don’t have anything to report on that. We’re making progress, but nothing for this call.

Jason Daniel Gabelman: Okay. And then just maybe longer-term question. You’ve talked a lot about the LNG growth on the U.S. Gulf Coast and the boom it’s been for your business. There is some concern that after this wave of capacity, there’s going to be a potential oversupply in the market. And I wonder if you’re — in your conversations with LNG customers, hearing anything around a potential slowdown in contracting or need for additional piping into future plants after this wave of capacity comes online or if your LNG customers really expect new builds to continue at pace through the decade and into the 2030s?

Kimberly Allen Dang: I mean, from my perspective, I mean, we’re not seeing — and you can see this from what the LNG builders are announcing, which is they continue to announce new projects. and sign new contracts. And we see — we continue to see projects get announced and projects get expanded. And I think part of the reason that you see that is it is a favorable environment right now to get projects built in the U.S., number one. Number two, I think that from a trade negotiation standpoint, it helps on the balance of payments and the whole tariff discussion to take gas from the U.S. So I mean, to date, we have not seen any slowdown in our discussions with these customers.

Richard D. Kinder: And Tom, you might share your model that you showed the Board today in terms of overall growth in worldwide demand and the U.S. portion of it.

Thomas A. Martin: Sure. I mean, as Richard alluded to in his comments, world demand is expected to grow by 25% between now and 2050. And much of that growth, actually more than 25% will be filled in our view and I think in the view from others in the market with LNG. Most of that growth, as Rich said, is in Asia, basically areas where they don’t have production. So it’s going to have to be LNG that ultimately fills that hole. And what we’ve seen so far is that the U.S., while the overall demand profile is growing, the U.S. market share is growing as well. So it’s almost a doubling effect of the benefits of having LNG infrastructure growing in the U.S. And I think that’s for a few reasons. One, the rule of law here in the U.S. as compared to other places around the world.

There’s a very advanced network within the U.S. such that if there’s ever a need to leave molecules back in the U.S. and optimize those from a world price environment versus a domestic U.S. environment, we have a great network of infrastructure here in the U.S. to support that. And then I think the track record. I mean, I think the developers in the U.S. have done an extremely good job of being successful in getting projects online timely and providing competitive rates. And we have a tremendous supply resource here in the U.S. that I think gives customers internationally a lot of comfort in knowing that there’s going to be a plenty of molecules behind these 20-year contracts that they signed with U.S. developers and with customer — midstream companies like us.

So I think the U.S. is in a great place. to continue to grow well north of what the overall global gas demand growth is between now and 2050. So I think that means more to come beyond what we see in the immediate line of sight of projects.

Operator: Our next caller is Brandon Bingham with Scotiabank.

Brandon B. Bingham: Just continuing on the LNG theme here. Could you maybe discuss some of the incremental opportunities you see maybe outside the Haynesville? And concurrently, which basin or basins do you expect to be sort of next on deck to meet all of that growth that you guys have been talking about?

Sital K. Mody: Yes, sure. So outside of the Haynesville, we’ve talked about this before. The lean Eagle Ford is going to be important. One of the key themes that’s kind of coming to surface is low nitrogen, the nitrogen quality of the gas. And as you think about LNG plant efficiencies, lower nitrogen equates to better production. So we think the Lean Eagle Ford is going to come into play, especially as it pertains to some of the Texas LNG facilities. You’ve obviously got the Permian. When we think about the Utica and the Marcellus, given the constrained nature of the basin, it’s going to be hard to get extra capacity out there. That being said, we are evaluating some opportunities to move incremental gas out of the Utica down south using our Tennessee network.

And so that’s in its early phases. It’s going to take an all of the above approach because it’s not just the LNG folks that are looking for molecules. It’s the power demand that we just talked about, and it’s also the existing organic LDC and the basic power that we’ve been talking about since January of 2024. All of that is going to be growing and needing access to molecules. So it’s an all-of-the-above basin approach. We’ve even talked about our Bakken egress project on the residue side, moving gas out west. I mean that’s another example of something that’s going to come into play as this demand kind of matures.

Brandon B. Bingham: Okay. Great. And then maybe just on the full year budget commentary regarding the EBITDA, reiterating the commentary there about exceeding by at least the Outrigger contribution. Could you discuss some of the areas you see outperforming expectations in 2H that sort of offset some of the lighter performance we’ve seen through 1H to kind of meet that expectation?

David Patrick Michels: The outperformance in the second half of the year, consistent with what we’ve seen in the first half of the year, really. Natural gas capacity sales, the Outrigger acquisition contributions parking loan services on our natural gas business, the Jones Act tanker contributions, those are all some of the items that are contributing to the second half outperformance, and those are consistent with what we’ve seen in the first half. I would say there was a little bit of timing between the first quarter and the second quarter. We didn’t see some of that show up in the first quarter, but out river particularly in some of the pals performance as well.

Operator: Harry Mateer with Barclays, you may go ahead, sir.

Harry Mead Mateer: David, earlier, you made the point that most of the expected reconciliation bill benefits come from the treatment on depreciation, which I think makes sense is it doesn’t look like the 30% of EBIT deductibility for interest was a material constraint for KMI. But having said that, does the expanded interest deductibility cause you to rethink anything on the financing or balance sheet side moving forward to take greater advantage of those tax benefits on interest expense down the road?

David Patrick Michels: No, it really — it’s a good question, but no, it really doesn’t. I think our financing strategy is pretty straightforward and simple. It’s pretty plain vanilla. And we don’t have a ton of external capital needs to fund our growth projects. We can fund $2.5 billion internally from cash flow that we generate as that EBITDA continues to grow, that will continue to grow. And so we really just use our external financing strategy to refinance our maturing bonds and this tax reform won’t influence that in our view.

Operator: At this time, I am showing no further questions. I’ll turn the call back over to you for any closing comments. Thank you.

Richard D. Kinder: Thank you very much. Have a good evening.

Operator: Thank you. This concludes today’s conference call. You may go ahead and disconnect at this time.