Kinder Morgan Inc - Class P (KMI) — Q2 2025 Earnings Call Transcript

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 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 that 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. 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.

Thank you, Rich. Our financial results for the quarter demonstrate strong growth compared to the second quarter of 2024, with adjusted EBITDA up by 6% and adjusted EPS up by 12%. For the year, we anticipate surpassing our original budget, which already indicated solid growth, particularly from the Outrigger acquisition. It is an exciting time to be part of the natural gas industry. This represents the best set of opportunities I have encountered in my 24 years in this field. The fundamental market conditions are robust, with U.S. natural gas demand projected to rise by 20% by 2030, according to WoodMac estimates. The federal permitting process has become more efficient, as evidenced by the U.S. Army Corps of Engineers issuing permits rapidly. Recent actions from FERC have also been beneficial, including a 50% increase in the prior notice limit and a one-year waiver of the five-month waiting period before construction can begin after a permit is issued. The Supreme Court's decision regarding NEPA should help streamline reviews and make it harder for nuisance lawsuits to arise. The recent budget reconciliation bill provides valuable tax advantages, such as incentives for investments and expanded interest deductions. Consequently, we expect substantial cash tax benefits in 2026 and 2027, with KMI not anticipated to be a significant cash taxpayer until 2028. The one challenge we face is tariffs; however, we do not foresee them having a major effect on our project economics at this time. For our major projects — MSX, South System 4, Trident, GCX, and Bridge, which make up nearly two-thirds of our backlog — we currently estimate that the impact of tariffs will be around 1% of project costs, unchanged from last quarter. Our project backlog increased from $8.8 billion to $9.3 billion during the quarter, adding $1.3 billion in new projects and placing about $750 million in projects into service. New projects include Trident Phase 2 and the Louisiana Line Texas Access project, which involves transporting natural gas from Katy, Texas, to the Louisiana LNG market. We also added two NGPL projects to support power plants. All these initiatives are backed by long-term contracts and promising returns. Additionally, we approved about $500 million of CapEx for KinderHawk, supported by life-of-lease contracts to facilitate a significant volume ramp-up by our clients. Currently, around 50% of the projects in our backlog will meet power demand. The multiple on the backlog is approximately 5.6x, slightly improved from Q1 because the projects we placed in service had a lower multiple than those added to the backlog. Overall, despite adding $6 billion in projects to our backlog over the past year, we still see ample future investment opportunities. As Tom Martin mentioned to me recently, while we are not in the first inning any longer, we are still far from the seventh-inning stretch. Our strategy remains consistent: we own and operate stable fee-based assets, which are essential to energy infrastructure. We leverage the significant cash flow these assets generate to invest in projects with attractive returns and to return capital to our shareholders, all while maintaining a strong balance sheet. Now, I'll pass it over to Tom.

Thanks, Kim. Starting with the Natural Gas business unit, transport volumes increased by 3% in the quarter compared to the second quarter of 2024, mainly driven by LNG deliveries on the Tennessee Gas Pipeline and new contracts along with LNG deliveries on our Texas Intrastate system. Natural gas gathering volumes decreased by 6% this quarter compared to the second quarter of '24 across most of our G&P assets, with the most significant impact seen in our Haynesville system. Sequentially, total gathering volumes were down by 1%. Our producer customers are gradually increasing their operations after experiencing lower gas prices in the latter half of 2024. For the full year, we anticipate our gathering volumes to average 3% higher than in 2024 but 3% lower than our 2025 budget. We expect gathering volumes to grow throughout the year due to a more favorable price environment than in 2024 and the necessity for increased production to meet rising LNG demand. Looking ahead, we are identifying substantial project opportunities across our natural gas pipeline network to enhance our transportation and storage capabilities in support of the expanding natural gas market. In our Products Pipeline segment, refined product volumes rose by 2% as did crude and condensate volumes in comparison to the second quarter of 2024. For the full year 2025, refined product volumes are projected to be about 2% higher than in 2024 and in line with our budget. In our Terminals business segment, our liquids lease capacity is high at 94%. Market conditions continue to favor strong rates and high utilization at our key hubs, including Houston Ship Channel and New York Harbor. Our Jones Act tanker fleet is fully leased today and will remain so through the rest of 2025. If likely options are exercised, the fleet will be 100% leased through 2026 and 97% through 2027. We have strategically chartered a large percentage of the fleet at elevated market rates and have extended the average contract length of our firm commitments to 4 years. The CO2 segment saw a slight decline in oil production volumes at 3%, an increase in NGL volumes at 13%, and a reduction in CO2 volumes at 8% when compared to the second quarter of 2024. For the full year, oil volumes are expected to be 4% below 2024 and 1% below our 2025 budget. With that, I'll turn it over to David.

We are declaring a dividend of $0.2925 per share for the quarter, which annualizes to $1.17 per share and is a 2% increase from our 2024 dividend. This quarter, we reported a net income attributable to KMI of $715 million, representing a 24% increase over the second quarter of 2024. Our earnings per share (EPS) came in at $0.32, a $0.06 increase from last year. Some of this improvement was driven by favorable mark-to-market adjustments on unsettled hedges. On an adjusted net income basis, excluding certain items, we achieved $619 million and an adjusted EPS of $0.28, which is a 13% and 12% increase from last year, respectively. Even when excluding the favorable adjustments, we saw solid double-digit growth compared to last year. This growth was fueled by larger contributions from our natural gas expansion projects, the Outrigger acquisition, and strong natural gas capacity sales driven by demand for our assets. Additionally, we experienced increased contributions from our Jones Act tankers. Our balance sheet at the end of the quarter showed $32.3 billion in net debt and a net debt to adjusted EBITDA ratio of 4.0x, down from 4.1x in the first quarter after the Outrigger acquisition. We expect to finish the year with a net debt to adjusted EBITDA ratio rounding up to 3.9x. Our net debt has increased by $623 million since the beginning of the year. To provide context for that change, we generated $2.811 billion in cash flow from operations over the first two quarters, paid out $1.3 billion in dividends, and invested a total of $1.42 billion. The Outrigger acquisition cost around $650 million, with other cash uses totaling about $65 million, accounting for the $623 million rise in net debt. As mentioned, we anticipate that our budget will be exceeded, mainly due to the contribution from the Outrigger acquisition. Our projected adjusted EBITDA growth for 2025 based on the 2024 figures was 4%. With the Outrigger acquisition included, we expect our EBITDA growth to rise to 5%, and our adjusted EPS growth will remain an appealing 10% from 2024. Most of our projected growth for 2025 is sourced from expansion project contributions, and we are on track to complete these projects on schedule and within budget, with only minor variances. The significant contributions will come from the Evangeline Pass project and our South Texas to Houston project, both of which are now operational. Additionally, Moody's has placed our credit rating on a positive outlook as of June, joining S&P, which issued a positive outlook earlier this year. Our credit spreads have already seen some improvement thanks to this. Overall, we are on a positive trajectory for the year and expect to exceed our budget. We have also approved additional profitable projects that will enhance our future growth and anticipate substantial cash flow benefits from tax reform. I will now hand it back to Kim for questions and answers.

Okay. Michelle, if you'll come back on, and we will take questions.

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?

Okay. A couple of points on that. One, I think 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.

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?

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 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 an 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.

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.

Sure. I want to emphasize that there has been no change in how we make our investment decisions or our approach to investments and returns. We continue to assess risk versus reward. On the risk side, we evaluate the stability of cash flows. This involves considering whether it's based on a take-or-pay contract or a long-term lease dedication. For take-or-pay contracts, we also look at the duration, whether it's a 5-year or a 20-year agreement, and the creditworthiness associated with it. When we have longer contracts with highly creditworthy partners under take-or-pay terms, we tend to align with the lower end of our return range. Conversely, for investments with commodity exposure or volume risk, we aim for returns at the higher end of our target range.

Okay. Great. I would like to get an update on your thoughts regarding behind-the-meter opportunities. I know you mentioned possibly having arrangements with partners, so I wanted to know the current status and how significant this could be as a future driver of capital expenditures.

When considering the most activity in the data center sector, it's primarily coming from regulated utilities. These utilities can incorporate these projects into their rate base and are entering power purchase agreements with data center providers. We haven't seen many independent power producers announce projects so far, but we are in discussions with them, and it's a viable option. If independent power producers secure contracts, they will likely be able to proceed with their projects. Now, I'll hand it over to Sital to provide more insight into our strategy in this area.

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.

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?

It's difficult to predict exactly what the mix will be. The main factor driving demand growth, based on both WoodMac's and our internal projections, is LNG, which is expected to double. Typically, when LNG projects are sanctioned, they start with a primary pipeline from the facility to the nearest liquefaction point. However, as development progresses, there is a tendency to seek out more competitive and diversified supply, leading to additional projects down the line. We have consistently observed, especially in the WoodMac figures, that their estimates may not accurately capture the growth we anticipate in power demand. This could create a discrepancy between the volumes they expect and the long-term contracts we aim to secure. The breadth and scope of power demand are substantial. We're witnessing increased power demand in states such as Arkansas, Louisiana, Georgia, South Carolina, Arizona, Wisconsin, and Texas. Therefore, when we evaluate the power demand projects in relation to the projected needs, I believe there's a strong correlation.

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?

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.

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.

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.

Yes, Jeremy, this is Sital. So I'll backspace on that and tell you 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 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.

We don't always know if the power is being directed to a data center or what exactly it is being used for, so we don't always have clear visibility as our customer is usually the power plant.

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 for more FIDs? Maybe just frame up like how that mix looks over the next couple of quarters or years?

Yes, it's challenging to predict the exact mix. The primary driver of demand growth, according to both WoodMac's and our internal projections, is LNG, which is expected to double. Typically, when LNG projects are authorized, they begin with a mainline from the facility to the closest liquid point. As development progresses, there is usually a search for more competitive and diverse supply, leading to additional projects later on. We have noted several times that we believe WoodMac's numbers do not accurately reflect the growth we anticipate in power demand. This could result in a disparity between their expected volumes and our projections for long-term contracts. The scale of power demand is vast. We're witnessing notable demand in states like Arkansas, Louisiana, Georgia, South Carolina, Arizona, Wisconsin, and Texas. When we evaluate the anticipated demand for power and the projects associated with it, I believe there is a clear alignment.

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?

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.

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.

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.

Yes, Jeremy, this is Sital. So I'll backspace on that and tell you 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 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.

We don't always know if the power is being directed to a data center or what exactly it's being used for, so we don't always have clear visibility since our customer is typically the power plant.

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 for more FIDs? Maybe just frame up like how that mix looks over the next couple of quarters or years?

It's difficult to predict exactly what the mix will look like. The primary factor driving demand growth, according to both WoodMac's projections and our own, is LNG, which is expected to double. Typically, when LNG projects are sanctioned, there's an initial pipeline that connects the facility to the nearest liquid point. However, as development progresses, there tends to be a search for more competitive and diversified supplies, leading to additional projects down the line. We've consistently pointed out, especially in relation to the WoodMac data, that we believe their numbers do not fully capture the growth we anticipate in power demand. This discrepancy may affect the volumes they expect versus what we plan to secure in long-term contracts. The scope of power demand is substantial, with notable increases in states like Arkansas, Louisiana, Georgia, South Carolina, Arizona, Wisconsin, and Texas. The anticipated growth in power demand aligns closely with our expectations for future projects in that sector.

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.

Thank you very much. Have a good evening.