Kinder Morgan, Inc. (NYSE:KMI) Q2 2024 Earnings Call Transcript

Kinder Morgan, Inc. (NYSE:KMI) Q2 2024 Earnings Call Transcript July 17, 2024

Kinder Morgan, Inc. misses on earnings expectations. Reported EPS is $0.25 EPS, expectations were $0.26.

Operator: Welcome to the Quarterly Earnings Conference Call. All lines have been placed on a listen-only mode until the question-and-answer session of today’s call. Today’s call is also being recorded. If you do have any objections, you may disconnect at this time. And I would now like to turn the call over to Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.

Rich Kinder: Thank you, Sue. As usual, before we begin, 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 decisions, 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.

Now on these investor calls, I’d like to share with you our perspective on key issues that affect our Midstream Energy segment. I previously discussed increased demand for natural gas resulting from the astounding growth in LNG export facilities. And last quarter, I talked about the expected growth in the need for electric power as another significant driver of natural gas demand. Since that call, there has been extensive discussion on this topic with the consensus developing that electricity demand will increase dramatically by the end of the decade, driven in large part by AI and new data centers. I’m a firm believer in anecdotal evidence, particularly when it comes from the actual users of that power and the utilities who will supply it, and from the regulators who have to make sure that the need gets satisfied.

And the anecdotal evidence over the last few months has been jaw-dropping. Let me give you just a few examples. In Texas, the largest power market in the US, ERCOT now predicts the state will need 152 gigawatts of power generation by 2030. That’s a 78% increase from 2023’s peak power demand of about 85 gigawatts. This new estimate is up from last year’s estimate of 111 gigawatts for 2030. Other anecdotal evidence also supports a vigorous growth scenario. For example, one report indicates that Amazon alone is expected to add over 200 data centers in the next several years, consistent with the large expansions being undertaken by other tech companies chasing the need to service AI demand. Annual electricity demand growth over the last 20 years has averaged around one-half of 1%.

Within the last 60 days, we’ve seen industry experts predict annual growth from now until 2030 at a range of 2.6% to one projection of an amazing 4.7%. So the question becomes, how will that demand be satisfied and how much of a role will natural gas play? Many developers of data centers would prefer to rely on renewables for their power, but achieving the needed 24/7 reliability by relying only on renewables is almost impossible and growth in usage is limited by the need for new electric transmission lines, which are difficult to permit and build on a timely basis. Batteries will help some and some tech companies now want to use dedicated nuclear power for their facilities. But as the Wall Street Journal recently pointed out, they will likely increase reliance on natural gas to replace the diverted nuclear power.

Again, anecdotal evidence is key. In Texas, a program that would extend low-cost loans for new natural gas-fired generating facilities was massively oversubscribed, which an ERCOT official predicting a day’s gas daily could result in an additional 20 gigawatts to 40 gigawatts just in the state of Texas. And the Governor has already suggested expanding this low-cost loan program. That oversubscription, I think, is clear evidence that the generators are projecting increased demand for natural gas-fired facilities. Perhaps Ernest Moniz, Secretary of Energy under President Obama summed it up best when he said and I quote, there’s some battery storage, there’s some renewables, but the inability to build electricity transmission infrastructure is a huge impediment, so we need the gas capacity.

As an example of how industry players see the world developing, S&P Global Insights has quoted in Gas Daily reports that US utilities plan to add 133 new gas plants over the next several years. And this view is reflected in the significant new project in the Southeastern United States that we are announcing today. While it’s hard to peg an exact estimate of increased demand for natural gas, as a result of all this growth and the need for electric power, we believe it will be significant and makes the future even more robust for natural gas demand overall and for our midstream industry. And with that, I’ll turn it over to Kim.

Kim Dang: Okay. Thanks, Rich. I’ll make a few overall points and then I’ll turn it over to Tom and David to give you all the details. We had a solid quarter. Adjusted EPS increased by 4%, EBITDA increased by 3%, and those were driven by growth in our natural gas segment and our two refined products business segments. We ended the quarter at 4.1 times debt-to-EBITDA and we continue to return significant value to our shareholders. Today, our Board approved a dividend of $0.2875 per share and we expect to end the year roughly on budget. Now, let’s turn and talk about natural gas for a minute. The long-term fundamentals in natural gas have gotten stronger over the course of this year with the incremental demand expected from power and backing-up data centers that Rich just took you through.

Overall, WoodMac (ph) projects gas demand to grow by 20 Bcf between now and 2030, with a more than doubling of the LNG exports as well as an almost 50% increase in exports to Mexico. However, they are projecting a 3.9 Bcf a day decrease in power demand. As Rich’s comments indicated, we simply do not believe that will be the case given the anticipated power-related growth in gas demand associated with AI and data centers, coal conversions, and new capacity to shore up reserve margins and backup renewables. Let’s start with the data center demand. Utility IRPs and press releases published since 2023 reflect 3.9 Bcf a day of incremental demand, and we would expect that number to grow as other utilities update their IRPs. It’s early in the process, but we’re currently evaluating 1.6 Bcf a day of potential opportunities.

Most estimates we have seen are between 3 and 10 of incremental gas demand associated with AI. Rich took you through the 20 Bcf a day of natural gas power that Texas is contemplating, subsidizing, I should have said 20 gigawatts as well as the US projection of 133 new gas plants over the next several years. At Kinder Morgan, we’re having commercial discussions on over 5 Bcf a day of opportunities related to power demand, and that includes the 1.6 of data center demand. Certainly, not all these projects will come to fruition, but that gives you a sense of the activity levels we’re seeing and supports our belief the growth in natural gas between now and 2030 will be well in excess of the 20 Bcf a day. Not including — not included in the 5 Bcf of activity that we’re seeing is capacity SNG signed up on its successful open season for its proposed approximately $3 billion South System 4 Expansion that’s designed to increase capacity by 1.2 Bcf a day.

Upon this completion, this project will help to meet the growing power demand and local distribution company demand in the Southeastern markets. Mainly as a result of this project, our backlog increased by $1.9 billion to $5.2 billion during the quarter. In the past, we have indicated that we thought the demand for natural gas would allow us to continue to add to the backlog, and South System 4 project is an example of that. We continue to see substantial opportunities beyond this project to add to our backlog. The current multiple on our backlog is about 5.4 times. During the quarter, we also saw some very nice decisions from the Supreme Court. On the Good Neighbor Plan, the court stayed the plan, finding that we are likely to prevail on the merits.

There’s still a lot to play out here, but I do not think the Good Neighbor Plan will be implemented in its current form. It is likely to be at least a few years before a new or revised plan could be put together and a few years beyond that for compliance. And in the interim, we’ve got a presidential election. The overturning of the Chevron doctrine, which gave deference to regulatory agencies when the law is not clear, is also a positive. Together, these decisions will help mitigate the regulatory barrage we’ve seen over the last couple of years. And with that, I’ll turn it over to Tom to give you some details on our business performance for the quarter.

Tom Martin: Thanks, Kim. Starting with the natural gas business unit, transport volumes increased slightly in the quarter versus the second quarter of 2023. Natural gas gathering volumes were up 10% in the quarter compared to the second quarter of 2023, driven by Haynesville and Eagle Ford volumes, which were up 21% and 8% respectively. Given the current gas price environment, we now expect gathering volumes to average about 6% below our 2024 plan, but still 8% over 2023. We view the slight pullback in gathering volumes as temporary that higher production volumes will be necessary to meet demand growth from LNG expected in 2025. Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation capacity and storage capabilities in support of growing natural gas markets between now, 2030 and beyond.

At our products pipeline segment, refined product volumes were up 2%, crude and condensate volumes were flat in the quarter compared to the second quarter of 2023. For the full year, we expect refined product volumes to be slightly below our plan about 1%, but 2% over 2023. Regarding development opportunities, the company plans to convert its Double H Pipeline system from crude oil to natural gas liquid service, providing Williston Basin producers and others with NGL capacity to key market hubs. The approximately $150 million project is supported by definitive agreements and the initial phase of the project is anticipated to be in service in the first quarter of 2026, with the pipe remaining in crude service well into 2025. Future phases could provide incremental capacity, including in support of volumes out of the Powder River Basin.

In our Terminals business segment, our leased liquid capacity remains high at 94%. Utilization and project opportunities at our key hubs at the Houston Ship Channel and the New York Harbor remain very strong, primarily due to favorable blend margins. Our Jones Act tankers are 100% leased through 2024 and 92% leased in 2025, assuming likely options are exercised. And currently, market rates remain well above our vessels at current — currently contracted rates. The CO2 segment experienced lower oil production volumes at 13%, lower NGL volumes at 17%, and lower CO2 volumes at 8% in the quarter versus the second quarter of 2023. For the full year, we expect oil volumes to be 2% below our budget and 10% below 2023. During the quarter, the CO2 segment optimized its asset portfolio in the Permian Basin through two transactions for a net outlay of $40 million.

The segment divested its interest in five fields and acquired the North McElroy Unit currently producing about 1,250 barrels a day of oil and an interest in an undeveloped leasehold directly adjacent to our SACROC field. The impact of these two transactions is to replace fields with high production decline rates and limited CO2 flood opportunities with fields that have attractive potential CO2 flood projects. In the Energy Transition Ventures group, they continue to have many carbon capture sequestration project discussions that utilize our CO2 expertise for potential projects to take advantage of our existing CO2 network in the Permian Basin and our recently leased 10,800 acres of pore space near sources of emissions in the Houston ship channel.

These transactions take time to develop, but the activity level and customer interest are picking up. With that, I’ll turn it over to David Michels.

David Michels: All right. Thanks, Tom. So a few items before we cover the quarterly performance. As Kim mentioned, we’re declaring a dividend of $0.2875 per share, which is $1.15 per share annualized, up 2% from our 2023 dividend. As disclosed in the press release, we’re changing our Investor Day presentation from annual to biannual. We plan to continue to publish our detailed annual budget early in the first quarter as normal. Also, last one before we get to the quarterly performance, I’d like to recognize our accountants, planners, legal teams, business unit teams, everyone involved in the preparation for our earnings release and our 10-Q filing, we already have a tough close at this time of year with many working during the July 4th holiday period.

And additionally, many of our Houston-based colleagues were impacted by Hurricane Beryl. I want to thank you all for going above and beyond to meet the challenges presented by power outages and damage and not missing a beat with regards to our quarterly reporting and analysis schedule. For the quarter, we generated revenue of $3.57 billion, up $71 million from the second quarter of last year. Our cost of sales were down $4 million, so our gross margin increased by 3%. We saw our year-over-year growth from natural gas products and terminals businesses, the main drivers were contributions from our acquired South Texas Midstream assets, greater contributions from our natural gas transportation and storage services and higher contributions from our SFPP asset.

Our CO2 business unit was down versus last year, mainly due to lower crude oil volumes due to some timing of recovery of oil in the second quarter of 2023. Interest expense was up due to higher short-term debt balance due in part to our South Texas Midstream acquisition. We generated net income attributable to KMI of $575 million. We produced EPS of $0.26, which is flat with last year. On an adjusted net income basis, which excludes certain items, we generated $548 million, up 1% from Q2 of 2023. We generated adjusted EPS of $0.25, which is up 4% from last year. Our average share count reduced by 18 million shares or 1% due to our share repurchase efforts. [Technical Difficulty] up 2% from last year. Our second-quarter DCF was impacted by higher sustaining CapEx and lower cash taxes, both of which are at least in part due to timing.

We expect cash taxes to be favorable for the full year and sustaining capital to be in line with budget for the full year. On a year-to-date basis, EPS is up 5% to last year and our adjusted EPS is up 9% from last year, so good growth. On our balance sheet, we ended the second quarter with $31.5 billion of net debt and a 4.1 times net debt to adjusted EBITDA ratio, which is consistent with where we budgeted to end the quarter. Our net debt has decreased $306 million from the beginning of the year and I’ll provide a high-level reconciliation of that change. We generated $2.9 billion of cash flow from operations year-to-date. We’ve paid out dividends of $1.3 billion. We’ve spent CapEx of $1.2 billion and that includes growth sustaining and contributions to our joint ventures.

And we had about $100 million of other uses of capital, including working capital. And that gets you close to the $306 million decrease in net debt for the year. And with that, I’ll turn it back to Kim.

Kim Dang: Okay. And so now we’ll open it up for questions. Sue, if you could come on, please.

Q&A Session

Operator: [Operator Instructions] Our first question is from Manav Gupta with UBS. You may go ahead.

Manav Gupta: Thank you, guys. First, a quick question here. The backlog went up pretty much, I mean, on a good note, which is very positive, but the multiple also went up just a little. So if you could just talk about the dynamics of those two things here.

Kim Dang: Okay. Sure. So the backlog, as I said, was up by $1.9 billion. That’s really two projects that are driving that. It’s the South System 4 that we mentioned and then it is also Double H is the other one and it’s our share of South System 4. And then with respect to the multiple, yes, it increased a little bit. As we always say, the reason that we give you the multiple is to give you guys some idea of the returns that we’re getting on these projects so that you can be able to model the EBITDA. Now it is not our goal ever to — we’re not targeting a specific multiple and getting a specific multiple on the backlog when we look at these projects. When we look at these projects, we’re looking at an internal rate of return.

And so — and we have a threshold for that, and we have a pretty high threshold for our projects. And that threshold is well, well, well in excess of our cost of capital. And then we vary around that threshold, what I’d say, marginally depending on the risk of a project. And so if we have — and projects that we do, that are connected to our existing infrastructure, where it’s not greenfield, tend to have a much higher multiple associated with it. When we are having to loop a pipeline or something, those typically might have a little bit higher multiple, but they’re still meeting our return thresholds. And so I think these are very — despite the fact that the multiple on the backlog is going up a little bit because of these projects, these are still very, very attractive return projects.

Manav Gupta: Thank you for a very detailed response. My quick follow-up here is, you mentioned the demand coming from data centers and we completely agree with you. When you are having these discussions with the data center operators, we believe at one point, these data center operators were not even talking to natural gas companies, they were only talking to renewable sources. Have you seen a change in sentiment where reliability has become a key factor, so you are a bigger part of these conversations than you were probably 18 or 24 months ago?

Kim Dang: Yeah. I’d say our initial reaction was similar to yours when we started to see this demand was, they’re probably going to target renewables. But as we have had discussions with them, I think that the two things are key from their perspective. One is reliability, and two is feed the market. And so I think natural gas, and Rich said this last quarter, given the reliability of natural gas, it is going to play, we believe, a key role in supplying energy to these data centers.

Manav Gupta: Thank you very much. I’ll turn it over.

Operator: Thank you. Our next question is from John Mackay with Goldman Sachs. You may go ahead.

John Mackay: Hey, team. Thanks for the time. Maybe we’ll pick up a little bit on that last one, surprisingly. So if you guys are talking about 5 Bcf of power demand discussions right now, would just be curious to hear a little bit from you on where you’re seeing that geographically. Is it primarily Texas? Is it elsewhere in the portfolio? And anything you can comment on in terms of speed-to-market? And again, that might be a Texas versus kind of more FERC jurisdiction kind of discussion, but both of those would be interesting. Thanks.

Kim Dang: Okay. No, I think the — and Sital and Tom, you guys supplement here. But this the 5 Bcf is overall power, so some of that’s related to AI and some of it’s just related to coal replacements, shoring up reserve margins, backing up renewables. So it’s across the board, we’re seeing it in Texas, we’re seeing it in Arkansas, we’re seeing it in Kentucky, we’re seeing it in Georgia. Desert in Arizona, desert Southwest, I mean it’s — it is in almost all the markets we serve. We’re seeing some sort of increase in power demand.

John Mackay: And maybe just on the kind of time-to-market in terms of how long it could bring — how long it could take to bring to the market?

Kim Dang: It’s very much dependent on where these are going to be cited. And so it depends on, is it a regulated market? Is it an unregulated market? So that’s just going to vary depending on the market location.

John Mackay: Yeah. Appreciate that. And just a second question, you guys talked a little bit about some kind of portfolio optimization here. There’s the CO2, I guess, you could call it asset swap. There’s a line in the release on maybe some divestitures in the nat gas segment. I guess, I’d just be curious overall for an updated view on how you’re thinking about kind of portfolio pruning and optimization over time.

Kim Dang: Okay. So on natural gas, I’m not sure. We did have a divestiture earlier in the year, which was a gathering asset, but not — that wasn’t during this quarter. And so that was just — it was an asset that wasn’t core to our portfolio and we had someone approach us, and so the price made sense, and so we sold it. On the CO2 sale, we had three — four fields where there was limited opportunity for incremental CO2 floods. And that is our business, is injecting CO2 to produce more oil. And so we sold those fields that had limited opportunity. And then we acquired a field called North McElroy, which we think has a very good flood potential. And then we acquired a leasehold interest in some property that is adjacent to some of our most prolific areas of SACROC, that we think will also be a great CO2 flood opportunity.

John Mackay: Okay. Thanks for the time.

Operator: Thank you. Our next question is from Keith Stanley with Wolfe Research. You may go ahead.

Keith Stanley: Hi, good afternoon. Wanted to follow up — hi. I wanted to follow up on the SNG South System project. Can you just talk to the timeline for regulatory approval, start of construction? And is it all coming into service in late 2028 and/or phased over time? And then it — sorry for the multipart question, is it also fair to assume your customer here is your partner, Southern, on the project or is it a broader customer base supporting this project?

Sital Mody: Yeah. So, Keith, this is Sital. One, we had an open season. We do have a broad customer base in terms of regulatory timeline with an in-service of 2028. Clearly, we plan a project of this scale to pre-file and then and then do a [firm filing] (ph), probably without getting into too much detail, there is always competition sometime next summer with a targeted in-service date of late ’28. So that’s probably the 50,000 foot view on bottom line. Did I answer your question?

Keith Stanley: Yeah. And then just on — yes, yes, you did. Does it on — does the contribution come in all in the end of 2028 or has it phased in over time as you see it?

Sital Mody: So we have — we do have initial phase in ’28 and we do have some volumes trickling into year after.

Keith Stanley: Okay, great. Thank you. Second question. Wanted to touch back on the Texas loan program for gas-fired power plants. How can we think about the opportunity for Kinder here? So, say Texas builds 20 gigawatts of new gas-fired power plants over the next five years. What type of market share do you have in the Texas market today [in] (ph) connecting to power plants? What’s a typical sort of capital investment to do a plant tie-in? Just any sort of thoughts of what it could mean for opportunities for the intrastate system?

Sital Mody: So, if I had to take a snapshot and don’t quote me on this, probably today we’re about 40%, probably have a 40% share in Texas in terms of connecting and the cost to connect, I really think it’s going to vary depending on where the ultimate location is going to be. We do have some unique opportunities where it’s actually quite low in terms of — it’s very capital-efficient and there are some targeted opportunities that might involve a little bit more capital.

Kim Dang: It really gets to how — are they going to be located on our existing system or are we going to need to build a lateral and how far is — how long is that lateral going to need to be? And then are there going to be opportunities where it requires some expansion of like some mainline capacity? So that’s what Sital means. So it’s just going to depend with respect to how big the capital opportunity is.

Keith Stanley: Thank you.

Operator: Thank you. Our next question is from Jeremy Tonet with JPMorgan. You may go ahead.

Jeremy Tonet: Hi, good afternoon.

Kim Dang: Good afternoon.

Jeremy Tonet: Just wanted to pivot back to Double H conversion here and how the — did you say how the NGLs are getting out of Guernsey at this point on — with this project and I guess, are you working with any other midstreamers on this project overall?

Sital Mody: So, one, our goal is to get it to market, the market being Conway and Mont Belvieu. And I think when you think about it broadly, a couple of calls ago, we talked about the basin in general and our desire to get egress both on the residue side and this is an opportunity to get egress on the NGL side. We see the basin are growing quite significantly. The GORs are rising. And so without getting into the complicated structures here because we are in a very competitive situation, I’ll just leave it at this that we are able to get to both the Conway and the Mont Belvieu markets.

Kim Dang: Yeah. And I’d say the other thing, Jeremy, when Sital says the market is growing, we don’t expect some big growth in crude. He’s really talking about the NGLs and the gas because of the increase in GOR.

Sital Mody: That’s right.

Jeremy Tonet: Got it. Okay. And maybe just pivoting when talking about a highly competitive market as far as Permian natural gas egress is concerned. Just wondering any updated thoughts you could provide with regards to the potential for brownfield expansion, be it through GCX expanding or greenfield as well getting to a different market or even the potential to market a joint solution at the same time. Just wondering how you see this market evolving, given that 2026 Permian gas egress looks like a deja vu all over again.

Sital Mody: Yeah. Look, good question, and the question is your — unfortunately, I don’t have a different answer for you this time. We still aren’t prepared to sanction the GCX project, still in discussions with our customers on the broader Permian egress opportunity. We’ve been, as I said, pursuing opportunity. We don’t have anything firmed up. There is — it’s a competitive space. We are open to all sorts of structures on that front and are willing to consider what’s best for the basin.

Jeremy Tonet: Got it. Understood. I’ll leave it there. Thanks.

Operator: Thank you. Our next question is from Theresa Chen with Barclays. You may go ahead.

Theresa Chen: Hi, I wanted to follow-up on the Double H line of questions. Can you tell us how much capacity the pipe will be in once it converted to NGL service? And would you expect the line to be highly utilized right away in first quarter of 2026, or will there be potentially a multi-quarter or multi-year ramp in the commitments?

Sital Mody: So, in terms of capacity, this is all — this is going to depend on the hydraulic combinations of our suppliers and ultimately what market they take that to. So, I think the takeaway here is, we’ve got a firm commitment that will likely start day one. And then as we scale the project, it is scalable, both from the Bakken and from the Powder River, and really the ultimate capacity is going to depend on the customer.

Theresa Chen: Thank you.

Operator: Thank you. Our next question is from Spiro Dounis with Citi. You may go ahead.

Spiro Dounis: Thanks, operator. Afternoon, everybody. First question, maybe just to talk about capital spending longer term. Historically, you’ve talked about spending near the upper end of that sort of $1 billion to $2 billion range, but Rich and Kim, if I sort of combine your statements at the outset, it seems to suggest, like, there’s a pretty robust opportunity set ahead that maybe wasn’t contemplated when you sort of last gave us that update. So, I’m curious, as you think about these larger projects coming in, like SNG and then the broader power demand you referenced earlier, are you still sort of on track to be in that $2 billion zone long term?

Kim Dang: Yeah. I’d say we wouldn’t say $1 billion to $2 billion anymore. We would just say around $2 billion. And, around $2 billion could be $2 billion, it could be $2.3 billion. I mean, just in that general area is what I would say. When you think about something like an SNG, it’s got a 2028 in-service, and so that’s going to be capital that you’re spending, just call it rough math two years of construction. So, most of that capital will be in ’27 and ’28. And so, that’s filling out the outer years of potential CapEx. So, around $2 billion.

Spiro Dounis: Okay. So, it sounds like not a material departure from before. Got it. And then…

Kim Dang: And I’d say, look, I’d say on the stuff that Rich and I are talking about, as I said, the $5 billion project — I mean, the 5 Bcf a day projects that we’re pursuing, that’s stuff that we’re pursuing today, right? That’s not things that are in the backlog today. And so, part of my point on the — is — was, we continue to see great opportunity beyond SNG. SNG, the 1.2 Bcf a day is not included in the 5 Bcf a day of potential opportunity. So, I think projects like SNG continue to fill out that CapEx in the outer years and give us more confidence that we’ll be spending $2 billion for a number of years to come.

Spiro Dounis: Got it. Okay. That’s helpful color. And then switching gears a bit here, Kim, you talked about some of the sort of regulatory events that are sort of becoming tailwinds now, headwinds at first, and I know one other sort of macro factor that sort of got you last year or two was with interest rates that were on the rise. I guess as we look forward, I’m not sure what your view is, but it seems like we’re setting up for some rate cuts later this year. So, maybe, David, maybe you could just remind us, as we think about your floating rate exposure, what does that look like in 2025, and is this a potential tailwind for you?

Kim Dang: Yeah. And I’ll let — it is a potential tailwind because the forward curve today is — for 2025, is below what we’ve experienced in 2024 to date and what the balance of the year is. So, ’25 curve is below ’24, but I’ll let David give you an update on our floating rate exposure.

David Michels: Yeah. It could be — we’ll see if we actually get these rate cuts or not. Remember, we all expected a bunch of rate cuts in 2024 as well, but we didn’t get them. We do have a fair amount of floating rate debt exposure. We’ve intentionally brought it down a little bit because it’s been unfavorable to later on additional swaps in the last couple of years, and so our floating rate debt exposure has come down from about $7.5 billion to about $5.3 billion. Additionally, we’ve locked in a little bit of that $5.3 billion for 2025, similar to past practice to take advantage of some of the forward curve, the favorable interest rate forward curves that we’re seeing for next year. So, about 10% of that, I think, is locked in for 2025 at favorable rates. The rest of it gives us a good opportunity to take advantage of any short-term interest rate cuts that we see coming to the market.

Spiro Dounis: Great. I’ll leave it there. Thanks, everybody.

Operator: Thank you. Our next question is from Michael Blum with Wells Fargo. You may go ahead.

Michael Blum: Thanks. Good afternoon, everyone. So, I wanted to get back to the discussion on the data centers. It seems like the hyperscalers are much less price-sensitive, and they’re willing to pay higher PPAs to secure power. So, do you think that could translate into you earning higher returns than you’ve gotten historically on some of these potential gas pipeline projects, and is there any way to quantify that?

Kim Dang: I think that — I think we’re early in the game. I think that’s hard to judge at this point. I would say, again, their two priorities are going to be reliability and speed to market. And I think that’s what you’re seeing — that’s what you’re hearing from the power guys on the — when they’re getting the PPAs. So, I think we will get — I think we are confident that we’ll be able to meet our return hurdles on these projects, but exactly what we’re going to get on these projects at this point, I think it’s too early to say that. And, generally these things will be — there’ll be some competition. And so, I wouldn’t expect us to get outrageous returns by any stretch.

Michael Blum: Okay. That makes sense. Thanks for that. And then, just one more follow-up on Double H. I believe the capacity — the oil capacity of that pipe was, I think, 88 million barrels a day, so — 88,000 barrels a day. So, I’m just wondering, should we assume that the NGL capacity will be kind of similar?

Sital Mody: Well, I mean, it depends on the receiving delivery. Just think about it this way. I’ll just make it real simple. If you’re at the beginning of the pipe and at the end of the pipe, it could be. If you’re in the middle of the pipe and bringing in volumes, it could be more. I mean, it just depends. So…

Kim Dang: And then, you got to get it to market. And so…

Sital Mody: You got to get — that’s right.

Kim Dang: It depends on downstream as well. But yeah, I mean, I think for the Double H pipe itself, I mean, if you’re coming in at the origin and going out at the terminus, yeah, I mean, that’s fair. But as Sital points out there, maybe people coming in at various points, and then the downstream points are going to matter as well.

Michael Blum: Got it. Thank you.

Operator: Thank you. Our next question is from Tristan Richardson with Scotiabank. You may go ahead.

Tristan Richardson: Hi, good afternoon. Maybe just one more on the CO2 portfolio. Can you talk about sort of capital needs or opportunities with the new portfolio? Historically, you’ve spent $200 million to $300 million annually here and you noted that there are greater flood opportunities with the new assets. Curious kind of how this changes capital deployment in CO2? And then also in the context of — I think in the past, you’ve noted a 10-year development plan of around $900 million. Just curious sort of what the new portfolio kind of looks like going forward.

Anthony Ashley: Okay. Tristan, it’s Anthony. I think I wouldn’t expect a material change in the capital numbers — the annual capital numbers for CO2. We weren’t spending a lot on any of the divested assets. There are obviously opportunities that you mentioned with regards to the two new assets. I think the undeveloped acreage that we’re talking about, that will become part of our annual SACROC numbers. And then North McElroy, we think there’s excellent opportunity there, as Kim and Tom said. But we’ve got to do a pilot first. And so, we’ll be proving out that opportunity. And once we prove out that opportunity, I think we’ll have more to say on that.

Tristan Richardson: Thanks, Anthony. And then maybe just on refined products, it seems like the lower 48 maybe saw a later start to the summer driving season. But it also seems like perhaps volumes have picked up in late June and end of July. Can you talk about what you’re seeing this season and maybe what’s contributing to that 1% below your initial budget?

Anthony Ashley: Yeah. I would say gasoline overall is reasonably flat. We’ve actually seen a bit of a pickup in jet fuel, primarily on the West Coast, as you saw in the release. And then on renewable diesel, we’ve seen a decent pickup on renewable diesel. We’re still a decent bit below our total capacity on the renewable diesel hub capacity. And I think we did 48 a day in the third quarter — I’m sorry, in the second quarter. We’ve got 57 a day of capacity. As that additional refinery comes on later this year, I think that’ll continue to continue to pick up. But with respect to being just slightly below our budget, we had probably slightly higher gasoline numbers in there, but we’re reasonably flat with the prior year.

Kim Dang: Yeah, the other thing I’d say on the volumes is, the volumes are one component of the revenue, right, price is the other. And what we’ve generally seen out in California is that we’re moving longer haul barrels rather than some of the shorter haul. So, from an overall revenue standpoint, I think we’re in good shape on the refined products.

Tristan Richardson: Appreciate it, Kim. Thank you guys very much.

Operator: Thank you. Our next question is from Harry Mateer with Barclays. You may go ahead.

Harry Mateer: Hi. Good afternoon. So, first question for South System Expansion 4, how should we think about funding that given you have the JV opco structure [Songas] (ph)? And I guess specifically, how much of an opportunity is there for some non-recourse debt financing to be used at the [Songas] (ph) entity itself?

David Michels: Yeah, it’s a good question. I think we’re — it’s still early stages and we’re still evaluating all our options. Generally with these JV arrangements, we prefer to fund at the parent level because our cost of capital is attractive, but we are evaluating our different funding opportunities. I don’t — we’ve never really been big fans of project financing, puts a lot of pressure on the project and so forth, but we’re still evaluating the best course forward. Because of the build time, it’s going to take some amount of time to get the pipeline into service. So, there is likely just to be going to be a fair amount of equity contributions in order to fund that as opposed to at the entity level itself. But it’s something that we’re looking at actively.

Harry Mateer: Okay. Thank you. And then second in Energy Transition Ventures, I’m curious where and whether acquisition opportunities in RNG might fit right now when you’re looking at growth potential in that business.

Kim Dang: Yeah. I’ll say a couple of things on that and then Anthony can follow up. But look, I think that business has been harder to operate than we would have expected. And as a result of that, until we get our hands fully around the existing operations, we have sort of stood down, if you will, looking at any significant acquisition opportunities. And I think that once we have these plants operating on a more consistent basis, that we will — we can reevaluate that. But at this point in time, I think we’ve just — we’ve got to get those plants up and operating consistently. But we think we are on the path to do that and hopefully, that will be the case for the second half of this year.

Harry Mateer: Great. Thank you.

Operator: Thank you. Our next question is from Samir Quadir with Seaport Global Securities. You may go ahead.

Sunil Sibal: Yeah, hi, good afternoon. This is Sunil Sibal. So, starting off on the new projects that you announced, could you talk a little bit about the contractual construct behind those? What kind of contract durations you have supporting those two projects?

Kim Dang: Yeah. Generally on the South System 4, we’ve got 20-year take-or-pay contracts with creditworthy shippers. And then we also have a contract that is — that’s underpinning the Double H project. So, consistent with how we’ve done — how we do our other projects, I mean, we want to make sure that we’ve got good credit and good quality cash flow that are supporting a capital builds?

Sunil Sibal: Understood. Then on the full year expectations, I think you mentioned you’re tracking a little bit below budget as far as gathering volumes are concerned. Could you talk a little bit about which basins et cetera are tracking below what we were expecting at the start of the year?

Kim Dang: Yeah. I think just — I mean, what we’re assuming for the balance of the year is volumes that are relatively flat with the volumes the first half of this year. So, we’re not assuming a big ramp-up in volumes the second half of this year, pretty consistent with what we saw in the first half. And then in terms of the big — the three big basins where we are going to be South are going to be Eagle Ford, Haynesville, and Bakken. And so, we’ve seen a little bit of weakness, I think, in each of those, probably a little more in the Haynesville than in the others.

Sital Mody: Yes, I mean, you saw producers react to the pricing in the Haynesville, which is why we’ve had a little bit of a pullback. But it’s prudent.

Tom Martin: But we expect that to ramp up later this year and the next year as demand picks up.

Sital Mody: That’s right.

Sunil Sibal: Thank you.

Operator: Thank you. And at this time, we are showing no further questions.

Rich Kinder: All right. Thank you very much for listening and have a good evening.

Operator: Thank you. That does conclude today’s conference. Thank you all for participating. You may disconnect at this time.