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. I would now like to turn the call over to Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin. 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 and 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 a 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. 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 U.S., ERCOT now predicts the state will need 152 GW of power generation by 2030. That's a 78% increase from 2023's peak power demand of about 85 GW. This new estimate is up from last year's estimate of 111 GW 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 0.5%. 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 predicted in today's Gas Daily could result in an additional 20GW-40GW just in the state of Texas. 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." End quote. As an example of how industry players see the world developing, S&P Global Insights, as quoted in Gas Daily, reports that U.S. utilities plan to add 133 new gas plants over the next several years. 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. With that, I'll turn it over to Kim. 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 4.1x debt to EBITDA, and we continue to return significant value to our shareholders. Today, our board approved a dividend of $28.75 per share, and we expect to end the year roughly on budget. Now, 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, Wood Mac 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 three and 10 of incremental gas demand associated with AI. Rich took you through the 20 BCF a day of natural, natural gas, power that Texas is contemplating subsidizing. I should have said 20 GW, as well as the U.S. projection of 133 new gas plants over the next several years. At Kinder Morgan, we're having commercial discussions on over five 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 that growth in natural gas between now and 2030 will be well in excess of the 20 BCF a day. Not included in the five 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 Four 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 Expansion Four 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 5.4x. 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. 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. With that, I'll turn it over to Tom to give you some details on our business performance for the quarter. 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, as 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. In 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. Currently, market rates remain well above our vessels' 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. All right, thanks, Tom. So a few items before we cover the quarterly performance. As Kim mentioned, we're declaring a dividend of $28.75 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'll 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 Fourth holiday period. 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 with 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 the 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 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. It's 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 4.1x 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've 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. Okay. And so now we'll open it up for questions. Sue, if you could come on, please. Thank you. At this time, if you would like to ask a question, please ensure that your phone is unmuted, press star one, and record your name clearly when prompted. If you would need to withdraw your request, you may press star two. Again, that is star one if you'd like to ask a question. Our first question is from Manav Gupta with UBS. You may go ahead. Thank you, guys. First quick question here. The backlog went up pretty much, I mean, in 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. Okay, sure. So, you know, 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 Four that we mentioned, and then it is also Double H is the other one, and it's our share of South System Four. And then with respect to the multiple, yes, it increased a little bit. As you know, 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, you know, 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 we have a threshold for that, and we have a pretty high threshold for our projects. And that threshold is well in excess of our cost of capital. And then we vary around that threshold, you know, what I'd say, marginally, depending on the risk of a project. And so, you know, if we have projects that we do that are connected to our existing infrastructure, you know, where it's not greenfield, tend to have a much higher multiple associated with it. You know, when we're having to loop a pipeline or something, those typically might have a little bit higher multiple, but they're still meeting our return thresholds. You know, I think these are very, despite the fact that the multiple on the backlog's going up a little bit because of these projects. These are still very, very attractive return projects. 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, you know, 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? Yeah, I'd say, you know, 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, you know, the two things are key from their perspective. One is reliability, and two is speed to market. And so, I think, natural gas, and Rich said this last quarter, you know, but given the reliability of natural gas, it is going to play, we believe, a key role, in supplying energy to these data centers. Thank you very much. I'll turn it over. Thank you. Our next question is from John Mackay with Goldman Sachs. You may go ahead. Hey, team, thanks for the time. Maybe we'll pick up a little bit on that last one, surprisingly. So you guys are talking about five BCF of power demand discussions right now. Would just be curious to hear a little bit from you on, you know, where you're seeing that geographically. You know, 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 a kind of more FERC jurisdiction kind of discussion, but both of those would be interesting. Thanks. Well, I think and Sital and Tom, you guys supplement here, but you know, this, the five BCF is overall power, so some of that's related to AI, and some of it's just related to coal replacements, you know, 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 you know, it is in almost all the markets we serve, we're seeing you know, some sort of increase in power demand. And maybe just on the kind of time to market in terms of how long it could take to bring those on? Yeah, time to market is gonna be, is very much dependent on where these are, are gonna be sited. And so, you know, it depends on is it a regulated market? Is it an unregulated market? So that's just gonna vary depending on the, the market location. Okay. Appreciate that. Just 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, you know, asset swap. There's a line in the release on maybe some divestitures in the natural 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. Okay. So, you know, on natural gas, I, I'm not sure. We did have a divestiture earlier in the year, which was a gathering asset, but that wasn't during this quarter. And so, that was just, you know, 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, you know, we had three or four fields, where, you know, there was limited opportunity for incremental CO2 floods. And, you know, that is our business, is, you know, injecting CO2 to produce more oil. You know, we sold those fields that had limited opportunity, and then we acquired a field called North McElroy, which we think has very good flood potential. We acquired a leasehold interest in some property that is adjacent to some of our most prolific areas at SACROC, you know, that we think will also be a great CO2 flood opportunity. Okay. Thanks for the time. Thank you. Our next question is from Keith Stanley with Wolfe Research. You may go ahead. Hi, good afternoon. Hi, Keith. Wanted to follow up. Hi. 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 sorry for the multi-part question. Is it also fair to assume your customer here is your partner, Southern, on, on the project, or is it a broader customer base supporting this project? So, Keith, this is Sital. One, we had an open season. We do have a broad customer base. You know, in terms of regulatory timeline, you know, with an in-service of 2028, you know, clearly we, you know, we plan a project of this scale to pre-file and then do a FERC filing, probably, you know, without getting into too much detail, you know, there is always competition sometime next summer with a targeted in-service date of late 2028. So that's probably the 50,000-foot view on timeline. Did I answer your question? Yeah. And then just on... Yes. Yes, you did. Oh, does it, does the contribution come in all in the end of 2028, or does it phase in over time as you see it? So we have, you know, initial phases in 2028, and we do have some volumes trickling into year after. 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 GW 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 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? So, you know, if I had to take a snapshot, and don't quote me on this, probably today we're about 40%, you know, probably have a 40% share in Texas. In terms of connecting and the cost to connect, I really think it's gonna vary depending on where the ultimate location is gonna be. We do have some unique opportunities where it's actually, you know, quite low in terms of it's very capital efficient, and there are some targeted opportunities that might involve a little bit more capital. It really gets to how, you know, are they gonna be located on our existing system, or are we gonna need to build a lateral, and how far is, you know, how, how long is that lateral gonna need to be? And then, you know, are there gonna be opportunities where it requires some expansion of, like, some mainline capacity? So that's what Sital means. You know, it's, it's just gonna depend, with respect to, you know, how big the capital opportunity is. Thank you. Thank you. Our next question is from Jeremy Tonet with JP Morgan. You may go ahead. Hi, good afternoon. Good afternoon. Just wanted to pivot back to the Double H conversion here, and how are the—did you say how the NGLs are getting out of Guernsey at this point, on you know, with this project? And I guess, you know, are you working with any other midstreamers on this project overall? ... Well, one, you know, our goal is to get it to market, market being Conway and Mont Belvieu. And, you know, I think when you think about it broadly, you know, a couple of calls ago, like, you know, we talked about the basin in general, and, you know, 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 growing quite significantly. You know, the GORs are rising, and so, you know, 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, you know, able to get to both the Conway and the Mont Belvieu markets. Yeah, and I'd say the other thing, Jeremy, when Sital says the market's 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. That's right. 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 a 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 déjà vu all over again. Yeah. Look, good question, and question du jour. You know, unfortunately, I don't have a different answer for you this time. You know, we still aren't prepared to sanction the GCX project, still in discussions with our customers on the broader Permian egress opportunity. You know, we've been, you know, 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. Got it. Understood. I'll leave it there. Thanks. Thank you. Our next question is from Theresa Chen with Barclays. You may go ahead. 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, you know, potentially a multi-quarter or multi-year ramp into commitments? So, you know, in terms of capacity, this is gonna depend on the hydraulic combinations of our suppliers and ultimately what market they take that to. So, you know, I think the takeaway here is, you know, 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 gonna depend on the customer. Thank you. Thank you. Our next question is from Spiro Dounis with Citi. You may go ahead. Thanks, operator. Afternoon, everybody. First question, maybe just to talk about capital spending longer term. You know, historically, you've talked about spending near the upper end of that sort of $1 billion-$2 billion range. For 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 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? Yeah, I'd say we wouldn't say one to two anymore. We would just say around two, and, you know, around two could be two, it could be 2.3. I mean, just in that general area is what I would say. You know, when you think about something like an SNG, you know, it's got a 2028 in service, and so that's gonna be capital that you're spending. You know, you just call it rough math, two years of construction. So most of that capital will be, you know, in 2027 and 2028. And so, you know, that's filling out the outer years of potential CapEx. So, around $2 billion. Okay. So it sounds like not a material departure from before. Got it. And then- I'd say, look, I'd say on the stuff that Rich and I are talking about, as I said, you know, the $5 billion project, I mean, the five BCF a day of, you know, 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, you know, part of my point on, you know, on the, you know, was we continue to see, you know, great opportunity beyond SNG. SNG, the 1.2 BCF a day, is not included in the five BCF a day of potential opportunity. So, you know, I think, you know, 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. Got it. Okay, that's, that's helpful color. And then switching gears a bit here, can we talk 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, was interest rates that were on the rise. You know, I guess as we look forward, you know, I'm not sure what, what your view is, but it seems like we're, we're setting up for some rate cuts later this year. So maybe, maybe, maybe you could just remind us, as we think about your floating rate exposure, what does that look like into 2025, and is this a potential tailwind for you? Yeah, and it is a potential tailwind, because the forward curve today is, you know, for 2025 is below, you know, what we've experienced in 2024 to date and what the balance of the year is. So 2025 curve is below 2024, but I'll let David give you an update on our floating rate exposure. Yeah. 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 layer 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 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. Great. I'll leave it there. Thanks, everybody. Thank you. Our next question is from Michael Blum with Wells Fargo. You may go ahead. Thanks. Good afternoon, everyone. So 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? You know, I think we're early in the game. I think that's hard to judge at this point. I would say again, you know, their two priorities are gonna be reliability and speed to market. And I think that's what you're seeing, you know, that's what you're hearing, from the power guys on the, you know, when they're getting the PPAs. So I think, you know, 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 gonna get on these projects at this point, I think, you know, it's too early to say that. And, you know, generally, you know, these things will be, there'll be some competition. I wouldn't expect us to get outrageous returns by any stretch. 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? Well, I mean, it depends on the receiving delivery. You know what? You know, 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- And then you got to get it to market. You got to get it to market. And so 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, you know, may be people coming in at various points, and then the downstream points are going to matter as well. Got it. Thank you. Thank you. Our next question is from Tristan Richardson with Scotiabank. You may go ahead. 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, you know, $200-$300 annually here, and, 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 ten-year development plan of around $900 million. Just curious sort of what the new portfolio kind of looks like going forward. Yeah, Tristan, it's Anthony. You know, 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 regard to the two new assets. You know, I think the undeveloped acreage that we're talking about, that will become part of our annual SACROC numbers. And then North McElroy, you know, 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. 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 into July. Can you talk about what you're seeing this season and maybe what's contributing to that 1% below your initial budget? Yeah, I would say, you know, gasoline overall is, you know, 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 mean, sorry, in the second quarter, we've got 57 a day of capacity. You know, as that additional refinery comes on later this year, I think that'll continue to pick up. But with respect to being just, you know, slightly below our budget, we had probably slightly higher gasoline numbers in there, but we're reasonably flat for the prior year, so. 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 hauls. So from, you know, from an overall revenue standpoint, I think we're, you know, we're in good shape on the refined products. I appreciate it, Kim. Thank you, guys, very much. Thank you. Our next question is from Harry Mateer with Barclays. You may go ahead. Hi, good afternoon. So first question, for South System Expansion Four, how should we think about funding that, given you have the JV OpCo structure at SNG? And I guess specifically, how much of an opportunity is there for some non-recourse debt financing to be used at the SNG entity itself? 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. It puts a lot of pressure on the project and so forth, but we're still evaluating the best course forward. You know, because of the build time, it's gonna take some amount of time to get the pipeline into service, so there likely 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. Okay, thank you. And then second, in Energy Transition Ventures, I'm curious where and whether acquisition opportunities in RNG, you know, might fit right now when you're looking at growth potential in that business. Yeah. I'll say a couple of things on that, and then Anthony can follow up. But, you know, 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, you know, we have sort of stood down, if you will, you know, looking at any significant acquisition opportunities. And, you know, I think that, you know, once we have these plants operating on a more consistent basis, that we can-- 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. We think we are on the path to do that, and hopefully, that will be the case for the second half of this year. Great. Thank you. Thank you. Our next question is from Sunil Sibal with Seaport Global Securities. You may go ahead. Yes, hi, good afternoon. This is Sunil Sibal. So starting off on the new projects that you announced, could you talk a little bit about contractual construct behind those? What kind of, you know, contract durations you have supporting those two projects? Yeah. Generally, on the South System Four, we've got, you know, 20-year take or pay contracts with creditworthy shippers. And then, you know, we also have a contract that is, that's underpinning the Double H project. So consistent with how we've done, you know, how we do our other projects, I mean, we wanna make sure that we've got good credit and good quality cash flow that are supporting capital builds. Understood. Then on the full year expectations, I think you mentioned you're tracking a little bit below budget as well as gathering volumes are concerned. Could you talk a little bit about, you know, which basins, et cetera, are tracking below what you were expecting in the start of the year? Yeah, I think, just so, you know, you know, 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, you know, in terms of, you know, the three big basins where we are gonna be, you know, so are gonna be Eagle Ford, Haynesville, and Bakken. And so, you know, 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. Yeah. I mean, you saw, you saw, you know, producers react to the pricing in the Haynesville, which is why we've had a little bit of a pullback, but, but it's proof. But we expect that to ramp- Right later this year and the next year as demand picks up. That's right. Thank you. Thank you. At this time, we are showing no further questions. All right. Thank you very much for listening, and have a good evening. Thank you. That does conclude today's conference. Thank you all for participating. You may disconnect at this time.