Kinder Morgan Inc - Class P (KMI) — Q2 2024 Earnings Call Transcript

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 that 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, with 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 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.

Thank you, Rich. I'll share some key points before handing it over to Tom and David for more details. We had a strong quarter, with adjusted EPS rising by 4% and EBITDA increasing by 3%, driven by growth in our natural gas segment and our refined products business segments. We ended the quarter with a debt-to-EBITDA ratio of 4.1 times and continued to deliver substantial value to our shareholders. Our Board has approved a dividend of $0.2875 per share, and we expect to finish the year approximately on budget. Now, let’s discuss natural gas for a moment. The long-term outlook for natural gas has improved this year, particularly due to the increasing demand from power generation and data centers. WoodMac anticipates gas demand will grow by 20 Bcf between now and 2030, with LNG exports expected to more than double and exports to Mexico increasing by nearly 50%. However, they predict a decrease in power demand by 3.9 Bcf a day. In contrast to those projections, we believe that power-related growth in gas demand—driven by factors such as AI, data centers, coal conversions, and new capacity to support reserve margins and renewables—will be significant. Starting with data center demand, utility IRPs and press releases from 2023 reflect an additional demand of 3.9 Bcf a day, which we believe will rise as more utilities update their plans. Currently, we are examining 1.6 Bcf a day of potential opportunities. Most estimates suggest an incremental gas demand associated with AI could range from 3 to 10 Bcf a day. Rich mentioned Texas's consideration of 20 gigawatts of natural gas power, and the US is projected to approve 133 new gas plants in the coming years. At Kinder Morgan, we are pursuing commercial discussions for over 5 Bcf a day of power demand opportunities, which includes the 1.6 Bcf related to data centers. Although not all these projects will materialize, they demonstrate the level of activity we are encountering and bolster our belief that natural gas growth between now and 2030 will significantly exceed the projected 20 Bcf a day. Also worth noting is the capacity signed by SNG for its successful open season related to the proposed South System 4 Expansion, a project that aims to increase capacity by 1.2 Bcf a day for about $3 billion. Once completed, this project will cater to growing power and local distribution company demand in Southeastern markets. As a result, our backlog rose by $1.9 billion to $5.2 billion this quarter. We have previously indicated confidence that the demand for natural gas would help us expand our backlog, and the South System 4 project exemplifies this. We see ample opportunities beyond this project for backlog growth, with the current multiple standing at about 5.4 times. During the quarter, we also received favorable rulings from the Supreme Court regarding the Good Neighbor Plan, which has been stayed as we are likely to prevail on the merits. While there are still many developments to come, I believe the current form of the Good Neighbor Plan will not be implemented, and it may take several years for a new plan to be developed and enforced. Additionally, we have a presidential election ahead of us. The recent overturning of the Chevron doctrine, which previously favored regulatory agencies when laws were ambiguous, is also a positive outcome. Collectively, these decisions will help reduce the regulatory challenges we’ve faced in recent years. Now, I'll hand it over to Tom to provide 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 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 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 $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. 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 a 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. 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 contributions to our joint ventures. 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.

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

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.

The backlog increased by $1.9 billion, driven primarily by two projects: South System 4 and Double H, which includes our share of South System 4. The multiple has increased slightly, which we mention to give an indication of the returns on these projects for modeling EBITDA. It's important to clarify that we do not target a specific multiple for the backlog; our focus is on the internal rate of return, which must significantly exceed our cost of capital. We may adjust around this threshold slightly based on project risk. Projects linked to our existing infrastructure typically have a higher multiple, whereas those requiring new pipelines might show a bit higher multiple, but they still adhere to our return criteria. Despite the rise in the backlog multiple due to these projects, they remain very attractive in terms of returns.

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?

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 feeding 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.

Thank you very much. I'll turn it over.

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.

Okay. I think Sital and Tom can add to this, but the 5 Bcf refers to overall power demand, which includes factors related to AI as well as coal replacements, enhancing reserve margins, and supporting renewables. We are observing this trend across various regions, including Texas, Arkansas, Kentucky, and Georgia, as well as in the deserts of Arizona and the Southwest. Essentially, we see an increase in power demand in almost all the markets we operate in.

Could you provide insights on the time it may take to bring this to market?

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.

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.

On natural gas, we had a divestiture earlier this year involving a gathering asset, but that wasn't related to this quarter. The asset was not essential to our portfolio, and when someone approached us with an offer that made sense, we decided to sell it. Regarding the CO2 sale, we had several fields with limited potential for additional CO2 floods, which is central to our business of injecting CO2 to enhance oil production. Therefore, we sold those fields. We also acquired a field named North McElroy, which we believe has strong flooding potential. Additionally, we obtained a leasehold interest in property next to some of our most productive areas at SACROC, which we expect to provide excellent CO2 flood opportunities.

Okay. Thanks for the time.

Hi, good afternoon. I wanted to follow up on the SNG South System project. Can you discuss the timeline for regulatory approval and the start of construction? Is everything expected to come into service in late 2028 or will it be phased over time? Also, is it correct to assume that your partner Southern is the customer for this project, or is there a wider customer base involved?

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 do a firm filing, 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?

Does the contribution come all at the end of 2028, or is it phased in over time as you see it?

We do have an initial phase in 2028 and some volumes will start to come in the following year.

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 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?

If I had to give a rough estimate, I would say that we currently hold about a 40% share in Texas regarding connections and connection costs. This is likely to change based on the specific locations. We have some unique opportunities that are quite capital-efficient, but there are also specific cases that may require additional capital investment.

It really gets to how they will be located on our existing system or if we will need to build a lateral, and how long that lateral will need to be. Additionally, are there going to be opportunities that require some expansion of mainline capacity? So that's what Sital means. It will depend on the size of the capital opportunity.

Thank you.

Hi, good afternoon.

Good afternoon.

I wanted to go back to the Double H conversion and ask how the NGLs are currently being transported out of Guernsey with this project. Are you collaborating with any other midstream companies on this project overall?

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 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.

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.

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.

Yeah. That's a good question, but unfortunately, I don't have a different answer for you this time. We are still not ready to move forward with the GCX project and are continuing discussions with our customers about the larger Permian egress opportunity. As I mentioned, we are actively pursuing opportunities, but nothing has been finalized yet. It's a competitive environment, and we are open to various structures that could work best for the basin.

Got it. Understood. I'll leave it there. Thanks.

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 the first quarter of 2026, or will there be potentially a multi-quarter or multi-year ramp in the commitments?

In terms of capacity, this will depend on the hydraulic combinations of our suppliers and the market they target. The key takeaway is that we have a solid commitment that is likely to begin from day one. As we expand the project, it is scalable from the Bakken and Powder River, and the ultimate capacity will rely on the customer.

Thank you.

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?

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, or 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.

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

I want to emphasize that the projects Rich and I are discussing, particularly the $5 billion initiatives and the 5 Bcf a day projects we are currently pursuing, are active opportunities, not items sitting in our backlog. My main point is that we continue to see substantial opportunities beyond SNG. The 1.2 Bcf a day for SNG is not part of the 5 Bcf a day potential. I believe projects like SNG will contribute to our capital expenditures in the coming years and reinforce our confidence in spending around $2 billion annually for several years ahead.

Got it. 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?

Yes, it is a potential advantage because the forward curve for 2025 is currently lower than what we have experienced in 2024 up to now and what we anticipate for the remainder of the year. The 2025 curve is below that of 2024, but I will let David provide an update on our floating rate exposure.

It remains to be seen if we will actually see these rate cuts. Remember, we anticipated several rate cuts in 2024, but they did not materialize. We have reduced our floating rate debt exposure somewhat due to unfavorable conditions for additional swaps over the past couple of years, bringing it down from about $7.5 billion to approximately $5.3 billion. Furthermore, we have locked in a portion of that $5.3 billion for 2025, in line with our previous practices, to benefit from the favorable interest rate forward curves we are observing for next year. Around 10% of that amount is secured for 2025 at advantageous rates. The remaining debt allows us to capitalize on any forthcoming short-term interest rate cuts in the market.

Great. I'll leave it there. Thanks, everybody.

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?

I believe we are still in the early stages, and it's difficult to assess at this moment. The key priorities will be reliability and speed to market, which is what we're hearing from the power companies regarding their power purchase agreements. We are confident we will meet our return expectations on these projects, but it's too soon to specify the exact returns we will achieve. Generally, there will be some competition, so I wouldn't anticipate extremely high returns.

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

Well, I mean, it depends on the receiving delivery. Just think about it this way. I'll just make it really 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. And so...

You have to get it to market.

Got it. Thank you.

Hi, good afternoon. Can you discuss the capital needs or opportunities related to the new CO2 portfolio? Historically, you've allocated $200 million to $300 million annually, and you've mentioned that the new assets present greater opportunities. I'm interested in how this affects capital deployment for CO2. Additionally, you've previously outlined a 10-year development plan of approximately $900 million. I'm curious about how the new portfolio will shape future plans.

Okay, Tristan, it's Anthony. I don't expect a significant change in the annual capital numbers for CO2. We weren't investing heavily in the divested assets. There are opportunities related to the two new assets you mentioned. The undeveloped acreage we are discussing will be included in our annual SACROC numbers. We believe there is great potential at North McElroy, as Kim and Tom indicated. However, we need to conduct a pilot first to validate that opportunity. Once we do that, I think we will have more information to share.

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?

Gasoline sales have remained relatively stable overall. We've noticed a slight increase in jet fuel, especially on the West Coast, as highlighted in the release. Renewable diesel has also shown a good increase, although we're still operating below our total hub capacity for renewable diesel. In the second quarter, we processed 48 barrels a day against our capacity of 57. As we bring an additional refinery online later this year, I expect further growth in this area. Regarding our performance being slightly below budget, we likely overestimated our gasoline projections, but our numbers are mostly in line with last year.

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.

Appreciate it, Kim. Thank you guys very much.

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? And I guess specifically, how much of an opportunity is there for some non-recourse debt financing to be used at the opco entity itself?

It's a good question. We are still in the early stages and assessing all our options. Typically, with these joint venture arrangements, we prefer to fund at the parent level because our cost of capital is favorable, but we are exploring various funding opportunities. We have not been particularly keen on project financing because it can create significant pressure on the project; however, we continue to evaluate the best path forward. Due to the pipeline build time, it will take time to get it into service, which will likely require substantial equity contributions for funding instead of relying solely on the entity level. This is something we are actively considering.

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.

I want to share a few thoughts on that before Anthony adds his insights. Operating the business has proven to be more challenging than we anticipated. Consequently, until we fully understand our current operations, we have decided to pause any significant acquisition opportunities. Once we get our plants running consistently, we can reassess our position. Right now, our priority is to ensure those plants are operating smoothly, and we believe we are on track to achieve this, ideally in the second half of this year.

Great. Thank you.

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?

Generally on the South System 4, we have 20-year take-or-pay contracts with reliable shippers. Additionally, we have a contract that supports the Double H project. As with our other projects, we aim to ensure that we have strong credit and quality cash flow backing our capital investments.

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?

I think what we're anticipating for the remainder of the year is that volumes will remain relatively flat compared to the first half of this year. We're not expecting a significant increase in volumes during the second half, which aligns with what we experienced in the first half. As for the major basins where we expect to see declines, they will be Eagle Ford, Haynesville, and Bakken. We have observed some weakness in each of these, particularly in the Haynesville.

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.

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

That's right.

Thank you.

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