Kinder Morgan Inc - Class P (KMI) — Q2 2023 Earnings Call Transcript

Thank you, Jordan. Before we begin, I'd like to remind you as we always do 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 and 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. The most important thing a Board of Directors does is to structure and implement orderly succession planning, and I'm proud of the job we've done at Kinder Morgan. In our 26-year history, we've only had two CEOs, and we'll welcome our third on August 1st. This will be Steve Kean’s last investment call as CEO, and I want to thank him for all his dedication and hard work in that position for the last eight years, and for his service to the company over the past two decades. He's been a fine leader of the organization with the ability to understand the big picture and still pay attention to the details, and I can assure you that's a unique combination. We're happy that Steve will stay on our Board, and I'm sure he will continue to contribute to our success in that role. As you all know, Kim Dang, our current President, will succeed Steve and Tom Martin, the long-term President of our Natural Gas segment, will replace Kim as President. Kim, Tom, and I will constitute the office of the Chair. We announced all this back in January and the transition has proceeded very smoothly. Kim joined Kinder Morgan in 2001 and Tom in 2003, so they both have long experience with the company and in the midstream energy business. They've both been outstanding contributors to our success, and I know they will be great leaders of the company in the coming months and years. In short, the Board and I are very comfortable that we will march forward without missing a beat. Now, as we make this change, it's important to again emphasize why we're bullish about the long-term future of Kinder Morgan. The single most important reason for optimism is the role natural gas will play in this country and around the world in the coming decades. We forecast US natural gas demand will grow by about 20 Bcf a day between 2023 and 2028 to about 121 Bcf a day, and that's a 20% increase. We expect 13.5 Bcf a day of that growth to come from LNG and Mexico exports with moderate growth in the power, residential, and commercial sectors. Almost all of that LNG and Mexico growth will occur in Texas and the Gulf Coast, where we have a superb and multifaceted pipeline system. That's why we believe that growth in demand combined with the strategic location of our network will drive expansion and extension opportunities for our network and significant bottom-line growth for years to come. And with that, for the last time, I'll turn it over to Steve.

Thank you, Rich. Thanks for the kind words. It's been an honor to work for you, for the Board, for our shareholders, and to work with this great management team that we have around the table. And I can only double down on what you said about Kim and Tom. They work extremely well together and with the rest of the management team, and this is going to be very good for the company. And so we had a good quarter and a solid year so far. We beat our budget for the second quarter, and although our outlook predicts slight underperformance on a full-year basis, that is all more than explained, by commodity prices coming in lower than our budget year-to-date and according to the forward curve for the balance of the year. Put another way, our business is performing better, and that is partially offsetting the lower commodity prices. We also continue to see a strong market from our business development standpoint. While our backlog is roughly even with the first quarter update at $3.75 billion, that's the net result of having placed about $450 million of projects in service during the quarter while adding roughly $500 million of new projects to the backlog. As we have noted many times, these projects are getting done at attractive returns well above our cost of capital. Notable among the projects brought into service was the first of our Wabash Valley RNG projects. Those projects were part of our Kinetrex acquisition from 2021. The first one went into service on June 27. The project was later than planned and a little more expensive, but still a nice return, and we expect the whole portfolio of Kinetrex projects to yield a very attractive return on our overall investment even with the delays we've experienced. I'll note also on our RNG business that we got a favorable outcome from the EPA. Those are four or five words that you don't often hear from an energy executive. Favorable outcome from the EPA on its June order establishing the renewable volume obligation for the next three years. That pushed D3 RINs, those are the RINs values that matter most to us, up over $3, and we held off on selling RINs until after that ruling came out. More significantly, our natural gas and terminals businesses are leading the way without performance versus plan. One other performance highlight to note, our CO2 business is beating plan on production. Jim and David will give you the percentages there, but we're actually up year-over-year. Now, that's more than offset by lower commodity prices, as I mentioned. But it's a significant accomplishment given the significant outage that we had at our SACROC, our largest field in the first quarter. That's very strong work by our EOR team. Other than that, the song remains the same. We're maintaining a strong balance sheet, originating new projects at attractive returns, and returning value to our shareholders through a well-covered dividend and opportunistic share repurchases. And now I'll turn it over to our President, soon to be CEO, Kim Dang.

All right. And let me say that I've enjoyed very much working with Steve for the last eight years. He has been selfless in his transition, and he has really helped put me in a position to do this role. And as Rich said, Tom and I are also very excited about the future of this company, and we're grateful for the opportunity to lead that. So with that, I'll start with the Natural Gas business unit as always. Here, our transport volumes increased by 5% versus the second quarter of last year. And that was driven by EPNG’s Line 2000 return to service. We also saw increased power demand, which was up 6%, increased LDC demand, which was up 6%, and increased industrial demand, which was up 5%. These increases were offset by reduced LNG volumes, and that was due to maintenance at several export facilities and decreased exports to Mexico. Natural gas gathering volumes were up 19% in the quarter compared to the second quarter of last year, driven by Haynesville volumes, which were up 29%, Bakken volumes up 26%, and Eagle Ford volumes up 21%. Sequentially, gathering volumes were up 7% with all three basins I just mentioned contributing to the increase. For the year, we expect gathering volumes to be up nicely about 16%, that's about 4% below our budget, driven by egress project delays and an asset sale. So largely what we're seeing is that we're not seeing much of a volume decline from our big producers. Where we're seeing some price sensitivity is on some of our smaller producers. And so that's why we still expect that we'll be up 16% for the year. As you can see from the volume increases that I just mentioned, despite a brief lull in new export LNG demand and lower prices in the quarter versus the second quarter of 2022, the natural gas markets continued to be robust. In our Product Pipeline segment, refined products were flat for the quarter versus the second quarter of last year. Road fuels were down about 2%. Our gasoline volumes were impacted by refinery maintenance during the quarter. Diesel volumes were down as renewable diesel volumes in California are currently being transported by other methods and pipelines and that's replaced some of the conventional diesel that previously moved on our pipe. However, the reduction in conventional diesel volumes doesn't really reflect the true economic picture as the RD volumes and projects we placed in service earlier this year are largely underpinned with take or pay contracts. So even though the volumes may not be moving on our pipeline yet, we get paid most of the revenue from those projects. Jet fuel volumes increased 9%. Crude and condensate volumes were up about 4%, and that was driven primarily by higher Bakken volumes. Sequential volumes were up about 8%, and that was primarily driven by the Eagle Ford. In terminals, our liquids lease capacity remained high at about 94%. Excluding the tanks out of service for required inspections, approximately 96% of our capacity is leased. Although we were down financially in the quarter, utilization at our key hubs Houston Ship Channel and the New York Harbor strengthened in the quarter. And we saw nice increases on our New York Harbor contract renewals that were negotiated during the quarter. Rates on our renewals in the Houston Ship Channel were slightly positive and our Jones Act tankers were 97% leased or 97% leased through 2024, assuming likely options are exercised. On the bulk side, overall volumes were flat, with increases in coal, fertilizer, and salt offset by the reduction in grain. The grain volumes have minimal impact on our financial results. And so excluding grain, both volumes were up 5.5%. And we also benefited financially from rate escalations. On the CO2 segment, lower prices on NGL and CO2 more than offset the increase in oil production. Overall oil production increased 7%, and that was driven by SACROC volumes where our projects have performed much better than we expected. And we've also seen strong volumes post the January outage. For the year, we still expect net oil volumes to exceed our plans, which helped offset some of the price weakness. With that, I'll turn it over to David.

Thank you, Kim. For the second quarter of 2023, we are announcing a dividend of $0.2825 per share, which annualizes to $1.13, reflecting a 2% increase compared to last year. I will share some highlights before discussing the quarterly performance. As of the end of the second quarter, our net debt to adjusted EBITDA ratio stood at 4.1 times, allowing us to maintain significant capacity under our leverage target of around 4.5 times. We also had nearly $500 million in cash at quarter-end with no amounts drawn from our $4 billion revolving credit facility. Additionally, we repurchased over $203 million worth of shares during the quarter, bringing our total share repurchases for the year to almost 20 million shares at an average price of $16.61, providing considerable value to our shareholders. Although we expect to slightly miss our budget for the full year, this can be largely attributed to lower-than-expected commodity prices. We have performed better than budgeted in both our Natural Gas and Terminals segments. In terms of quarterly performance, we recorded revenue of $3.5 billion, which is down $1.65 billion from the second quarter of 2022, but our cost of sales also decreased by $1.7 billion, primarily due to significant drops in commodity prices from last year. As you may recall, we engaged in offsetting purchase and sales positions within our Texas intrastate natural gas pipeline system that provided an effective take or pay transportation service. While this exposes our revenue and cost of sales to price fluctuations, it does not affect our margin from this activity. In fact, when netting revenue and offsetting cost of sales, our gross margin actually increased. Interest expenses were higher than in 2022 as anticipated, primarily due to the impact of short-term interest rates on our floating rate swaps. We generated net income of $586 million, reflecting an 8% decline compared to the second quarter of last year. Adjusted earnings were $540 million, a 13% decrease from the same quarter in ‘22. If we exclude the impacts of commodity prices and interest expenses, our performance would be better than last year's. Our share count reduced by 28 million, or 1%, this quarter relative to the same period last year due to our share repurchase activities. In our business segment performance, improvements in Natural Gas and Terminal segments, both of which increased, were partially counterbalanced by the performance of our Products and CO2 segments. In Natural Gas, improved sales margin from our Texas Intrastate system and favorable re-contracting rates at our Midcontinent Express Pipeline contributed significantly, along with returns from EPNG and higher value capacity sales on Stagecoach and our Tennessee Gas Pipeline. These gains were partially offset by negative re-contracting impacts on our South Texas assets. The Product Pipeline segment declined mainly due to adverse pricing effects on our transmix business and unfavorable re-contracting on our KMCC asset. Our Terminal segment's growth was driven by enhanced contributions from our Jones Act tanker business, project expansions, and rate escalations, although these gains were partially offset by reduced truck rack volumes and higher operating costs. Our CO2 segment experienced a decline due to reduced prices for CO2, NGL, and oil, although this was partially balanced by increased oil production volume. Our adjusted EBITDA for the quarter reached $1.8 billion, a 1% decrease from last year. DCF amounted to $1,076 million, down 9% from last year, with a DCF per share of $0.48, an 8% decline year-over-year. In these non-GAAP metrics, similar to our GAAP measures, we outperformed last year when excluding the effects of interest expenses and commodity price declines. On the balance sheet side, we concluded the second quarter with $30.8 billion in net debt and a net debt to adjusted EBITDA ratio of 4.1 times. As previously mentioned, our net debt saw a reduction of $139 million since the start of the year. To summarize, we generated cash flow from operations of $2.883 billion. We disbursed $1.265 billion in dividends, allocated $1.18 billion for capital growth, sustainability, and contributions to joint ventures, and conducted stock repurchases totaling $317 million by the end of the quarter, which provides a clear view of the year-to-date net debt change. Now, back to Steve.

Okay. We're going to take your questions now. And as usual, we have a good chunk of our management team around the table. We'll try to make sure that you hear from them as well. Jordan, if you would, please open up the line for questions.

Hi, good morning, everyone. My first question is just around the guidance. We've seen 1Q and 2Q come roughly in line with the original quarterly guidance outlined at the Analyst Day. But in your prepared remarks, you talked about how commodity headwinds have been really offset by base business outperformance. So kind of looking ahead to the second half, should we expect continued outperformance in kind of the natgas and terminal segment or could we see a recovery in products in the back half as well? Thanks.

Yeah, good question, Brian. I think part of the outperformance year to date has been our ability to take advantage of some of the volatility that we've experienced particularly in our natural gas assets. And we saw some outperformance there in our interest rate business, like I mentioned. Our storage is a bit full, which might limit our ability to take advantage of that going into the end of the year. But there might be some additional ability to take advantage of that if prices and storage capacity become more available.

Yeah. So go ahead.

And so we haven't assumed that same level of outperformance in the back half of the year as what we experienced in the first part of the year. And therefore, that's why we're saying that we will be slightly down versus planned; to the extent that we see some of that outperformance in the back half of the year, then that could improve the outlook that we've given you here today.

Great. I really appreciate that color. As a follow-up, just wanted to talk RIN pricing. It's been very volatile year-to-date based on the RVO outlook. So just curious if you could help sensitize perhaps the ability for Kinder to utilize its RINs on the balance sheet that were held on the first half and then monetize in the back half or second half ‘23? Thanks.

As I mentioned earlier, I'll let Anthony provide more details. We were aware that another round from the EPA was expected in June. Based on the comments, feedback, and data we received, we anticipated an increase in the renewable volume obligation, which indeed rose by about 30% for this year and the next two years, with a 33% increase this year. Instead of selling at $1.95, we decided to hold on and sold it at $2.90 and above.

I think we have taken advantage of the increase in pricing. One of the reasons for the low trading in the first half of the year was that many had a similar strategy as us, leading to a lack of liquidity in the market, which kept prices down. I believe the renewable volume obligations that were announced are very supportive for RIN pricing moving forward. We've already benefited from the increase regarding most of our inventory levels. However, we will be generating additional RINs for the rest of the year, and as far as we can see, there are no reasons for RIN prices to decline for the remainder of the year.

Great. Thanks. I'll leave it there.

Good afternoon. Steve, you mentioned the incremental $500 million was added to the backlog. Can you provide a bit more detail on the nature of those projects? And then safe to assume those are additive to mostly ‘24 and ’25. So the runway is extending a bit here.

Yeah. So I think we had some additions in our EOR business. We had some additions in our natural gas sector as well. I think those were the two primary contributors. David?

I think those are positioned further down the backlog compared to most of our projects, which is extending the overall backlog duration.

Got it. And maybe a question for Anthony on the landfill RNG development. I think we're tracking a bit slower than expected at the time of acquisition. Could you just update us on what some of those delays may be attributable to, whether it's permitting, supply chain, construction, just generally curious as to the build-out there?

We have experienced multi-month delays on the three RNG projects currently under construction this year. These delays have mainly been due to supply chain issues, weather conditions, and more recently, some commissioning challenges that have postponed the start of operations for certain facilities. The positive news is that our first facility, Twin Bridges, is now operational, and we have a clear path for the next two projects to start as well.

Great. Thank you.

Hi. I'd like to follow-up on the line of thought related to RNG and D3 RINs. Just looking beyond this year, I'd love to hear about your outlook for D3 RIN pricing over time that underlines the returns of these projects. And how do you take into account the supply of additional D3 RINs if and when an eRIN halfway eventually becomes available even if it's on pause for now?

That's a great question. We have forecasts for our D3 RINs and from an investment perspective, we adjust for potential low or worst-case scenarios to ensure we're satisfied with our expected returns. We also consider selling some of our products into the voluntary market, which operates on a fixed price basis, and we have specific price points for that. The recent RVO targets, which have been released for three consecutive years, are very encouraging as they suggest a 30% price increase each year, which compounds positively. Additionally, eRINs, although delayed, represent potential future demand growth for our projects. While we’re waiting for more clarity on eRIN implementation, we believe it will ultimately benefit our long-term pricing strategy once it is in effect.

Thank you. And in relation to your project backlog, so excluding CO2 and G&P, the remaining $2.6 billion in projects, can you talk about why the average EBITDA multiple is now 4.2 times versus 3.9 times previously, and what's driving that upward pressure and lower returns?

Sure, Theresa. The change there is just a mix of the backlog. What went in service during the quarter versus what we added in the quarter, what went in service were lower multiple, so stronger returning G&P type projects. And what came into the backlog mostly were very attractive returning projects, but at a little bit of a higher multiple, more in line with our longer-haul pipeline type opportunities. And so that was the biggest driver of it.

Thank you.

Thanks. Maybe I want to stay on this topic. I guess the decision to exclude the CO2 and G&P projects from the backlog multiples, I'm wondering if you could just expand on your thinking there and because you say that the cash flow streams are a little less predictable, does this change at all how you think about making those types of investments and anything around minimum hurdle rates to allocate capital there?

Yeah. No, Michael. It doesn't. So I think the reason to exclude those projects is because the other projects that we have on Natural Gas and Products and Terminals, they typically have a very consistent cash flow. And so people, a lot of the sell side like you are using the backlog and they're looking at the multiple and they're saying, okay, well that's the level of EBITDA I should assume from these projects. Well, as you know, when some of the CO2 projects come on or some of the G&P projects come on, they can come on at higher multiples but then they ultimately decline over time. And in many cases, that cash flow is replacing other cash flows which are declining. And so all we were trying to do is give people a better proxy for estimating what cash flow is incremental and stably recurring. It does not change the way that we think about CO2 or G&P projects. Those projects, they have more variability, and therefore we require a higher return on those projects. And so as you know, when we're doing CO2 projects, we're typically requiring 20% or higher returns, but we think those are very attractive returns, and we should do those projects. And G&P are typically in the high teens, and those are very attractive returns. And so we'll continue to do those. But we were just trying to help people in their modeling.

Okay. Got it. No. That makes sense. Thanks for that. I also wanted to ask about Midcontinent Express. You've had a really nice uptick there in the last couple of quarters and think you mentioned in the prepared remarks some favorable re-contracting on an MEP. So, you could just maybe just clarify just how sustainable this new kind of run rate is for MEP, and then, how much of the capacity is now contracted and the duration of contracts? Thanks.

Yeah, Michael. So when we take a step back and look at MEP, over the past couple of years, we've seen a lot of the Oklahoma Basin Drilling driving some of that basis. But as we move forward, really we see that basis strengthening now, as all the LNG facilities come on that Louisiana Gulf Coast corridor, as well as some of our Southeast markets competing for supply. So we do see that basis continuing to sustain if not grow. We've got incremental LNG facilities coming on in 2024. As you know, Golden Pass is first up. So nothing but support we think for the basis. We've been opportunistic in terms of how we're selling that capacity, trying to capture the highest margins. And so we'll continue to do so. Probably in the two to three-year tranche, we've been selling out the capacity, waiting for that spread to widen a little bit.

Got it. Thank you very much.

Hey, good evening guys. Just a question on the Midstream side. Obviously seeing very strong year-over-year growth rates across your three primary basins. Maybe you also mentioned in the prepared comments though that you are seeing at the margin maybe some smaller producers being a little bit more price sensitive. Maybe curious about regionally where you're seeing that most across the three basins in Midstream?

Sital?

Good question. In the Haynesville, some of our smaller producers have scaled back their drilling plans due to the current pricing environment. The larger producers there still expect LNG demand to pick up in the latter half of the year and anticipate potential volatility in Europe. We believe they will keep their rigs operational in the Bakken, where we've seen growth. In the Eagle Ford, we're actually exceeding our pre-COVID volumes, even with the current price situation. Overall, all systems are functioning well.

That's great. And then just a quick follow-up on the Gulf Coast storage expansion you guys announced, I think the Markham project. Can you maybe give some context around relative magnitude versus your overall storage portfolio? And then maybe just some of the logistics, are we assuming third-party contracts, or is this all considered perhaps new storage that would be available to new customers? Maybe just curious to touch on that one.

You're asking about our Markham expansion, which involves a 6 Bcf increase to our Markham facility. We're adding approximately 650,000 of additional withdrawal capacity, and our current plan is to offer this to our customer base. In fact, we have already sold most of it at rates significantly higher than what we initially set for the project, with returns even better than we expected. Did I address your question?

Yep. That's very helpful. Thank you guys.

Hi, thank you. The first question, kind of a random one, but how is the company thinking about gas marketing, which I think some of your peers are more active in? Is that a business that you could try to grow in to increase margin? It just seems like if your view is gas is going to be more volatile, you have a lot of storage and other physical asset positions. Is marketing something that's becoming more interesting given the direction that gas is going?

Yes, it is, but with an important note of caution there. We have done a fair amount of enhancement in our crude pipeline assets by picking up capacity that would otherwise not be utilized by third-party shippers and making use of it and attracting additional volumes to the system in order to recover additional tariffs. And so we've done very well with that. We are extending that a bit into the gas marketing arena. But very much sticking to our knitting there and doing it in a non-speculative and kind of legging into it gradually. But we do expect we'll be able to build on that as we go. There's another part of the business, which is larger than that right now, which is in our Texas Intrastate business where we buy and sell natural gas. As David pointed out in his comments about revenue versus cost of goods sold, that is often done with reference to the same Houston Ship Channel price, purchase at Houston Ship Channel minus sell it at Houston Ship Channel or Houston Ship Channel Plus and pull out a transport margin in between. But we have storage and we often find that we have excess storage that we can optimize and make money on it in the state of Texas. And we've done very well with that and that shows up in some of the optimization numbers that David was going through. So it's an activity that we're already in, in kind of a limited way in Texas, and we're looking to pick up additional and have picked up additional bits of capacity here and there around our system in order to expand on that business, but doing it in a very, I would say, very conservative and careful way.

Makes sense. Thanks. And second question on the buybacks. So you've got a lot year to date now. And the press release referenced $200 million of unbudgeted buybacks during Q2. Can you clarify what you mean by unbudgeted buybacks and then how you think about buyback capacity for the company over the balance of the year versus other priorities? Thanks.

The unbudgeted comment just meant that we didn't budget for those.

And we don't budget for share repurchase.

We do not set a budget for our share repurchase because we adopt an opportunistic strategy that relies on the share price. We generally avoid a programmatic approach to share buybacks, as we believe this is the best way to manage the program. In the future, we aim for a balanced strategy. We will utilize our balance sheet capacity for share repurchases when it makes sense and when the price is favorable. However, we want to ensure that this is done in a measured manner. We have put considerable effort into strengthening our balance sheet, which is now in a very solid position, and we want to maintain that while also seizing good share repurchase opportunities.

Thank you.

Yeah, good evening, guys. Just maybe a quick broad one first. Not surprising you all mentioned just healthier lower than budget commodity prices impacted results. I'm just wondering kind of a go forward now, have you reset or how you're thinking about sort of the remainder of the year and into ‘24, how much differently now just maybe in broad strokes.

The forecast we provided today includes gas prices and crude prices that align with the current forward curve. We have adjusted it for 2023, but we won't be discussing 2024 at this time as our budget process occurs later in the year.

Great answer. Lastly, it's not surprising that you mentioned in the release how the crude and condensate business was affected by the lower re-contracting rates. I'm looking at the Eagle Ford and wondering if you could discuss the expected rates in that basin going forward, particularly for the remainder of the year that will need to be re-contracted.

Dax Sanders?

We have rolled one contract recently. Over the past few years, we have addressed the original legacy contracts from 2013 and 2014, and it’s not surprising that the new rates are lower. Currently, at KMCC, we have around 84 to 85 units of capacity held by third parties, with about 75 held by our intercompany marketing affiliate mentioned by Steve. Of the 85 units, those will be rolling over the next couple of years. We expect these contracts have already transitioned from the high legacy rates from a decade ago. They will roll over, but we do not anticipate any significant changes like those we have experienced in the last couple of years.

Helpful. Thanks, Dax.

Hi. I think that you were just addressing crude in the last question, but I think I have sort of a similar question, which is that Eagle Ford volumes for gas were up year-on-year pretty materially. But it sounds like Eagle Ford contribution is down. I think that that's pretty much all because of the Copano roll-off. Is that right and has that fully rolled off now?

Yes, that's correct. 2023 was the final year of those roll-offs. Now, as we re-contract, we have already completed our re-contracting for the 2023 period. As we increase these volumes, our focus will be on enhancing our margins.

Okay. That makes sense. As a follow-up, many analysts are predicting that the gas differentials between Texas and Louisiana will widen since not all Permian gas can reach Louisiana LNG. Do you agree with this outlook and does it influence your strategy for the next Permian gas takeaway solution?

Well, one, we do see a need to get some infrastructure across to the Eastern Louisiana side. We are looking at some opportunities on our interstate networks to complement that or to accomplish that. As we look at the next Permian project, we are having discussions not only with Gulf Coast LNG facilities but also with the Louisiana facility. So all of that will be taken into context, but I do see a physical need to get across from the western side to the eastern side.

Great. Thanks. That's all for me.

Hi. Thanks for taking my question. I wanted to follow-up on LNG demand specifically in the Corpus Christi area. Now that we have the Rio Grande project sanctioned, do you see any incremental interest in expanding GCX given that there's more demand in the Corpus Christi area and the last two pipes have been built to the Houston area?

Yeah. So first congratulations to the NextDecade team on getting that project across to the FID. At the outset, it's good for the network, period. But yes, there is incremental interest not only in a Permian project but also you've noticed we've sanctioned our Freer to Sinton project. We've also got renewed interest in GCX, those conversations are happening. But as you know, we're in a very competitive environment, and returns are going to determine whether or not we proceed with the next project.

And the reference to NextDecade was separate and apart from GCX. We're not attributing that to particular. But I think the main update there is we had told you before that those discussions had gone cold, and they are now active again.

That's right.

And that's the change.

Got it. And then the second follow-up on the contract structure maybe for your Texas Intrastate network. We had pretty weak basis in the second quarter. I think it averaged about $0.60 between Waha and Henry Hub because of the heat. So do you have marketing contracts or short-term contracts? How are you able to increase your earnings off of that with a narrow basis there this quarter?

I want to clarify a couple of things. First, regarding what Steve mentioned about the Texas Intrastate business and the associated purchase and sales, we typically lock in these agreements for one to three years. This involves real supply and real demand at the other end, meaning it isn't as impacted by changing basis differentials. There is a market value for that transport spread, and due to the demand on the other end, it doesn't fluctuate as much as forward spreads. This pertains to the Texas Intrastate market. As for the spread between Waha and Houston, we have some capacity there that we've hedged for this year and into next, so we don't have significant exposure to the fluctuations in those basis differentials.

Okay, great. Thank you very much.

Hi. Good afternoon.

Good afternoon.

Steve, I wish you the best in your retirement. I want to start by asking about the leverage levels you've mentioned in previous calls, specifically around 4 or 5. Is that still the target you consider appropriate for Kinder over time? If so, what is your plan to reach that level considering current lower leverage? Will it involve more buybacks, acquisitions, or growth projects? Additionally, what kind of multiples are you observing on new growth projects in light of the recent changes you discussed regarding the backlog update?

Let me share a few thoughts on that. Firstly, we are comfortable with our leverage target of 4.5 times, considering the range and potential of our assets. We have assessed whether reducing this target makes sense, and we believe it doesn't. Being rated BBB is suitable for a company like ours, allowing us to secure the necessary debt at reasonable rates. Lowering our leverage significantly would be costly without substantial benefits to our cost of capital, so we are maintaining our target at 4.5 times for now. As David mentioned, we're currently operating at 4.1 times, which provides us with flexibility on our balance sheet. We don’t feel pressured to bridge the gap from 4.1 to 4.5. When attractive opportunities arise, we can utilize that capacity, but we won’t stretch just to fill it if suitable chances aren’t available. Our return targets remain unchanged as we have solid capabilities. Regarding the increase in backlog multiples, we typically aim for an unlevered after-tax project return of around 15%. This can sometimes mean entering projects with multiples of 7 or 8 times. Even if our current backlog isn't achieving those multiples, we will proceed with projects that meet our return criteria. We focus on whether a project offers a good return, rather than how it impacts our backlog multiple. We might consider projects with returns below 15% if they include long-term contracts, but we won’t drop to single-digit returns. Our approach is to actively seek projects that maximize our returns, and even if that shifts our backlog returns, we will still pursue those opportunities. Any follow-up questions? Oh, and I mentioned BBB, but I should clarify that we are satisfied with BBB.

Got it. That's very helpful there. And just one last one, if I could, regards to the CCS, we've seen some action recently in the industry projects continue to move forward and other items developing there. Just wondering, is there anything new to share from Kinder Morgan's perspective with regards to CCS potential?

We are actively engaged in carbon capture and storage initiatives, particularly with our existing project in West Texas. Our Red Cedar project, which we discussed in January, is making good progress. We're also in talks with several other parties in West Texas and are involved in discussions along the Gulf Coast. This includes aspects related to transportation and registration, as well as exploring potential transportation opportunities. These projects have long development cycles, and when it's the right time, we will provide updates on them. There is a significant amount of activity in this area, particularly following the Inflation Reduction Act.

And we're definitely looking at it and of course what we bring to the table is the expertise to move it and sequester it. And we've done that in West Texas and we can do that in the Gulf Coast if the opportunities are correct and the returns are correct.

Got it. Makes sense. I'll leave it there. Thank you.

Okay. Thank you, everybody. Have a good evening.