Kinder Morgan, Inc. (NYSE:KMI) Q2 2023 Earnings Call Transcript

Kinder Morgan, Inc. (NYSE:KMI) Q2 2023 Earnings Call Transcript July 19, 2023

Kinder Morgan, Inc. reports earnings inline with expectations. Reported EPS is $0.24 EPS, expectations were $0.24.

Operator: Welcome to the Quarterly Earnings Conference Call. Today’s call is being recorded. If you have any objections, you may disconnect at this time. All participants are in a listen-only mode until the question-and-answer session of today’s call. [Operator Instructions] I would now like to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. You may begin.

Rich Kinder: 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.

About 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 all of you 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 and demand, combined with a 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.

Steve Kean: 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, 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 during the quarter. 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.

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, and 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 facility 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 renewables 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 reduction in grain. The grain volumes have a 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 productions. 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.

David Michels: Okay. Thanks, Kim. All right. So for the second quarter of 2023, we’re declaring a dividend of $0.2825 per share which is $1.13 annualized, up 2% from last year. So I’ll start with a few highlights before getting into the quarterly performance. We ended the second quarter 2023 with a net debt to adjusted EBITDA of 4.1 times ratio, leaving us with a good amount of capacity under our leverage target of around 4.5 times. We also had almost $500 million of cash at the end of the quarter and nothing drawn on our $4 billion revolving credit facility. We also repurchased over $203 million worth of shares in the quarter, which brings our total share repurchases for the year to almost 20 million shares repurchased at an average price of $16.61, creating what we think is very good value for our shareholders.

While we are forecasting to be slightly below budget for full year, more than all of that can be explained by the lower than budgeted commodity prices. We’re seeing better than budgeted performance in both our Natural Gas and in our Terminals segments. As for the quarterly performance, we generated revenue of $3.5 billion, that is down $1.65 billion from the second quarter of 2022, but our cost of sales were also down, down $1.7 billion. These were both due to the large decline in commodity prices from last year. As you will recall, we entered into offsetting purchase and sales positions in our Texas intrastate natural gas pipeline system. Those arrangements resulted in an effective take or pay transportation service. And while that leaves us — leaves our revenue and our cost of sales exposed to price fluctuations, our margin from that activity is not impacted by price.

In fact, netting the revenue and the offsetting cost of sales impacts, gross margin grew. Interest expense was higher versus 2022 as expected, which is driven by the short-term interest rates impacting our floating rate swaps and we generated net income of $586 million, down 8% from the second quarter of last year. Adjusted earnings was $540 million, down 13% compared to the second quarter of ‘22. Excluding the impact from commodity prices and interest expense, we would have been favorable to last year’s performance. Our share count was down $28 million or 1% this quarter versus the second quarter of last year due to our share repurchase efforts. On to our business segment performance, improvements in our Natural Gas and Terminal segments, which were both up, were partially offset by performance on our Products and our CO2 segments.

In Natural Gas, the largest driver of the outperformance came from greater sales margin in our Texas Intrastate system and favorable rates on re-contracting at our Midcontinent Express Pipeline, as well as contributions from EPNG due to a pipeline returning to service, and higher value capacity sales on Stagecoach and our Tennessee Gas Pipeline. And those are partially offset by an unfavorable re-contracting impacts on our South Texas assets. The Product Pipeline segment was down mostly due to unfavorable pricing impacts, impacting our transmix business, and unfavorable re-contracting on our KMCC asset. Our Terminal segment was up mainly due to improved contributions from our Jones Act tanker business, expansion project contributions and rate escalations, which were all partially offset by lower truck rack volumes and some higher operating costs.

Our CO2 segment was down due to our CO2, NGL and oil prices partially offset by, as Steve and Kim both mentioned, higher oil production volume. Our adjusted EBITDA was $1.8 billion for the quarter, which was down 1% from last year. DCF was $1,076 million, down 9% from last year and our DCF per share was $0.48, down 8% from last year. On these non-GAAP measures, just like on our GAAP measures, excluding interest expense and commodity price headwinds, we were favorable to last year. Moving on to the balance sheet. We ended the second quarter with $30,800 million of net debt and a net debt to adjusted EBITDA of 4.1 times. As I mentioned, our net debt decreased $139 million since the beginning of the year. And I’ll provide a high-level reconciliation.

We generated cash flow from operations of $2.883 billion. We’ve paid out dividends of $1.265 billion. We’ve spent capital growth, sustaining and contributions to our joint ventures of $1.18 billion and we’ve made — we had head stock share repurchases through the end of the quarter of $317 million and that gets you pretty close to the reconciliation for the year-to-date net debt change. Back to Steve.

Steve Kean: 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.

Q&A Session

Operator: Thank you. We will now begin our question-and-answer session. [Operator Instructions] Our first question comes from Brian Reynolds with UBS. Your line is open.

Brian Reynolds: 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 you prepared remarks, you talked about how commodity headwinds have been really offset by base business outperformance. So kind of looking ahead to 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.

David Michels: 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 becomes more available.

Steve Kean: Yeah. So go ahead.

Kim Dang: 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.

Brian Reynolds: 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.

Steve Kean: Yeah. So as I mentioned and then I’ll let Anthony expand on it. We did — we knew that there was another round coming from the EPA in June. And we expected that based on all the comments and the feedback and the data that they were going to increase the renewable volume obligation, which they did on the order of 30% for each this year and the following two years, there was 33% this year, and last the next two years. And so anticipating that we’d see some positive news rather than selling at $1.95, we held on and sold it at $2.90 and above.

Anthony Ashley: I think we — as Kim said, we have taken advantage of the increase in pricing. I think part of the reason why, and I mentioned this a little bit I think on the first quarter call, why it was trading so low in the first half of the year is everybody had a similar strategy as we — there was really no liquidity in the market, which was holding prices down. I now think the RVOs that came out are very supportive for RINs pricing moving forward. As I said, we’ve taken advantage I think of the uptick already with regards to the majority of our inventory levels. But we’ll be obviously generating additional RINs for the remainder of the year and our anticipation is that — and as far as we can see, there’s no reason for RIN prices to diminish in the next — for the remainder of the year.

Brian Reynolds: Great. Thanks. I’ll leave it there.

Operator: Our next question comes from Colton Bean with TPH and Company. Your line is open.

Colton Bean: 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.

Steve Kean: 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?

David Michels: And I think those were — those are on the back — those are a little bit later in the backlog than most of our backlog. So it is adding some length to the backlog overall.

Colton Bean: Got it. And maybe a question for Anthony on the landfill RNG development. I think we’re tracking a bit slower than expected at 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?

Anthony Ashley: Yeah, sure. We have seen multi-month delays on the three RNG projects that we’ve been — that are in construction this year. Those have been primarily, I would say, supply chain, weather and then most recently we’ve had some commissioning issues, which have pushed back in service of some of the facilities. The good news is we do have our first facility in service, Twin Bridges, and think we have good line of sight for — in-service for the next two projects as well.

Colton Bean: Great. Thank you.

Operator: Our next question comes from Theresa Chen with Barclays. Your line is open.

Theresa Chen: 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 underlights 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?

Steve Kean: Yeah, good question. So I think we obviously have the forecast for our D3 RINs. We — when we’re looking at it from an investment standpoint, we do sensitize it down to where we feel like it’s sort of a low case or a worst case type of situation and to make sure that we’re satisfied with the types of returns we’re getting. We know we do assume in some cases that we sell also into transportation market some percentages to the transportation market — I’m sorry, the voluntary market, which is more of a fixed price environment. And we do have some price points that we use there as well. But I think, as I was saying earlier with the RVO targets that just came out and they came out for the first time for three consecutive of years, right?

So normally it’s just an annual process. And they — I think are very supportive for RINs prices moving forward with roughly a 30% increase for each consecutive year. So that compounds upon itself. And so I think that’s supportive. I think obviously you mentioned eRINs as well, which has been delayed or postponed. I think our long-term view on eRIN is that, that provides another avenue for demand growth for our projects, right? So that’s supportive as well for long term for pricing as well. We’ll have to see when that actually comes into play. It was postponed in June and that’s for, we think, probably good reasons around sort of the mechanics and logistics of how it will line, actually be implemented. But long term, I think it’s a good thing for us if it comes into play.

Theresa Chen: Thank you. And in relation to your project backlog, so excluding CO2 and G&P, the remaining $2.6 billion in project, 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?

David Michels: 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 a little bit — 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.

Theresa Chen: Thank you.

Operator: Our next question comes from Michael Blum with Well Fargo. Your line is open.

Michael Blum: 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 type of investments and anything around minimum hurdle rates to allocate capital there?

Kim Dang: 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 turns — 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.

Michael Blum: 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 is — how much of the capacity is now contracted and duration of contracts? Thanks.

Sital Mody: 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 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 — waiting for that spread to widen a little bit.

Michael Blum: Got it. Thank you very much.

Operator: Our next question comes from Tristan Richardson with Scotiabank. Your line is open.

Tristan Richardson: 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?

Rich Kinder: Sital?

Sital Mody: Yeah. So, good question. Across the three basins, really on the — at the — in the Haynesville, we have some of our smaller producers that given the current pricing environment that have kind of tapered off some of the drilling plans. Obviously, our big producers or larger producers there I think you know who they are. But I mean those guys still anticipate the LNG demand coming on at the back half of the year as well as Europe’s potential volatility that may arise. Our sense is they’re going to continue to keep these rigs up in the Bakken. We’ve continued to see growth in the Bakken. And then in the Eagle Ford, here’s a data point for you, we’re ahead of our volumes pre-COVID, even in this price environment. So all those systems are pretty well, all systems go.

Tristan Richardson: 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.

Steve Kean: Yeah. So that basically — you’re referring to our Markham expansion, that’s a 6 Bcf incremental expansion to our Markham facility. We’re adding about 650,000 of incremental withdrawal capacity. And at this point, our plan is to offer it up to our customer base. In fact, we sold most of it at rates really higher than we sanctioned the project with several returns or even better than we anticipated. Did I answer your question there?

Tristan Richardson: Yep. That’s very helpful. Thank you guys.

Operator: Our next question comes from Keith Stanley with Wolfe Research. Your line is open.

Keith Stanley: 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?

Steve Kean: 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.

Keith Stanley: 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.

David Michels: The unbudgeted comment just meant that we didn’t budget for those.

Kim Dang: And we don’t budget for share repurchase.

David Michels: And we don’t budget for our share repurchase because we take an opportunistic approach. It’s share price dependent. We don’t take a program — in general, we don’t take a programmatic approach to share repurchases. We think that’s the right way to run this program. Going forward, what we’d like to do is take a balanced approach. We do — we will use balance sheet capacity for share repurchases if it makes sense, if the price makes sense for us to repurchase, but we want to do so in a way that’s measured. We’ve worked really hard to improve our balance sheet. We’ve got it in a really good spot and we don’t do anything to damage that, but we also want to take advantage of good share repurchase opportunities.

Keith Stanley: Thank you.

Operator: Our next question comes from Neal Dingmann with Truist Securities. Your line is open.

Neal Dingmann: 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.

Kim Dang: So yes, so the forecast that we gave you today has the gas prices and the crude prices at the — roughly the current forward curve. So, yes, we’ve reset it for 2023. And in 2024, we don’t really get into that. So we do our budget process later in the year.

Neal Dingmann: Okay. Great answer. And then just lastly, again, also not surprising you all mentioned just in the release how the crude and condensate business was impacted by the lower re-contracting rates, certainly just looking — what I was looking in within the Eagle Ford, and I’m just wondering, could you speak to degree of rates also in the same basin going forward, again, maybe the remainder of the year that will be — need to be re-contracted there?

Rich Kinder: Dax Sanders?

Dax Sanders: Yeah, so we did — we rolled one contract there. There’s still a — we’ve gone through over the last couple of years the original legacy contracts from back in 2013, 2014 and not surprising the rates that they’re rolling at are lower than that. Right now, on KMCC, we’ve got about 84 a day, 85 a day of capacity held by third parties. We’ve got about 75 held by our intercompany marketing affiliate that Steve spoke about. Of that 85, that rolls over the next kind of call it two to three years. And we would expect, I mean, those contracts have largely already rolled from the high legacy rates of 10 years ago. So they’ll roll, but we wouldn’t expect that there would be any massive changes like you’ve seen with the past couple of years.

Neal Dingmann: Helpful. Thanks, Dax.

Operator: Our next question comes from Jean Ann Salisbury with Bernstein. Your line is open.

Jean Ann Salisbury: 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?

Dax Sanders: Jean, yes, that’s right. 2023 was the last year of those roll-offs. And so now we should see — as we re-contract — we’ve already done our re-contracting through the 2023 period. And so as we increase these volumes now, we’re just going to focus on increasing our margins.

Jean Ann Salisbury: Okay. That makes sense. And then as a follow-up, a lot of people are forecasting — are forecasting a widening of Texas and Louisiana gas differentials as not all Permian gas is able to get to Louisiana LNG. Do you agree with this and does it change how you’re thinking about your next Permian gas takeaway solution offering?

Dax Sanders: 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.

Jean Ann Salisbury: Great. Thanks. That’s all for me.

Operator: Our next question comes from Neel Mitra with Bank of America. Your line is open.

Neel Mitra: 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?

Sital Mody: Yeah. So first congratulations to 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.

Steve Kean: So, 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.

Sital Mody: That’s right.

Steve Kean: And that’s the change.

Neel Mitra: 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?

Kim Dang: So I just want to clarify a couple of things. First, the — what Steve was talking about on Texas Intrastate business and the purchase and sales there. Typically, we’re locking in those purchase and sales over a year or two years or three years. And so, and it’s real supply and it’s real demand on the other end. And so it’s not as affected by changing basis differentials. There is a market for what that transport spread is worth. And because there’s demand on the other end, it doesn’t necessarily move as much as the forward spreads move all the time. So that’s with respect to the Texas Intrastate market. With respect to the spread between Waha and Houston, we do have a little bit of capacity between Waha and Houston. We’ve hedged that capacity for this year and into next. And so we don’t have much exposure there to what’s happening, good or bad with those basis differentials.

Neel Mitra: Okay, great. Thank you very much.

Operator: Our next question comes from Jeremy Tonet with JPMorgan. Your line is open.

Jeremy Tonet: Hi. Good afternoon.

Rich Kinder: Good afternoon.

Jeremy Tonet: Steve, wish you the best of luck in retirement here. Just want to start off, I guess, in the past, I think, calls you talked about, you know, 4, 5 as kind of a leverage level that the company thought about. And just wondering, is that still the level that you guys are kind of seeing as appropriate for Kinder over time here? And if it is, what’s the path to getting there given that leverage sits lower right now? Would it be more buybacks? Would it be acquisitions? Or would it be growth projects and just wondering what type of multiples are you seeing on new growth projects given that this — was a little bit of shift as you guys talked about with the backlog update?

Kim Dang: Okay. Let me make a couple of points on that. Okay. Well, first one is we are very comfortable with the 4.5 times leverage target given the breadth and the scope of our assets. And we have looked at whether it makes sense to bring that down and we don’t think it does. We think that where we are rated, BBB plus is a good place for a company like ours and our ability to raise the debt that we need at reasonable rates and that it would cost a lot of money to take our leverage much lower and there’s not much benefit in our cost of capital. And so we’re leaving our leverage target at 4.5 times right now. As David told you, we’re running that 4.1 times, it’s not burning a hole in our pocket, right? I mean, so we like having some flexibility on our balance sheet.

And so we don’t feel some type of pressure to go from 4.1 to 4.5. When we see nice opportunities, we have flexibility there because we have that capacity. But if we don’t see opportunities, we’re not going to stretch for anything to use that leverage capacity. So we’re not changing any of our return targets because we have average capability. And with respect to the multiple going up on the backlog, what I would say about that is we target on average 15% unlevered after-tax project. That can be — I mean that can in some cases result in a going in multiple of 7 times or 8 times. And just because our existing backlog is less than a 7 times or 8 times multiple, we’re still going to do that project. It’s a 15% unlevered after-tax return. So we’re going to do it even though it might increase the multiple on our backlog.

So we’re not — as we look at projects, we’re not saying, oh, what happens to our backlog multiple, that determines whether we do the project? No. Is it a good return project? We will go lower than 15% unlevered tax return for a project with long term contracts. But we don’t — we’re not going to drop into single digits. So that’s how we think about it. Think about it more, we’re doing — we’re out there, we’re looking for projects we’re trying to earn the maximum return that we can. We have a return threshold and even though that might cause our backlog return to change, we’ll still do that project. And, follow-up question? Oh, sorry. I said BBB plus, I should have said we’re happy with BBB. Sorry.

Jeremy Tonet: 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.

Kim Dang: CCS?

Jeremy Tonet: Carbon capture. Yeah.

Steve Kean: Good. Sorry. What was the question? [indiscernible]

Jeremy Tonet: Just there’s been some actions out there in the CCS industry projects, bigger projects moving forward in the Midwest and and other actions out there in the industry at large and just wondering if there’s any updated thoughts from Kinder Morgan with regards to potential CCS efforts?

Anthony Ashley: Yeah. We continue to be very busy on the CCS front, I would say both around our existing structure that we have in West Texas. We talked about our Red Cedar project in January, that continues to progress well. We’re talking to a number of other folks in West Texas as well. And then we’re very active kind of in conversations in the Gulf Coast as well. I’d say, both from sort of the transportation and the registration side of things as well as just pure potential transportation and opportunities. And so these are long development cycle opportunities and I think once — when it’s appropriate for us to talk to you guys about that, we’ll talk about those projects, but there’s a lot of activity especially post IRA in that world.

Rich Kinder: 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.

Jeremy Tonet: Got it. Makes sense. I’ll leave it there. Thank you.

Operator: There are no further questions in the queue.

Rich Kinder: Okay. Thank you, everybody. Have a good evening.

Operator: Thank you for your participation in today’s conference. You may disconnect at this time.