Kinder Morgan, Inc. (NYSE:KMI) Q3 2023 Earnings Call Transcript

Kinder Morgan, Inc. (NYSE:KMI) Q3 2023 Earnings Call Transcript October 18, 2023

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

Operator: Good afternoon and thank you for standing by, and welcome to the Quarterly Earnings Conference Call. [Operator Instructions] Today’s conference is being recorded. If you have any objections, you may disconnect at this time. It is now my pleasure to turn the conference over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.

Rich Kinder: Okay. Thank you, Michelle. And before we begin, I’d like to remind you as usual that KMI’s earnings released 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.

Aerial view of an oil and gas pipeline, spanning vast landscapes.

My remarks at the beginning of our second quarter investor call, I talked about future demand for natural gas and why that makes us bullish about the future of KMI. The biggest portion of that growth in demand is attributable to LNG. So let me follow up on this call by reviewing the latest estimates regarding future U.S. feedgas demand to serve the country’s LNG export facilities. S&P Global Commodity Insights estimates LNG feedgas demand at 13.1 Bcf a day for 2023 and projects that it will grow to 24.7 Bcf a day in 2028 and to 27.5 Bcf a day in 2023, IEA estimates that U.S. LNG exports, as a share of global LNG supply will grow from 20% in 2022 to almost 30% in 2026. All of these numbers demonstrate incredible growth, which is driven, of course, by new LNG export facilities could have been FID, most of which are currently under construction.

Now how does this increased demand affect the Midstream Energy segment and specifically Kinder-Morgan? To meet this increased feedgas demand, the country is going to need additional pipelines and not just header pipelines to the export terminals, but also significant expansion in the pipeline and infrastructure upstream from those header systems and terminals. While we believe Haynesville production will grow the supply portion of this demand, because of its proximity to the LNG facilities in Louisiana and Southeast Texas, we will not be able to fulfill all these growth volumes and additional takeaway capacity from multiple basins will be required. Access to basins is also important to help solve the excess nitrogen problem confirming LNG export facilities.

While there are other midstream players will also benefit, we think Kinder Morgan, which is currently transporting a little less than half of all U.S. LNG feedgas is in an excellent position to take advantage of this tremendous opportunity because of the extensive footprint of our pipeline network, particularly in Texas and Louisiana where so much of the additional demand will occur. And with that, I’ll turn it over to Kim and the team.

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Q&A Session

Kim Dang: Okay. Thanks, Rich. I’ll make a few overall points, and then I’m going to turn it over to Tom and David to give you more details. We had a solid quarter financially. We continue to find opportunities to add to our backlog. We repurchased $73 million in shares at an average price of $16.77. That brings us to $472 million of share repurchases year-to-date at a very attractive price of $16.58. Financially, our portfolio of assets performed well with contributions from the segments up 5%, driven by increases in natural gas, products and terminals. Products had a particularly strong quarter, up 22%. Overall, our results were largely flat because of increased interest expense and sustaining CapEx, which we anticipated in our budget.

For the year versus our budget, our expectations remain the same as what we communicated last quarter, slightly below our guidance, which can all be attributed to lower commodity prices. Versus the guidance we gave you last quarter, we have seen some benefit from improved commodity prices, but that was largely offset by other moving pieces, for example, delays in our ETV projects, all netting to leave us approximately in the same place for the full year that we discussed with you last quarter. We continue to see good opportunities to add to the backlog and – we’re able to more than offset the projects that went into service with new additions. The backlog now stands at $3.8 billion, with an average multiple of 4.7 times. And we see opportunities beyond the backlog, especially in natural gas.

As Rich said, demand is expected to grow by more than 20%, and the biggest driver of that growth is LNG, where many LNG exporters are interested in capacity further upstream to secure more competitively priced and diverse supply. Power demand and exports to Mexico also provide opportunities. We’re seeing incremental power demand from new Peaker plants in Texas and conversions from coal to natural gas, and that benefits our existing business as well as provides future opportunity and Tom will have more details on this in a minute. We also see additional opportunities for renewable diesel on the West Coast and are actively talking to customers about projects. We’re delivering according to the strategy we laid out many years ago. One, maintain a solid balance sheet.

We ended the quarter at 4.1 times, continuing to main some cushion versus our 4.5 times long-term target. Two, invest in high-return projects that we internally fund. Since the second quarter of 2022, we added almost $1.2 billion to the backlog, and we continue to find good prospects. And three, return capital to our shareholders through a well-covered dividend and opportunistic share repurchase. We’ve returned $17.1 billion to our shareholders over the last eight years which is about 45% of our market cap. With that, I’ll turn it over to Tom.

Tom Martin: Thanks, Kim. So, starting with the natural gas business unit. Transport volumes increased by 5% which is about 1.9 million dekatherms per day for the quarter versus third quarter of 2022, driven by EPNG, Line 2000, return to service, increased LNG feedgas demand, increased power demand and increased industrial demand. These increases were partially offset by decreased exports to Mexico. Our natural gas gathering, volumes were up 11% in the quarter compared to the third quarter of 2022, driven by Haynesville volumes, which were up 23%, Bakken volumes, which were up 13%, and Eagle Ford volumes were up 7%. For the year, we expect gathering volumes to be up nicely, 16%, but about 4% below our plan, driven primarily by egress project delays and an asset sale.

As you can see from the overall growth in transmission and gathering volumes, the gas markets continue to be robust. Power demand was particularly notable this quarter. We set a new network peak demand day record of 11.1 million dekatherms per day on August 24 and monthly total demand records, both in July and August, of 9.35 million and 9.81 million dekatherms per day, respectively. 16 of our 20 highest all-time network power demand days occurred this quarter. These statistics reinforce the critical role that our natural gas pipelines and storage assets play in support of the power sector. In our Products Pipeline segment, refined products volumes were up slightly for the quarter versus third quarter 2022. Gasoline volumes were up 1%, while diesel volumes were down 2% for the comparable quarter last year.

Diesel volumes continue to be lower primarily in California as the growing renewable diesel volumes displacing conventional diesel, were initially transported by methods other than pipeline. However, the reduction in conventional diesel volumes does not reflect the true economic picture for us as the RD hub projects we placed in service earlier this year are largely underpinned with take-or-pay contracts. So we get paid most of our revenue even if the volumes do not flow. That said, renewable diesel volumes on our pipelines have been ramping up considerably since the RD hubs came online, up from 700 a day in Q1 of this year to 24,000 a day in Q3. Overall jet fuel volumes increased 5% for the quarter versus third quarter 2022. Crude and condensate volumes were up 5% in the quarter versus third quarter 2022, driven by higher Bakken and Eagle Ford volumes.

In our Terminals business segment, our liquids lease capacity remained high at 95%, excluding tanks out of service for required inspections, approximately 96% of our capacity is leased. Utilization at our key hubs at Houston Ship Channel and New York Harbor strengthened in the quarter versus third quarter 2022, and we continue to see nice rate increases in those markets as the fundamentals improve. Our Jones Act tankers were 98% leased through 2024, assuming likely options are exercised. On the bulk side, overall volumes were down 5% in the third quarter 2022, primarily from lower coal, grain and metals tonnage, partially offset by increases in pet coke and soda ash. Grain volumes have minimal impact on our financial results. So excluding grain, our bulk volumes were down about 3%.

Financial results benefited from rate escalations in the quarter. The CO2 segment experienced lower overall volumes and prices on NGLs, CO2 and oil production versus the third quarter 2022. Overall oil production decreased by 2% from the third quarter last year, but was above our plan for this quarter. For the year, we expect net oil volume to exceed our plan, largely due to better-than-expected performance from projects as well as strong volumes post the February outage at SACROC. These favorable volumes relative to the 2023 plan helped offset some of the price weakness that we’ve experienced. With that, I’ll turn it over to David Michels.

David Michels: All right. Thanks, Tom. So for the third quarter of 2023, we’re declaring a dividend of $0.2825 per share, which is $1.13 per share annualized or 2% up from last year’s dividend. Before I get into the quarterly performance, a few highlights. We’ve continued with our opportunistic share repurchase program, as Kim mentioned, bringing our year-to-date total repurchases to 28.5 million shares at an average price of $16.58 per share, creating very good value for our shareholders. We ended the third quarter with net debt to adjusted EBITDA of 4.1 times, which leaves us with good capacity under our leverage target of around 4.5 times, despite $472 million of unbudgeted share repurchases during the year. And while, as Kim mentioned, we are forecasting to be slightly below budget on full year DCF and EBITDA, more than all of that can be explained by lower-than-budgeted commodity prices.

Meanwhile, we continue to see better than budgeted performance in both our natural gas and terminals businesses. Now on to the quarterly performance. We generated revenues of $3.9 billion, which is down from $5.2 billion in the third quarter of 2022, which is down $1.3 billion. Cost of sales was also down $1.3 billion, and that is due to the large decline in commodity prices from last year to this year. As you will recall, we entered into offsetting purchase and sales positions in our Texas Intrastate natural gas pipeline system, and that results in an effective take-or-pay transportation service, but it leaves our revenue and cost and sales, both exposed to price fluctuations while meanwhile, our margin is generally not impacted by price. Interest expense was higher versus 2022 as we expected, driven by the higher short-term rates, which impacted our floating rate swaps.

We generated net income attributable to KMI of $532 million, down $0.08 from the third quarter of last year. Our earnings per share was $0.24, which is $0.01 down from 2022. Our adjusted earnings was $562 million, down 2% compared to the third quarter of 2022, and our adjusted EPS was flat with last year. Excluding the impact from interest expense, we would have been favorable to last year. And our share count was down $23 million or 1% versus the third quarter of 2022 due to our share repurchase efforts. On our business segment performance, improvements in our natural gas terminals and product segments, which were all up, but were partially offset by lower contributions from our CO2 segment. The favorable natural gas segment performance was driven by greater sales margin on our Texas Intrastate system, favorable rates on recontracting at our Midcontinent Express Pipeline as well as contributions from EPNG and those were partially offset by unfavorable recontracting impacts on our South Texas access.

Our Product pipeline segment was up due to unfavorable pricing impacts in the second quarter of last year as well as rate escalations across multiple assets. Our Terminals segment was up mainly due to improved contributions from our Jones Act tanker business and expansion project contributions. Our CO2 segment was down due to lower CO2 and NGL price and volume as well as higher power costs, and those were all partially offset by contributions from our renewable natural gas business. Our adjusted EBITDA was $1.835 billion for the quarter, up 3% from last year. Our DCF was $1.094 billion, down 2% from last year. And our GCF was $0.49 equal to last year. Again, excluding interest expense, we were favorable to last year. Moving on to our balance sheet.

We ended the third quarter with $30.9 billion of net debt. Our net debt has decreased $9 million since the beginning of the year and on a year-to-date basis, the reconciliation is as follows; we generated $4.7 billion of cash from operations. We’ve paid out $1.9 billion in dividends. We’ve also funded $1.85 billion in total capital expenditures, and that includes growth sustaining and contributions to JVs and settled through the third quarter, we had stock repurchases of $389 million. That gets you pretty close to the $9 million change in net debt year-to-date. And with that, I’ll hand back to Kim.

Kim Dang: And I think, David, on the share count, you mean it was down 23 million shares. Okay. With that, we will take questions. [Operator Instructions]. So operator, Michelle, would you please open it up for questions.

Operator: Thank you. [Operator Instructions] Jeremy Tonet with JPMorgan. You may go ahead, sir.

Jeremy Tonet: Hi, good afternoon.

Kim Dang: Good morning Jeremy.

Jeremy Tonet: Just wanted to start off with a high-level question, if I could. And just coming back to some of the commentaries you said in the past, given that the business has worked through a lot of, I guess, adverse contract rolls and other kind of headwinds are in the past. If you think about the current portfolio, how do you think the EBITDA growth generation is for this asset base? Do you see this as low single-digit EBITDA growth, mid-single-digit EBITDA growth or any other, I guess, framework that you could provide for us would be helpful?

Kim Dang: Sure. So, I think we will go through our 2024 budget in the next month, six weeks or so. I think that will give us a better idea for 2024. But just at a high level, you’re right that we have had some contract rollovers. We published those for you for the last couple of years in our analyst conference. And we stopped doing that because the headwinds with respect to rollovers, et cetera, were not – were no longer material. So, I think the network and natural gas, as you know, the pipes have filled up. Average utilization has gone much higher. That allows you to charge higher rates. That also means that your customers need ancillary services. Storage rates have increased significantly. So, we’re able to charge more for storage.

Obviously, on our contracts and Products and Terminals, we have inflation escalators, which help increase the EBITDA in those businesses. And we’ve seen some nice rate increases, especially as a result of improving markets. On the Terminal side, especially in the New York Harbor and so those businesses have some nice tailwinds. I think in CO2, obviously, the forward curve right now is that it’s a little bit below where we are right now. But I think on average, it is above where we have been. The 2024 curve is above 2023. I think rent prices in 2024 above 2023 right now; we will have these projects that are in service. So I think we have a lot of tailwinds coming in this business. I would say, the one thing that we have to manage is just the regulatory environment, which we’ve seen increase over the last couple of years.

And so those are things we’ll address as we go through the 2024 budget, but it’s – we’ve done a lot of project opportunities also on gas. To some, a lot of which we have added to the backlog, but there’s still many, many more that aren’t in the backlog yet. And I went through some of those in my opening commentary. So it’s hard to boil it all down to a rate until we get very specific on numbers. But I think in terms – the tailwinds right now are very nice.

Jeremy Tonet: Got it. That’s helpful. Thanks for that. And maybe just kind of pivoting gears a little bit here towards capital allocation and see that the leverage is still at 4.1, which I think is below the long-term target here. And it seems like most of the buybacks have been done below $17. And so when you think about capital allocation, do you think this buyback is below $17 sending the message to the market on how management thinks about the value of the stock? Or you see more value in retaining dry powder for acquisitions or growth CapEx? Just wondering if you could update us on your thoughts there?

Kim Dang: Sure. I mean, I think that where we have our return set with respect to projects, as we’ve stated a lot of times is in the mid-teens. And we move up and down from that depending on the risk of the project. And so those are going to be very nice returns and well above our cost of capital and so the priority when we have our target returns set at that threshold are going to take priority over share repurchase. That being said, when we have excess cash flow, and we will do opportunistic share repurchase. And so we don’t have unlimited cash flow to do share repurchases. And so we want to make sure that when we do those, we’re getting a very attractive price.

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

Operator: Thank you. Our next caller is Jean Ann Salisbury with Bernstein. You may go ahead.

Jean Ann Salisbury: Hi. I think a minor for Tom. I know you’ve talked a bit on prior calls about rates for gas storage rising and getting close to $3. I wanted to understand how much of KMI’s 700 Bcf of storage should eventually be able to reset up to these higher rates and the time line of that occurring?

Tom Martin: Yes. I mean I’ll give you a high level and then let Sital step in for more clarity. But yes, I mean much of that capacity is a single-cycle reservoir storage, smaller percentage of that is salt storage, which is really what the multi-cycle storage facilities, which garner those higher rates. As you know, part of our storage is in regulated services. So there’s limits as to what rate increases we can charge for those services. But what we’re seeing in those instances, we’re getting much longer term. And we also have also, as you know, house services, which are another way where we can extract additional value that may not be limited by regulatory caps. And so it’s hard to put a number to answer your question. But we do think whether it’s through salt service that we sell, fee-for-service or these opportunistic PAL services, both short-term and long-term, that we do, as well as getting additional duration on our single cycle storage services.

We’re getting additional value out of this growing trend in storage.

Jean Ann Salisbury: That makes sense. Great. And my other question was about the Wyoming Interstate projects that I saw in release. Is that basically just using currently unused capacity on WIC for the 400 MMCFD. I was wondering if there’s any material CapEx associated with that? Or it’s just – you just start moving flow on empty pipeline?

Sital Mody: Hi, Jean. This is Sital. So really, from a Kinder standpoint, we’ve got the minimal capital, mostly interconnect capital. We’ve been working with our partners for a long time on this. We see Bakken GRs rising significantly. And this is an example of a collaborative project that maximizes infrastructure that’s in existence today and on our side, very little capital.

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

Operator: Thank you. Our next caller is Brian Reynolds with UBS. You may go ahead, sir.

Brian Reynolds: Hi, good morning or good afternoon, everyone. Maybe to start off a little high level on Kinder’s positioning to support this 20% increase in natural gas demand by 2028 that you put in the release. It seems like Kinder is well positioned for this growth, but we could see CapEx trend higher of that $1 billion to $2 billion range. So some of these projects that are helping debottleneck the Texas, Louisiana corridor, GCX expansion and potential more Permian greenfield that’s needed. Just kind of curious, high level, can you talk about the opportunity sets that Kinder has just given Kinder’s prior comments of looking to maintain that 50% market share around LNG supply going forward? Thanks.

Kim Dang: Yes. I’ll make a couple of high-level comments about the opportunity side and then Sital and Tom can add in. I think there’s multiple opportunities on the LNG front. So you’ve got the next decade down in South Texas. So that is going to require incremental pipeline infrastructure probably. You’ve got multiple facilities coming in along the Texas, Louisiana border, and those – a lot of – some of those have existing header pipes, some of them don’t. Some of them are wanting to reach further back. As a result of the sucking sound of LNG on the Gulf Coast, you have a southeast market that is short supply. And so there’s opportunities to try to expand pipeline capacity into the Southeast to help meet some of the demand there.

There is opportunities for exports to Mexico think they’re building a number of new power plants, which don’t have supply yet, some of that’s out on the West Coast of Mexico. So there’s opportunity to serve that new power plant load. There’s also LNG facilities that are going on the West Coast of Mexico. And so there’s incremental opportunity there. In California, they’ve just announced that they’re extending the life of their natural gas facilities and they’re increasing the capacity of Aliso Canyon. And so I think people are understanding that natural gas is going to play a big role for a longer period of time than what some people out there previously thought. We’re seeing, as Tom talked through all the power demand, we’re still seeing some coal conversions to natural gas, which is driving demand.

And then there’s industrial growth on the Texas Gulf Coast. And so I think there are a number of – there are a number of different factors driving the growth, but I think most of it is in the southern market. It’s really hard to get infrastructure built into the Northeast. And so WoodMac shows 90% to 95% of the demand growth in natural gas occurring in Texas and Louisiana.

Sital Mody: I think the only thing I’ll add to that, we’re – when you think about the competitive landscape, we’re heavily competitive, right? And so I think what differentiates us is our network. I think what we’ll bring to the table is our – our on-system storage, balancing capabilities, and then more recently, we’ve been focused on expanding our ability to aggregate nitrogen. And I think that’s what’s going to help differentiate us from the competition.

Kim Dang: Yes. The other thing I’d say is that helps differentiate is the fact that we can provide shippers with multiple different outlets. So if an LNG shipper, if the international markets change and the ships go somewhere else, we can, given the pipeline system that we have can help them redirect those flows if they have storage service into storage, but if they don’t have storage service to other markets.

Brian Reynolds: Great. Thanks for all that. Maybe as my follow-up to touch on just the CapEx backlog build multiple. It’s got a lot of focus over the previous few quarters. So it seemed to trend a little bit higher this quarter with an increase of the backlog as well. So just kind of wondering if you can talk about the moving pieces there, whether it’s new projects driving it or whether the rising rate environment is having an impact on future returns? Any color would be helpful. Thanks.

Kim Dang: Sure. Absolutely. So one, let me start with the fact, and we talked a little bit about this last quarter that the backlog multiple is not our focus. What we focus on is the return on projects. And so – and we run a long-term cash flow and assume a terminal value or not and assume a renewal or a partial renewal or not. And for you guys, what we do and the backlog is we just look at first year EBITDA and translate that into a multiple to try to help you understand sort of what these projects are going to generate. But the way – so all I’m saying is that, the multiple may move up or down on the backlog and these are still very attractive projects. So it’s not like we only do projects that come into the backlog at three times.

And again, with kind of a mid-teens average unlevered IRR and we’re adjusting up or down that slightly based on cash flow risk. But this quarter, what we saw was the projects that went into service were about roughly three times multiple the projects that we placed into the backlog, so that the added projects were about a four times multiple. And then on one of the existing projects in the backlog, we decreased the year one EBITDA. And the reason did that was because we think that project is going to take a little longer time to ramp into the EBITDA. And so we’ll get – we think we’ll get to the EBITDA that was in the backlog. It just won’t happen until later in time, it won’t be year one. Now, even if we never ramped on that project, that project is still a very attractive return.

And I think we feel pretty good that we are going to add incremental volume there.

Brian Reynolds: Great. Makes sense. I’ll leave it there. Enjoy the rest of the evening. Thanks

Operator: Our next caller is Tristan Richardson, Scotiabank.

Kimberly Dang: Hi, Tristan.

Tristan Richardson: Hi, good morning. Good evening. Just appreciate it Kim. I guess just given the growth you guys you’re seeing in the core transport business and certainly, volumes are growing in midstream, but as you said, volumes are a little below plan, and you guys are working on asset sales. I mean, do you see midstream continuing to contribute less to the business maybe as a percent over time, especially as we kind of look into next year?

Kimberly Dang: And so when you say midstream, you’re separating out the gathering and processing from all Texas Intrastate business, which is also in midstream?

Tristan Richardson: Correct.

Kimberly Dang: Particularly focused on gathering and processing.

Tristan Richardson: Yes.

Kimberly Dang: I think the gathering and processing is going to decrease as a percentage of the overall business. I don’t know the answer as a percentage of overall business. What I can tell you is I don’t anticipate the gathering and processing the EBITDA from gathering and processing on the natural gas side is going down, because we – natural gas demand is growing, and we’re going to continue to need more natural gas molecules. And our biggest position is in the in the Haynesville and Eagle Ford. And those are two places that are very close to the LNG demand. And as Rich and Sital have both mentioned, Eagle Ford has some gas – has some very nice characteristics in that it has low nitrogen. And so that I think would continue to expect to see growth in the volumes coming out of those basins.

Sital Mody: Yes. I mean I think the relative comparison as you secure some of these large projects, you might see a differential in overall percentage. But I think Kim’s when we look at our gathering and processing systems, Bakken constrained, Eagle Ford approaching full processing capacity. And in the Haynesville, we’re trying to keep up. And so I think that trend will continue as we see these LNG facilities come on. And as far as the proportionate – the relative proportion, it all depends on if we’re successful in getting these big LNG feeder projects and not, and those are obviously material.

Kimberly Dang: So on the Haynesville being constrained, that means there’s going to be opportunities for new projects as that volume increase on the processing capacity at – being at capacity on processing in the Eagle Ford. There may be opportunities to charge incremental rate there. So just to clarify what Sital was saying.

Tristan Richardson: Appreciate it. And then a quick follow-up. Just on the energy transition venture side, maybe top of the funnel, commercial activity you’re seeing around RNG maybe just a sense of overall potential capacity projects out there, particularly as you get past 2024 and Autumn Hills comes online?

Anthony Ashley: Yes. Hi, Tristan, it’s Anthony. Yes, so as we look 2024 and beyond, we do have some additional projects within the North American natural acquisition, landfill gas and electric projects, which are potential RNG conversion opportunities. And so now we’re got a little bit more clarity from the EPA on the RINs potential. We are now looking at those potential projects again. And we have a few other ones, I would say, that we’re looking at in terms of organic growth potential, but our focus has really been getting our existing projects up and in service and operating well and going through the wind generation process. But yes, we do have some potential opportunities beyond Autumn Hills.

Kim Dang: And just on the facilities, I mean for an update there, two of the three that we’re bringing in service this year are in service. One, we’ve had a few operational issues. We think we’ve largely worked through. The other one is ramping up. And the third one we expect to be on by the end of the year.

Tristan Richardson: Appreciate the update. Thank you, Kim.

Operator: Thank you. Our next caller is Neal Dingmann with Truist Securities. You may go ahead.

Neal Dingmann: Good afternoon, all. You talked a bit about M&A. I guess my question is just perhaps on near-term M&A. I’m wondering how you all would think about potentially adding natural gas pipelines, various other assets. I’m just wondering given your current footprint, is there a preference? Or are you sort of agnostic on looking at various assets?

Kim Dang: Yes. I think that acquisitions are easy to imagine and hard to do. And so I think that it’s more – acquisitions are more opportunistic is what I would say for the most part. And yes, we are always interested in acquisitions and have been since our inception, and we have a pretty disciplined process around looking at it. There are three criteria that are core for us to do an acquisition. One, the asset has to fit our strategy. So it needs to be fee-based, energy infrastructure. Two, it needs to have the right attractive economics around it, which means it needs to be accretive to DCF per share and have an attractive unlevered after-tax return. And three, it can’t be – we prefer that it not be dilutive to our long-term debt metric of 4.5 times debt to EBITDA. And generally, I don’t think we would do something that is relative to that debt metric. It would have to be something that was very, very special.

Neal Dingmann: That all makes sense. And then, Kim, I think you mentioned you mentioned earlier, something about the RIN price. I’m just wondering, did you say you saw this increase in or maybe also could you speak to the direction of your – of the D3 RINs?

Kim Dang: On the D3 RINs, they have gone to $3.40 right now, I think. So they were below $2 before June when the EPA came out with the new RBOs. Post that, they traded in and around $3. And in the last week or so, we’ve seen them go up to $3.40. And hard to pinpoint exactly what that is, but I think there may be people out there that haven’t satisfied their 2022 obligations yet, and that could be driving some of the 2023 pricing. So I think RINs prices right now look pretty good for 2024.

Neal Dingmann: Yes, it sounds encouraging. Thank you.

Operator: Thank you. Our next caller is Keith Stanley with Wolfe Research.

Keith Stanley: Hi, good afternoon. Sorry, if I missed this, but any updated comments on the potential to expand Gulf Coast Express and where things are in discussions with customers and how soon that could move forward.

Kim Dang: Yes, we continue to have discussions with customers and – which is kind of where we were last quarter at this time. And I think there are people that are interested in that, but we don’t have anything to announce yet.

Keith Stanley: Okay. Second question, just on the 2023 commentary of being slightly below plan. It just – it seems to me like the company was pretty much on budget in the first half of 2023 on the EBITDA line anyway and Q3, maybe less than $50 million below budget. I mean, are we talking, when we’re saying slightly below plan that maybe even like less than 1% below the EBITDA target? It just seems kind of small with you guys calling it out.

David Michels: Yes. Hi, Keith, it’s David. Yes, it’s – that’s why we said slightly below. It’s not a material amount below. It’s disappointing that we are below because we’re having really strong performance across a number of categories in our base business. The commodity price impact is less impactful now that we’ve seen some improvement. But as we go through the year, we put on additional hedges and so forth. So we have less upside as the later part of the year improvement in commodity prices materialized and we’ve continued to have some weakness in other parts of the business that offset some of that commodity price improvement. So net-net, it’s – unfortunately, I don’t have additional detail for you with regard to a slightly determination. But yes, it’s disappointing that we’re still a little bit down, but it’s not much.

Keith Stanley: Okay. Thank you.

Operator: Thank you. Gabe Moreen with Mizuho, you may go ahead, sir.

Gabe Moreen: Hi. Good afternoon, everyone. Just a quick question on the fixed to floating and then back to fixed hedges, which you’ve got on, some of which are expiring soon. Just wondering how you’re thinking about that with some of the hedges expiring in the not-too-distant future for interest expense for next year?

Kim Dang: So we have about 25% of our deficit flow. For 2023, we locked in about half of that. So we – our floating rate for 2023, it was about 13%. Those hedges that we put on the 2023 expired at the end of 2023. And so you would expect us to go back to 25%. But we do have swaps that roll off in 2023 and swaps that roll off in 2024. Those swaps totaled $2.75 billion. We have not made a decision yet as to whether we will put a – put swaps on when those expire or just stay more fixed. We would – if we just let all those swaps expire did not put on any new swaps, we would be at 15% or 16% floating percentage. Our long-term strategy has been to float on a portion of our debt because the forward curve has generally overestimated future floating rates.

And so we’ve made – through last year, we’ve made $1.2 billion over the last 10 years on those swaps. This year, we gave back about $200 million. So we made about $1 billion. The one exception to – that we’ve seen in the charts to the forward curve over predicting floating rates has been when you’ve been in a rate hike cycle. And so I think we’re going to be flexible as to when we put new swaps back on. So I think there’s a reasonable likelihood that we may be at a lower floating percentage than 25% in 2024 and may wait for a period of time to put some new swaps back on. But in the future – in the longer term, we may decide to put some of those swaps back on, but in no event do I think we would go above the 25%.

Gabe Moreen: Thanks Kim. And then maybe if I can follow-up with another question around the LNG opportunity and whether Kinder-Morgan sees the need to perhaps develop more of a marketing presence outside the Intrastates to aggregate supply for some of these pipeline opportunities around LNG and similarly, whether there’s any thought to taking stakes in LNG export facilities yourselves to sort of marry up an integrated approach?

Kim Dang: Yes. So we actually do have a small gas marketing business right now and not really focused on LNG opportunities exclusively, but really just opportunities across the domestic market largely off of our assets. We’ll see if there’s incremental opportunities there. We may consider that, as you suggest. But I mean, we don’t – I don’t see us going into an international market that really hasn’t been our footprint and our strategy. But we’ll be open to consider things as opportunities develop, and we’ll see where things go from there. As far as our own LNG taking space out and an LNG facility, again, there’s a lot of capital a lot of risk related to doing that. And so we have tended to be more fee-for-service and provide LNG both capacity – transportation capacity and as it pertains to Elba Island export facility for our customers to play in the international markets. And I don’t see that changing much, if at all.

Gabe Moreen: Thanks Tom.

Operator: Thank you. Our next caller is Zack Van Everen with TPH & Company. Please go ahead sir.

Zack Van Everen: Perfect. Thanks for taking my question. Just want to go back up to the Bakken after seeing the announcements on gas side, have you guys looked into or considered converting the HH pipeline to an NGL pipe to help diversify some of the takeaway options up there?

Dax Sanders: We have, yes. We’ve – and this is Dax. We’ve looked at several different options for repurposing that being one of them. And – we are – we continue to transport crude on the pipe. It’s becoming more largely. We’ve got about 30 a day of residual contracts on that. It’s becoming – as those contracts roll, it’s becoming more of a basis pipeline, which obviously has an incremental element of risk around it, but that’s certainly something we would consider with the right deal.

Zack Van Everen: Got you. And then if you were to convert that, could we assume it’s a similar capacity with NGLs? And are there any opportunities to expand that at all if you were to go that route?

Dax Sanders: It depends on what you put it in. But ultimately, I think if it’s still in liquid service, you do NGLs, maybe a little bit more capacity with some pumps adds but still early.

Kim Dang: Yes. It’s just like any time we have an underutilized asset. We’re looking for other opportunities to utilize, I think this one is pretty early.

Zack Van Everen: Okay. Perfect. Thanks guys.

Operator: Thank you. Sunil Sibal with Seaport Global Securities. You may go ahead.

Sunil Sibal: Hi, good afternoon, everybody and I apologize if I missed this. But I just wanted to touch upon what kind of sequential trends you saw in Q3 with regard to your gas gathering volumes in various basins and also on the crude and condensate systems?

Kim Dang: Sequential volumes. Hang on a second. Sequential volumes on gas gathering, they were down 1%, and they were down 1% on crude. So kind of flattish on a sequential basis.

Sunil Sibal: And that’s fairly representative across the basin?

Kim Dang: They’re different basins. And so that is total for Kinder Morgan. So in gas, that would be – the primary basins would be Eagle Ford, Bakken, Haynesville, and some of those were up a little bit and some were down a little bit in net – I mean, minus 1, I could say that’s kind of flattish, but down slightly. And on the crude, it’s primarily Bakken.

Sunil Sibal: Got it. Thanks for that.

Operator: And at this time, I am showing no further questions.

Rich Kinder: Okay. Michelle, thank you very much. And everybody, have a good day and a good evening. Thank you.

Operator: And thank you. This concludes today’s conference call. You may go ahead and disconnect at this time.