Operator:

Welcome to the Quarterly Earnings Conference Call. All lines have been placed on a listen-only mode until the question-and-answer session of today's call. Today's call is also being recorded. If you do have any objections, you may disconnect at this time. And I would now like to turn the call over to Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.

Kim Dang:

Okay. Thanks, Rich. I'll make a few overall points and then I'll turn it over to Tom and David to give you all the details. We had a solid quarter. Adjusted EPS increased by 4%, EBITDA increased by 3%, and those were driven by growth in our natural gas segment and our two refined products business segments. We ended the quarter at 4.1 times debt-to-EBITDA and we continue to return significant value to our shareholders. Today, our Board approved a dividend of $0.2875 per share and we expect to end the year roughly on budget. Now, let's turn and talk about natural gas for a minute. The long-term fundamentals in natural gas have gotten stronger over the course of this year with the incremental demand expected from power and backing-up data centers that Rich just took you through. Overall, WoodMac (ph) projects gas demand to grow by 20 Bcf between now and 2030, with a more than doubling of the LNG exports as well as an almost 50% increase in exports to Mexico. However, they are projecting a 3.9 Bcf a day decrease in power demand. As Rich's comments indicated, we simply do not believe that will be the case given the anticipated power-related growth in gas demand associated with AI and data centers, coal conversions, and new capacity to shore up reserve margins and backup renewables. Let's start with the data center demand. Utility IRPs and press releases published since 2023 reflect 3.9 Bcf a day of incremental demand, and we would expect that number to grow as other utilities update their IRPs. It's early in the process, but we're currently evaluating 1.6 Bcf a day of potential opportunities. Most estimates we have seen are between 3 and 10 of incremental gas demand associated with AI. Rich took you through the 20 Bcf a day of natural gas power that Texas is contemplating, subsidizing, I should have said 20 gigawatts as well as the US projection of 133 new gas plants over the next several years. At Kinder Morgan, we're having commercial discussions on over 5 Bcf a day of opportunities related to power demand, and that includes the 1.6 of data center demand. Certainly, not all these projects will come to fruition, but that gives you a sense of the activity levels we're seeing and supports our belief the growth in natural gas between now and 2030 will be well in excess of the 20 Bcf a day. Not including -- not included in the 5 Bcf of activity that we're seeing is capacity SNG signed up on its successful open season for its proposed approximately $3 billion South System 4 Expansion that's designed to increase capacity by 1.2 Bcf a day. Upon this completion, this project will help to meet the growing power demand and local distribution company demand in the Southeastern markets. Mainly as a result of this project, our backlog increased by $1.9 billion to $5.2 billion during the quarter. In the past, we have indicated that we thought the demand for natural gas would allow us to continue to add to the backlog, and South System 4 project is an example of that. We continue to see substantial opportunities beyond this project to add to our backlog. The current multiple on our backlog is about 5.4 times. During the quarter, we also saw some very nice decisions from the Supreme Court. On the Good Neighbor Plan, the court stayed the plan, finding that we are likely to prevail on the merits. There's still a lot to play out here, but I do not think the Good Neighbor Plan will be implemented in its current form. It is likely to be at least a few years before a new or revised plan could be put together and a few years beyond that for compliance. And in the interim, we've got a presidential election. The overturning of the Chevron doctrine, which gave deference to regulatory agencies when the law is not clear, is also a positive. Together, these decisions will help mitigate the regulatory barrage we've seen over the last couple of years. And with that, I'll turn it over to Tom to give you some details on our business performance for the quarter.

David Michels:

All right. Thanks, Tom. So a few items before we cover the quarterly performance. As Kim mentioned, we're declaring a dividend of $0.2875 per share, which is $1.15 per share annualized, up 2% from our 2023 dividend. As disclosed in the press release, we're changing our Investor Day presentation from annual to biannual. We plan to continue to publish our detailed annual budget early in the first quarter as normal. Also, last one before we get to the quarterly performance, I'd like to recognize our accountants, planners, legal teams, business unit teams, everyone involved in the preparation for our earnings release and our 10-Q filing, we already have a tough close at this time of year with many working during the July 4th holiday period. And additionally, many of our Houston-based colleagues were impacted by Hurricane Beryl. I want to thank you all for going above and beyond to meet the challenges presented by power outages and damage and not missing a beat with regards to our quarterly reporting and analysis schedule. For the quarter, we generated revenue of $3.57 billion, up $71 million from the second quarter of last year. Our cost of sales were down $4 million, so our gross margin increased by 3%. We saw our year-over-year growth from natural gas products and terminals businesses, the main drivers were contributions from our acquired South Texas Midstream assets, greater contributions from our natural gas transportation and storage services and higher contributions from our SFPP asset. Our CO2 business unit was down versus last year, mainly due to lower crude oil volumes due to some timing of recovery of oil in the second quarter of 2023. Interest expense was up due to higher short-term debt balance due in part to our South Texas Midstream acquisition. We generated net income attributable to KMI of $575 million. We produced EPS of $0.26, which is flat with last year. On an adjusted net income basis, which excludes certain items, we generated $548 million, up 1% from Q2 of 2023. We generated adjusted EPS of $0.25, which is up 4% from last year. Our average share count reduced by 18 million shares or 1% due to our share repurchase efforts. [Technical Difficulty] up 2% from last year. Our second-quarter DCF was impacted by higher sustaining CapEx and lower cash taxes, both of which are at least in part due to timing. We expect cash taxes to be favorable for the full year and sustaining capital to be in line with budget for the full year. On a year-to-date basis, EPS is up 5% to last year and our adjusted EPS is up 9% from last year, so good growth. On our balance sheet, we ended the second quarter with $31.5 billion of net debt and a 4.1 times net debt to adjusted EBITDA ratio, which is consistent with where we budgeted to end the quarter. Our net debt has decreased $306 million from the beginning of the year and I'll provide a high-level reconciliation of that change. We generated $2.9 billion of cash flow from operations year-to-date. We've paid out dividends of $1.3 billion. We've spent CapEx of $1.2 billion and that includes growth sustaining and contributions to our joint ventures. And we had about $100 million of other uses of capital, including working capital. And that gets you close to the $306 million decrease in net debt for the year. And with that, I'll turn it back to Kim.

Operator:

[Operator Instructions] Our first question is from Manav Gupta with UBS. You may go ahead.

Kim Dang:

Okay. Sure. So the backlog, as I said, was up by $1.9 billion. That's really two projects that are driving that. It's the South System 4 that we mentioned and then it is also Double H is the other one and it's our share of South System 4. And then with respect to the multiple, yes, it increased a little bit. As we always say, the reason that we give you the multiple is to give you guys some idea of the returns that we're getting on these projects so that you can be able to model the EBITDA. Now it is not our goal ever to -- we're not targeting a specific multiple and getting a specific multiple on the backlog when we look at these projects. When we look at these projects, we're looking at an internal rate of return. And so -- and we have a threshold for that, and we have a pretty high threshold for our projects. And that threshold is well, well, well in excess of our cost of capital. And then we vary around that threshold, what I'd say, marginally depending on the risk of a project. And so if we have -- and projects that we do, that are connected to our existing infrastructure, where it's not greenfield, tend to have a much higher multiple associated with it. When we are having to loop a pipeline or something, those typically might have a little bit higher multiple, but they're still meeting our return thresholds. And so I think these are very -- despite the fact that the multiple on the backlog is going up a little bit because of these projects, these are still very, very attractive return projects.

Kim Dang:

Yeah. I'd say our initial reaction was similar to yours when we started to see this demand was, they're probably going to target renewables. But as we have had discussions with them, I think that the two things are key from their perspective. One is reliability, and two is feed the market. And so I think natural gas, and Rich said this last quarter, given the reliability of natural gas, it is going to play, we believe, a key role in supplying energy to these data centers.

Operator:

Thank you. Our next question is from John Mackay with Goldman Sachs. You may go ahead.

Kim Dang:

Okay. No, I think the -- and Sital and Tom, you guys supplement here. But this the 5 Bcf is overall power, so some of that's related to AI and some of it's just related to coal replacements, shoring up reserve margins, backing up renewables. So it's across the board, we're seeing it in Texas, we're seeing it in Arkansas, we're seeing it in Kentucky, we're seeing it in Georgia. Desert in Arizona, desert Southwest, I mean it's -- it is in almost all the markets we serve. We're seeing some sort of increase in power demand.

Kim Dang:

It's very much dependent on where these are going to be cited. And so it depends on, is it a regulated market? Is it an unregulated market? So that's just going to vary depending on the market location.

Kim Dang:

Okay. So on natural gas, I'm not sure. We did have a divestiture earlier in the year, which was a gathering asset, but not -- that wasn't during this quarter. And so that was just -- it was an asset that wasn't core to our portfolio and we had someone approach us, and so the price made sense, and so we sold it. On the CO2 sale, we had three -- four fields where there was limited opportunity for incremental CO2 floods. And that is our business, is injecting CO2 to produce more oil. And so we sold those fields that had limited opportunity. And then we acquired a field called North McElroy, which we think has a very good flood potential. And then we acquired a leasehold interest in some property that is adjacent to some of our most prolific areas of SACROC, that we think will also be a great CO2 flood opportunity.

Operator:

Thank you. Our next question is from Keith Stanley with Wolfe Research. You may go ahead.

Sital Mody:

Yeah. So, Keith, this is Sital. One, we had an open season. We do have a broad customer base in terms of regulatory timeline with an in-service of 2028. Clearly, we plan a project of this scale to pre-file and then and then do a [firm filing] (ph), probably without getting into too much detail, there is always competition sometime next summer with a targeted in-service date of late '28. So that's probably the 50,000 foot view on bottom line. Did I answer your question?

Sital Mody:

So we have -- we do have initial phase in '28 and we do have some volumes trickling into year after.

Sital Mody:

So, if I had to take a snapshot and don’t quote me on this, probably today we're about 40%, probably have a 40% share in Texas in terms of connecting and the cost to connect, I really think it's going to vary depending on where the ultimate location is going to be. We do have some unique opportunities where it's actually quite low in terms of -- it's very capital-efficient and there are some targeted opportunities that might involve a little bit more capital.

Keith Stanley:

Thank you.

Jeremy Tonet:

Hi, good afternoon.

Jeremy Tonet:

Just wanted to pivot back to Double H conversion here and how the -- did you say how the NGLs are getting out of Guernsey at this point on -- with this project and I guess, are you working with any other midstreamers on this project overall?

Kim Dang:

Yeah. And I'd say the other thing, Jeremy, when Sital says the market is growing, we don't expect some big growth in crude. He's really talking about the NGLs and the gas because of the increase in GOR.

Jeremy Tonet:

Got it. Okay. And maybe just pivoting when talking about a highly competitive market as far as Permian natural gas egress is concerned. Just wondering any updated thoughts you could provide with regards to the potential for brownfield expansion, be it through GCX expanding or greenfield as well getting to a different market or even the potential to market a joint solution at the same time. Just wondering how you see this market evolving, given that 2026 Permian gas egress looks like a deja vu all over again.

Jeremy Tonet:

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

Theresa Chen:

Hi, I wanted to follow-up on the Double H line of questions. Can you tell us how much capacity the pipe will be in once it converted to NGL service? And would you expect the line to be highly utilized right away in first quarter of 2026, or will there be potentially a multi-quarter or multi-year ramp in the commitments?

Theresa Chen:

Thank you.

Spiro Dounis:

Thanks, operator. Afternoon, everybody. First question, maybe just to talk about capital spending longer term. Historically, you've talked about spending near the upper end of that sort of $1 billion to $2 billion range, but Rich and Kim, if I sort of combine your statements at the outset, it seems to suggest, like, there's a pretty robust opportunity set ahead that maybe wasn't contemplated when you sort of last gave us that update. So, I'm curious, as you think about these larger projects coming in, like SNG and then the broader power demand you referenced earlier, are you still sort of on track to be in that $2 billion zone long term?

Spiro Dounis:

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

Spiro Dounis:

Got it. Okay. That's helpful color. And then switching gears a bit here, Kim, you talked about some of the sort of regulatory events that are sort of becoming tailwinds now, headwinds at first, and I know one other sort of macro factor that sort of got you last year or two was with interest rates that were on the rise. I guess as we look forward, I'm not sure what your view is, but it seems like we're setting up for some rate cuts later this year. So, maybe, David, maybe you could just remind us, as we think about your floating rate exposure, what does that look like in 2025, and is this a potential tailwind for you?

David Michels:

Yeah. It could be -- we'll see if we actually get these rate cuts or not. Remember, we all expected a bunch of rate cuts in 2024 as well, but we didn't get them. We do have a fair amount of floating rate debt exposure. We've intentionally brought it down a little bit because it's been unfavorable to later on additional swaps in the last couple of years, and so our floating rate debt exposure has come down from about $7.5 billion to about $5.3 billion. Additionally, we've locked in a little bit of that $5.3 billion for 2025, similar to past practice to take advantage of some of the forward curve, the favorable interest rate forward curves that we're seeing for next year. So, about 10% of that, I think, is locked in for 2025 at favorable rates. The rest of it gives us a good opportunity to take advantage of any short-term interest rate cuts that we see coming to the market.

Operator:

Thank you. Our next question is from Michael Blum with Wells Fargo. You may go ahead.

Kim Dang:

I think that -- I think we're early in the game. I think that's hard to judge at this point. I would say, again, their two priorities are going to be reliability and speed to market. And I think that's what you're seeing -- that's what you're hearing from the power guys on the -- when they're getting the PPAs. So, I think we will get -- I think we are confident that we'll be able to meet our return hurdles on these projects, but exactly what we're going to get on these projects at this point, I think it's too early to say that. And, generally these things will be -- there'll be some competition. And so, I wouldn't expect us to get outrageous returns by any stretch.

Sital Mody:

Well, I mean, it depends on the receiving delivery. Just think about it this way. I'll just make it real simple. If you're at the beginning of the pipe and at the end of the pipe, it could be. If you're in the middle of the pipe and bringing in volumes, it could be more. I mean, it just depends. So...

Sital Mody:

You got to get -- that's right.

Michael Blum:

Got it. Thank you.

Tristan Richardson:

Hi, good afternoon. Maybe just one more on the CO2 portfolio. Can you talk about sort of capital needs or opportunities with the new portfolio? Historically, you've spent $200 million to $300 million annually here and you noted that there are greater flood opportunities with the new assets. Curious kind of how this changes capital deployment in CO2? And then also in the context of -- I think in the past, you've noted a 10-year development plan of around $900 million. Just curious sort of what the new portfolio kind of looks like going forward.

Tristan Richardson:

Thanks, Anthony. And then maybe just on refined products, it seems like the lower 48 maybe saw a later start to the summer driving season. But it also seems like perhaps volumes have picked up in late June and end of July. Can you talk about what you're seeing this season and maybe what's contributing to that 1% below your initial budget?

Kim Dang:

Yeah, the other thing I'd say on the volumes is, the volumes are one component of the revenue, right, price is the other. And what we've generally seen out in California is that we're moving longer haul barrels rather than some of the shorter haul. So, from an overall revenue standpoint, I think we're in good shape on the refined products.

Operator:

Thank you. Our next question is from Harry Mateer with Barclays. You may go ahead.

David Michels:

Yeah, it's a good question. I think we're -- it's still early stages and we're still evaluating all our options. Generally with these JV arrangements, we prefer to fund at the parent level because our cost of capital is attractive, but we are evaluating our different funding opportunities. I don't -- we've never really been big fans of project financing, puts a lot of pressure on the project and so forth, but we're still evaluating the best course forward. Because of the build time, it's going to take some amount of time to get the pipeline into service. So, there is likely just to be going to be a fair amount of equity contributions in order to fund that as opposed to at the entity level itself. But it's something that we're looking at actively.

Kim Dang:

Yeah. I'll say a couple of things on that and then Anthony can follow up. But look, I think that business has been harder to operate than we would have expected. And as a result of that, until we get our hands fully around the existing operations, we have sort of stood down, if you will, looking at any significant acquisition opportunities. And I think that once we have these plants operating on a more consistent basis, that we will -- we can reevaluate that. But at this point in time, I think we've just -- we've got to get those plants up and operating consistently. But we think we are on the path to do that and hopefully, that will be the case for the second half of this year.

Operator:

Thank you. Our next question is from Samir Quadir with Seaport Global Securities. You may go ahead.

Kim Dang:

Yeah. Generally on the South System 4, we've got 20-year take-or-pay contracts with creditworthy shippers. And then we also have a contract that is -- that's underpinning the Double H project. So, consistent with how we've done -- how we do our other projects, I mean, we want to make sure that we've got good credit and good quality cash flow that are supporting a capital builds?

Kim Dang:

Yeah. I think just -- I mean, what we're assuming for the balance of the year is volumes that are relatively flat with the volumes the first half of this year. So, we're not assuming a big ramp-up in volumes the second half of this year, pretty consistent with what we saw in the first half. And then in terms of the big -- the three big basins where we are going to be South are going to be Eagle Ford, Haynesville, and Bakken. And so, we've seen a little bit of weakness, I think, in each of those, probably a little more in the Haynesville than in the others.

Tom Martin:

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

Sunil Sibal:

Thank you.

Rich Kinder:

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

Operator:

Welcome to the Quarterly Earnings Conference Call. [Operator Instructions] Today's call is being recorded. If you have any objections, please disconnect at this time. I’ll now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Thank you. You may begin.

Kim Dang:

Okay. Thanks Rich. I'm going to make a few overall points, and then I'll turn it over to Tom and David to give you all the details. We had a great quarter. Adjusted EPS increased by 13%, EBITDA was up 7%, and that was driven by strong performance in natural gas and our refined products businesses. This type of growth is tremendous for a stable fee-based set of midstream assets as large as ours. So, the balance sheet remains strong. We ended the quarter at 4.1 times debt-to-EBITDA and we continue to return significant value to shareholders. Today, our Board approved an increase in the dividend of $0.02 per share. This is the seventh year in a row that we've increased the dividend. Our financial outlook of 14% growth and adjusted EPS for the year as well as the other budget guidance we provided in January is unchanged. We've seen much lower gas prices than we anticipated this year, but the long-term fundamentals in natural gas remain very strong. Gas demand is expected to grow significantly between now and 2030 with a more than doubling of LNG exports as well as a 50% increase in exports to Mexico. And that doesn't include the anticipated substantial increase in gas demand from power associated with AI and data centers that Rich just mentioned, estimates we've seen range anywhere from 3 Bcf to over 10 Bcf and we've seen some estimates as high as 16 Bcf. With respect to the LNG pause, we do not think it impacts our planned projects or the growth in the LNG market between now and 2030, although it could impact the mix of projects. But we think that is an - we think the LNG pause is an unwise decision and bad policy. Our petroleum products business continues to produce very stable cash flow. Volumes are steady and much of the business has tariff for contract escalators. It will produce nice cash flow for years to come. It's also a capital-efficient business and have some nice growth opportunities around the edges in product blending, renewable diesel, and other sustainable fuels. Our backlog of projects increased by about $300 million during the quarter due to new natural gas projects added. The backlog and the multiple on the backlog remains less than 5 times. And I also think that we've got significant opportunity to add to the backlog within the next year. In our ETV business, we secured port space in the Houston Ship Channel for CO2 sequestration with capacity to store more than 300 million tons. Significant distance between the emitting source and the sequestration site often challenges CCS economics, and we've secured a very strategically located site. So we had a nice quarter in terms of growth. We continue to expect nice growth for the year. We've got a sound balance sheet. We returned significant value to our shareholders and we have nice opportunities to invest in the longer-term. With that, I'll turn it over to Tom to give you details on the business performance for the quarter.

David Michels:

Okay. Thank you, Tom. So for the first quarter of 2024, we're declaring a dividend of $0.2875 per share, which is $1.15 per share annualized up 2% from 2023. For the quarter, we generated revenues of $3.85 billion, which was down $38 million from Q1 of 2023. Our cost of sales was down $108 million, so our gross margin increased 3%, which explains most of the 2% growth in our operating income. Earnings from equity investments is up $78 million, but $65 million of that was due to a non-cash impairment we took in the first quarter of last year. We saw year-over-year growth from our natural gas, products and terminals businesses. The main drivers of that growth came from project contributions, growth project contributions placed in service across each of those business units as well as from additional contributions from our acquired South Texas Midstream assets. We also had higher margins on our natural gas storage assets and higher volumes on our natural gas gathering systems. Interest expense was up due to a higher short-term debt balance due in part to the South Texas acquisition, and we generated net income attributable to KMI of $746 million and EPS of $0.33, both up 10% from Q1 of last year. On an adjusted net income basis, which excludes certain items, we generated $758 million, up 12% from Q1 of last year. And we generated adjusted EPS of $0.34, up 13% from last year. So nice growth as Kim mentioned. Our average share count reduced by 27 million shares or 1% due to our share repurchase efforts. And our DCF per share was $0.64, up 5% from last year. Our first quarter DCF was impacted by higher cash taxes and sustaining CapEx, but that is due to timing of our cash tax payments and maintenance projects. We expect cash taxes to be favorable for the full year and sustaining capital to be in line with our budget for the full year. On our balance sheet, we ended the first quarter with $31.9 billion of net debt, which increased $94 million from the beginning of the year. And here is a high-level reconciliation of that increase. We generated $1.189 billion of cash flow from operations. We paid $630 million in dividends, and we spent about $620 million in total capital, including growth sustaining and contributions to our joint ventures. Finally, as you can see in our press release, we are adjusting our long-term leverage target from around 4.5 times to a range of 3.5 to 4.5 times. We've been operating near the midpoint of that range for several years, and we believe this range is the appropriate long-term guidance for a company like ours that has significant scale in a high-quality business mix, which produces stable cash flows backed by multiyear contracts. And now with that, back to Kim.

Operator:

[Operator Instructions] The first question is from John Mackay with Goldman Sachs. Your line is open.

David Michels:

Sure. So, we started assessing this when our actual operating leverage started gravitating further away from the target leverage of 4.5 times, the budget for 2024 has us at 3.9 times. So, that's when we started assessing it. The timing of the change doesn't really have any - there's no magic to why we're changing it now, except for that slight difference and gravitating away from the 4.5. The practical implications of this change are really - we're not changing the way that we operate our company. We've always kind of had to leverage target of 4.5, but viewed having some cushion below that 4.5 as valuable. We think that this 3.5 to 4.5 is more reflective of where we've been operating and how we'll continue to operate the company going forward.

John Mackay:

All right. I appreciate that. And maybe shifting gears, you obviously started on the big demand ramp. We're hoping to see on the power gen side. Talked through the - you guys talk through the macro really well. Maybe what I wanted to ask on is just tying that to the micro side. If we're looking at Kinder over the next couple of years, where do you see the biggest opportunities for you guys specifically?

Rich Kinder:

But if you just look at overall demand, we've been talking about for months and years, calibrating the demand for LNG export and how much that adds. This is another leg to the stool really. And whether it's 5 Bcf a day, or 10 Bcf a day, we don't know, but it's clearly going to be another leg to the stool in terms of natural gas demand. And I think it will tend to be located near reliable electric generation because if you're a Microsoft or Google, you want that power as close to your facility as possible.

John Mackay:

All right. I appreciate all that. Thank you very much.

Michael Blum:

Thanks. Good afternoon, everybody. I wanted to ask about the Permian, West Texas. Obviously, Waha prices have been negative of late. And I wonder if you can just remind us if there is a benefit there to you? Is there any negative impact just overall how those Waha prices are impacting you?

Kim Dang:

We've got a little bit of capacity on PHP and GCX. We've hedged a lot of that for this year, but there's a little bit open. But as you go out in time, more of that capacity is open. So we participate, I'd say, around the margin when those spreads blow out. So that delivers a little bit of benefit to our shareholders.

Rich Kinder:

Well, look, we continue to try and commercialize both. As I said the last time, highly competitive. We think there's a need. It's just - it's a matter of making sure we have the contract to support the investment.

Operator:

And the next question in the queue is from Jeremy Tonet with JPMorgan. Your line is open.

Rich Kinder:

Hi, Jeremy.

Tom Martin:

From a budget perspective, yes, it's slightly below budget in the Eagle Ford and the Bakken those are well - and even a little bit in the Haynesville overall, but still good growth year-over-year. And like I said earlier, I think this is a temporary blip and development of the production because as demand picks up next year, we're certainly going to need all these volumes and more to meet that demand.

Kim Dang:

Sure. I mean all the businesses that we own and operate, we like. We think they provide stable cash flow and good opportunities. I think that really – we could simplify it a little bit for you. I mean, if you put products and terminals together since they're both primarily refined products, we'd have essentially three different commodity lines. We have Natural Gas, we'd have petroleum products, and we have the CO2. I think on CO2, that oil production is going to be needed for a long time. There's going to be incremental opportunities for CO2 flooding in the Permian as you get through all the primary production. And I think that business gives us the expertise that we need to exploit the CCS business. And so the reservoir engineers that we use in that business help us as we go out and talk to customers and talk to them about sequestering their gas and being able to keep it in certain reservoirs. And so the businesses we own and operate, we think, are similar in that they are stable fee-based assets, they are – or to the energy infrastructure. And we will continue to operate the asset, somebody coming in and offering to buy them at a great price, in which case, we are highly economic, and we would entertain that. But I think absent getting a wonderful price for our shareholders, we are happy with the businesses that we own.

Operator:

Next question is from Neal Dingmann with Truist Securities. Your line is open.

Rich Kinder:

Good afternoon, Neal.

Neal Dingmann:

Sorry about that. Good afternoon, Kim. My question is on shareholder return, given the new plan for, I guess, the modified plan, I'd say, for the leverage. Will that change anything? With these thoughts towards dividends and buybacks on a go forward?

Neal Dingmann:

Very clear. And then just a quick follow-up on the – I think I got that one on the – exit midstream assets, I'm just wondering, is that kind of going as you had thought, maybe just talk about integration and potentially even maybe more upside than expected. It seems like it's going quite well.

Tom Martin:

Yes. So I mean, early days, obviously. But yes, we are seeing some of the commercial and development opportunities that we were contemplating when we made the acquisition, we're seeing those opportunities come together sooner than we originally expected. Some of those were out even several years from now. I think we may see something even sooner than that late this year or next year on some of those opportunities. But yes, on the other side, we are seeing slightly lower volumes this year to start with, again, given the lower price environment. But overall, we feel we're going to be on our acquisition model for 2024 and beyond.

Operator:

And the next question is from Keith Stanley with Wolfe Research. Your line is open.

Kim Dang:

We added, Keith, about $400 million, and we put $100 million of projects in service to get to the $300 million net additions. And on the projects that we added and gas, we added one interstate projects on TGP. We added an intrastate lateral project on the Texas Intrastate and we added a pipeline Egress project in Altamont, which is on the gathering and processing side.

Operator:

And the next question in the queue is from Theresa Chen with Barclays. Your line is open.

Sital Mody:

Yes. So, this is Sital Mody. Just to - I'll give you a micro example of something we're working on in the Southeast. We've got data center looking to connect to our system. As Rich alluded to, reliability is very important. Not only are they looking for reliable power supply, the power provider itself is looking for incremental capacity. And on top of that, the data center is looking for incremental storage to backstop the intermittency of their backup power generator to the effect that it's not available. So, that's an example of something we're looking at in terms of the broader themes. I think they're looking for access to reliable power. They're looking for access to obviously large populations and land and then water is important for cooling purposes. So, those are kind of some of the themes in our discussions, but specifically, that's a good example of something we're working on in the Southeast.

Kim Dang:

Sure. So, I think it just - it refers to a broad set of opportunities that we're looking at. And so - that is on the supply side, there could be things around Haynesville. We talked about already on this call, coming out of the Permian, there is opportunities coming out of the Eagle Ford as all these basins are going to have to ramp up. Just to get to the 20 Bcf of growth that we've been talking about before you add on top of that, what all the data center and AI demand growth numbers that we talked about. So it is supply to the Southeast, it's LNG on the demand side, it's the industrial growth on the demand side. It is LNG potentially on the West Coast, it's market power growth out in the West. Its power growth in Mexico on the West Coast. So I mean there's a whole bunch of fundamental factors that are driving this. And I think what we're seeing is that the opportunity set has grown. And so - but we are to the point of commercialization of the opportunity set. We won't get all the things that we're looking at. But I think that once you start looking at larger opportunity sets, over time, we're going to add those to the backlog. And so I think some of these opportunities are going to come to fruition within the next year, and that's really what's behind my comments.

Operator:

And the next question is from Dan Lungo with Bank of America. Your line is open.

Kim Dang:

Yes. So I mean here's what I'd say is if we see an acquisition or there's some huge expansion opportunity that could result in leverage going up for a period of time. If there are periods of time when there's less opportunity. Obviously, we produce tremendous amounts of cash flow. And then you could create capacity on the balance sheet for a period of time until more opportunity came along. And so that's why the range it gives us the flexibility to move up and down inside that range, depending on what the environment looks like.

David Michels:

I don't want to speak for the agencies. But I do think it matters that 4.5 being our previous target was viewed somewhat – somewhat by the agencies and certainly by some of our fixed income investors as where we would like to operate with our leverage over the longer period of time to get up to that 4.5 times. In reality, the way we operated was - we operated with some cushion below that. So we think that this leverage target is more in line with the way we've been operating, which is what we've told everyone for a long time. But I think by making this change, I think it will have some impact on the way that the rating agencies view our financial policy as well as our fixed income investors.

Operator:

And I'm showing no further phone questions at this time.

Operator:

This concludes today's call. Thank you for your participation. You may disconnect at this time.

Operator:

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

Kim Dang:

Thanks, Rich. I'll make a few overall points and then turn it over to Tom and David to give you the details. We ended 2023 slightly below budget, with about 1% on DCF per share and about 2% on EBITDA. There are several different moving pieces, but more than all of it can be attributed to lower commodity prices. Just before year-end, we closed the roughly $1.8 billion NextEra South Texas acquisition. This asset -- these assets fit nicely into our existing Texas system serving the Gulf Coast and Mexico demand markets. We were excited to be able to get that transaction done a little more quickly than we expected. Looking forward to 2024, as Rich said, we expect really nice growth over '23, with every business unit expected to contribute incremental earnings. We've updated the preliminary budget guidance we released in early December of last year to incorporate the South Texas acquisition. As a result, our final 2024 budget now projects 15% growth in earnings per share versus 2023, and 8% growth in DCF per share. Our commodity assumptions in the final budget are unchanged versus the preliminary budget. We assumed WTI of $82 a barrel and $3.50 for Henry Hub natural gas, which was consistent with the forward curve during our annual budget process. While current prices are lower, we did not update prices in our final guidance given their potential to change over the year. However, based on our commodity sensitivities, even at current prices, we would still expect strong growth over 2023, given our relatively modest commodity exposure. For example, at a WTI price of $72 per barrel and Henry Hub of $2.80, earnings per share would grow at 12% versus '23, and DCF per share would grow at 6%. During the fourth quarter, we put $965 million of projects in service and added $344 million to the backlog, which currently stands at approximately $3 billion. Despite the decline versus last quarter, we're still confident in our ability to spend at the high end of the $1 billion to $2 billion per year discretionary CapEx range for the next few years. Our confidence is supported by the roughly 20% expected growth in the natural gas market between now and 2030, driven by LNG exports, exports to Mexico, and industrial demand. We're looking at multiple expansion projects, some of them significant in size, to supply LNG exports from the Texas Coast, the Louisiana Coast, and the West Coast, to supply Mexico through exports from both Texas and Arizona, to bring incremental supply to the Southeast markets for Permian egress, as well as expansion of the storage, and for incremental power and industrial demand. We're in a strong position as we exit 2023 and move into 2024. Our balance sheet is the strongest it has been in about a decade. We're projecting nice growth for 2024. And the natural gas business, which is greater than 60% of KMI's EBDA, is underpinned by 20% growth in that market, leading to nice expansion opportunities. We will continue to return significant capital to our investors through dividends and opportunistic share repurchase. Next week, at our annual Investor Conference, we will review in much more detail our '24 budget, industry fundamentals, and our future opportunity set and answer all your questions. And with that, I'll turn it over to Tom to give you details on the performance for the quarter.

David Michels:

Thank you, Tom. So, for the fourth quarter of 2023, we're declaring a dividend of $0.2825 per share or $1.13 per share annualized, which is 2% up from the 2022 dividend. We continued with our opportunistic share repurchase program in the fourth quarter, bringing our total year-to-date repurchases to over 31 million shares at an average price of $16.56 per share, creating a good value for our shareholders. We ended 2023 with net debt to adjusted EBITDA of 4.2 times, and that includes $522 million of repurchased shares and the $1.8 billion closing of our acquisition of the South Texas Midstream assets before year-end. Our leverage would have been 4.1 times if we had included a full year adjusted EBITDA contribution from those acquired assets. We ended 2023 just slightly below budget for the full year. And more than all of that underperformance can be explained by lower-than-budgeted commodity prices. We saw better than budgeted performance in both our natural gas and terminals businesses. And for the quarterly performance, we generated revenues of $4 billion, which was down $541 million from the fourth quarter of 2022. Cost of sales were down a bit more than that, at a reduction of $614 million. Both of those declines were due to a decline in commodity price year-over-year. As you'll recall, we enter offsetting purchase and sales positions in our Texas Intrastate business, which is primarily why our revenue and cost of sales are exposed to price fluctuations, but our margin is generally not impacted by price. Interest expense was higher versus 2022 as expected, driven by short-term interest rates impacting our floating rate interest swaps. We generated net income attributable to KMI of $594 million, down 11% from the fourth quarter of 2022. Our EPS was $0.27, down $0.03 from 2022. Our average share count reduced by 27 million shares or 1% due to the repurchased shares. For our business segment performance, Terminals and Products segments were up, Natural Gas and CO2 segments were down versus the fourth quarter of 2022. The Natural Gas segment was down mostly due to mild winter weather in 2023 versus 2022. The Product Pipeline segment was up due to higher rates on existing assets as well as contributions from new expansion projects, including our renewable diesel assets. Terminals was up due to improved rates on our Jones Act business, contractual rate escalations across multiple assets, and improved tank lease rates in the Northeast region. Our CO2 segment was down due to lower oil and CO2 volumes. Our DCF per share was $0.52, down $0.02 from last year. Excluding interest expense, we were favorable to last year. For the balance sheet, we ended the year with $31.8 billion of net debt, which was an increase from year-end of $901 million -- year-end 2022 that is. So, a high-level of reconciliation for the year-to-date or the full-year 2023 change in net debt is as follows. We generated $6.5 billion of cash flow from operations. We spent $2.5 billion in dividends. We spent $2.5 billion of total CapEx. That includes our growth, sustaining, and contributions to JVs. We repurchased $500 million of stock and we spent $1.8 billion on the South Texas Midstream acquisition, which gets you close to the $901 million increase in net debt for the year. As Kim mentioned, we updated our 2024 budget for the South Texas acquisition from the December guidance that we released. As you can see, the acquisition was quite accretive on both EPS and DCF per share. We're very pleased with the resulting growth projected for 2024 with EPS growth of 15%, DCF per share and EBITDA growth of 8%, and a nice improvement in our leverage ratio to 3.9 times by year-end 2024. And as Rich said, we'll be providing all the details behind those at our annual Investor Day meeting one week from today. With that, back to Kim.

Operator:

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question will come from Jeremy Tonet with JPMorgan. Your line is open.

Kim Dang:

Good afternoon, Jeremy.

Kim Dang:

Sure, Jeremy. Yeah, I mean, the cold weather, you're right, does lead to incremental opportunities for us. You're also right that this is not the same order of magnitude as a Uri. When we do our budget, we do budget for some cold weather and I think coming into the year, we are a little bit nervous about that given the -- a warmer than expected weather. With this cold front I think we have made good progress on achieving -- on our way to achieving some of those cold weather budget assumptions. So, very happy with the progress to date.

Kim Dang:

No. I mean, I think we like the flexibility that we have on our balance sheet. We've been around 4-ish times for the last three years. I think in end of '21, we were at 3.9. Last year, we were at 4.1. And right now, we're at 4.2. But if you adjusted for the EBITDA on the acquisition, you would be at 4.1. And so that gives us flexibility to do acquisitions. That gives us flexibility to do share repurchases. And so, last year we were able to do share repurchase, we did $522 million, as you heard David say. We made a $1.8 billion acquisition and our balance sheet ended essentially in the same place that we started the year. So, when -- especially when we're doing attractive acquisitions, it's not that dilutive to our debt metric and so we acquired the NextEra acquisition at about 8.6 times. And so, relative to our debt metrics, even though we are 100% debt-funded, it wasn't that dilutive. So, I think where our balance sheet is, it gives us lots of flexibility and we were able to execute on multiple opportunistic transactions during 2023. And that's quite frankly what we would look to do going forward as well.

Operator:

Thank you. Next, we will hear from Brian Reynolds with UBS. You may proceed.

Brian Reynolds:

Hi. Good afternoon, everyone. Maybe to start off on just the quarterly performance and the '24 guidance, kind of as it relates specifically to the Natural Gas segment. Jeremy touched on it a little bit, but we saw the year-over-year decline in Nat Gas segment driven by some winter storms in 4Q '22, but I'd be great if you could just refresh us on maybe some of the marketing exposure in the business. Previously, we kind of view it as mostly contracted at this point, but just given the year-over-year earnings decline and maybe looking forward, just given significant amount of Nat Gas price volatility expected ahead and Kinder's strategic positioning in natural gas storage, just kind of curious how we should think about maybe the marketing side of this business on a go-forward basis versus kind of Kinder over the last five years? Thanks.

Brian Reynolds:

Great. Thanks. Appreciate that. Maybe as a follow-up to Permian Natural Gas egress looking forward. It seemed to be -- appear to be short natural gas in the Agua Dulce market going forward with LNG demand coming online in the back half of the decade. So, kind of just curious if you could talk about potential new projects including GCX expansion, what are the updates there and/or the potential for a new-build longer-term? Thanks.

Brian Reynolds:

Great. Makes sense. I'll leave it there. See you next week.

Brian Reynolds:

Great. Makes sense. Appreciate that extra color. Have a great rest of your day.

Jean Ann Salisbury:

Hi. There is a lot of differing reports around Haynesville production trajectory and whether it's in decline and kind of has been in decline for a couple of months. It seems like your fourth quarter was up quite a lot from your third quarter Haynesville volumes, but I was wondering if you could just talk about what you've been seeing on your acreage there over the last month or two, I guess towards the end of the fourth quarter?

David Michels:

Yeah. I mean, so, look, we -- the team has done a wonderful job with our acreage. We're -- look, our acreage is positioned in prime Tier 1 acreage. Our largest customer there is planning for the upcoming LNG wave. And so, while we have seen some of the smaller producers kind of pull back, I think everyone is getting ready for the upcoming demand that's coming our way. And so, if you ask me, I think some of the pullback has helped us. We've had a little bit -- we're trying to keep up with the demand in terms of physical capacity. And so, this year, hopefully, we'll get the rest of that capacity on and be primed and ready to support our customers when they are ready to take. It's been a good ride. We've pretty much doubled our volumes over the last couple of years.

David Michels:

Well, no. I think -- look, I think we've got -- I think we talked about the last quarter. We had our -- we have two projects that we're looking at bringing incremental gas out of the Bakken, one which was, we just put into service this past November. We call it our Bakken Express. We had a Phase 1 and Phase 2. That first wave is already in service and flowing full, 92,000 a day coming into the Cheyenne hub out of the Bakken. So, we don't think gas will be the limiting factor anymore, especially once we get the second phase out. I think we're in pretty good shape there.

Operator:

Thank you. Our next question will come from John Mackay with Goldman Sachs. Your line is open.

Kim Dang:

The $8.0 billion when we published, that was slightly below $8.0 billion, but it rounded up to $8.0 billion and so -- and then the $8.16 billion, the only difference between those two numbers is the EBITDA on NextEra. And the EBITDA on NextEra for 2024 is consistent with what we were expecting.

Kim Dang:

Yeah. I mean, I would say the contribution from the RNG plants in the fourth quarter was relatively small. And we do have three plants in service now. They are not running as consistently as we would like them to run. And so, I think that's what we're focused on now. We recently took over operations from Waste Management and we think that once we really get our arms around this, we will be able to run these -- get these to run very consistently. That may take a couple of months into 2024, but we think we'll get them running consistently.

Operator:

Next, we will hear from Tristan Richardson with Scotiabank. You may proceed.

Kim Dang:

Sure. So, between '23 and '24, there is an expansion project, contracted expansion project that came online, it came online late last -- late -- very late last year. And so, that incremental EBITDA between '23 and '24 is locked-in with customer contracts. With respect to '24 and '25, we don't see anything as significant as that driving the growth. We talked about longer-term multiple being between 7 times and 7.5 times, coming down from the 8.6 times that we bought it. And that was driven a lot by -- a small amount by cost-savings, but really by some commercial synergies and some incremental business that we think we can bring to those pipes, but that really occur three to four years out.

Kim Dang:

Yeah. So, our leverage targets are 4.5 times and there's no change in that. And so, I think we feel like that's appropriate given the size, scope of our assets, the stability of our contracts that are underpinned by take or pay contracts with good customer credit quality. We run, as I said earlier, around 4 times at the end of the last three years. And we see value in having some cushion for opportunities and/or risk if they should arise. And so that gives us plenty of capacity to execute on some opportunity if we found it attractive. Now this isn't burning a hole in our pocket. We don't have to go out and spend this money today. I mean, you've seen us, as I talked earlier, acquire those NextEra assets. Not much impact to our debt to EBITDA multiple. We purchased 500 million in shares, not much impact. And so we've been able to do a lot of these things without huge impacts, but we've got a lot of capacity there if we find something that is a good strategic set, and that has attractive economics for our shareholders.

Operator:

Our next question will come from Neal Dingmann with Truist. Your line is open.

David Michels:

Yeah. I don't think it's changed much. I think it's been the expectation. I think as the market -- both the market side is coming together from the LNG standpoint and the producing side, I think it's probably a perfect match in terms of timing. But I do sense that there is more of a need to ensure that there's a solution in place, probably a little more urgent than maybe we had on the last couple of calls.

Dax Sanders:

Yeah. This is Dax. Good question. I would just reiterate kind of what we've got now. Between the two hubs, we've got about 60,000 barrels a day just under capacity. And then in Los Angeles harbor, our Carson Terminal, we've got 750,000 barrels of storage that will be fully in by the end of the year, 20,000 barrels a day of rack throughput. In Los Angeles Harbor, I think we could easily double that, double both the storage as well as the throughput -- rack throughput capacity. On the hubs, we can double those as well. If we did, off of 60,000, that would get us up to a rate -- throughput rate that would be somewhat consistent with what we've historically supplied in the State of California, call it, roughly around 120,000. Now California uses about 250,000 barrels a day of diesel. And so theoretically, I think we could convert even above that because I think we'll see -- we've got our first facility now, Bradshaw, which is just outside of Sacramento which we've converted 100% to renewable diesel, no hydrocarbon diesel going through there. So -- but whether we do that, it will all be determined by the market. I mean we'll be continuously engaged with our customers and watching the ramp-up of these two Northern California refineries, and we'll do whatever our customers ask us to.

Operator:

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

Kim Dang:

Yeah. Hey, Neal, on -- with respect to the 2024 budget assumptions, we're going to go through all of those at the conference next week. So, if you can hold your question and we'll make sure we address it next week at the Investor Conference when we go through the '24 budget in detail.

Kim Dang:

Yeah. I think we're comfortable at 4.5 times, as I said earlier, given the size, scope -- size and scope of our assets and stability of our cash flow. And so, that being said, we see value in having some cushion and we've been operating with a cushion for the last couple of years.

Kim Dang:

Sure. Yes.

Sital Mody:

This is Sital. I think what Kim was talking about is what -- one, we have the ability to expand GCX. I think as the intrastate industrial market and power market evolve, there is an opportunity to probably do some downstream expansions to carry those volumes into that corridor. I think that's what Kim was referring to.

Neel Mitra:

Got it. I appreciate all the color.

Theresa Chen:

Good afternoon. Thank you for taking my questions. First, just a quick follow-up related to the longer-term guidance on the STX acquisition. In order to get to the 7 times and 7.5 times multiple over multiple years, is there any CapEx associated with that, and how much?

Theresa Chen:

Got it. And on the product side in California, given the ample supply of diesel into the state, with renewable diesel being produced in state, as well as entering into the state from other areas, it looks like the state may be short on gasoline over time as in-state refineries convert. With this backdrop, if there is incremental bid for gasoline imports, are there opportunities for your waterborne terminals there?

Theresa Chen:

Thank you.

Zack Van Everen:

Hey. Thanks, guys, for taking my question. Just following back up on the Permian pipeline, is there a market that you guys are looking more towards, whether it's Agua Dulce, or Carthage, or Houston, that would make more sense at the time for a new pipe?

Kim Dang:

And ultimately the customer -- the customers and the customer contracts will drive that.

Zack Van Everen:

Okay. That makes sense. And then, turning to M&A, I know you all don't rule it out. And one of your peers this year will have some assets on the market. Curious if you guys would ever step out of the US for assets or mostly focused on just US assets for M&A?

Zack Van Everen:

Alright. Perfect. That's all I had. Thanks, guys.

Harry Mateer:

Hi, good afternoon. First one, for the past couple of quarters you've been disclosing your 10-Q, some potential financial effects on the EPA's Good Neighbor Act, with the high-end of the range fairly material. I was wondering if you can update us on where you stand in that process and things we can keep an eye out for in terms of whether the ultimate effect winds up being towards the higher or lower end of the range?

Harry Mateer:

Got it. All right. Thank you.

Kim Dang:

Thank you, Sheila.

Operator:

That does conclude today's conference. Thank you for participating. You may disconnect at this time.

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.

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.

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.

Operator:

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

Kim Dang:

Good morning Jeremy.

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

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.

Operator:

Our next caller is Tristan Richardson, Scotiabank.

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?

Tristan Richardson:

Correct.

Tristan Richardson:

Yes.

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.

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?

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

Operator:

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

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%.

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.

Operator:

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

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.

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.

Zack Van Everen:

Okay. Perfect. Thanks guys.

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?

Sunil Sibal:

And that's fairly representative across the basin?

Sunil Sibal:

Got it. Thanks for that.

Rich Kinder:

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

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.

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.

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.

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.

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.

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.

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.

Brian Reynolds:

Great. Thanks. I'll leave it there.

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.

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

Operator:

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

Rich Kinder:

Sital?

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.

Tristan Richardson:

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

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?

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.

Kim Dang:

And we don't budget for share repurchase.

Keith Stanley:

Thank you.

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.

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?

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.

Operator:

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

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.

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.

Operator:

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

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.

Sital Mody:

That's right.

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?

Neel Mitra:

Okay, great. Thank you very much.

Jeremy Tonet:

Hi. 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?

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.

Jeremy Tonet:

Carbon capture. Yeah.

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?

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.

Operator:

There are no further questions in the queue.

Operator:

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

Operator:

Welcome to the Quarterly Earnings Conference Call. At this time, all participants are in a listen-only mode. [Operator Instructions] Today’s call is being recorded. If you have any objections, you may disconnect at this time. I’ll now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Steve Kean:

All right. Thanks, Rich. I'll make a few key points about our business, and then Kim and David will cover the substance and details of our performance, and then we'll take your questions. The overview is this. Our balance sheet is strong. Our backlog of projects is up and our largest business, natural gas continues to show growing strength. A couple of more details on each of those. We built our budget for this year with balance sheet capacity available to enable opportunistic share repurchases and incremental investment opportunities at attractive returns, and we have done both. Second, the backlog projects are attractive returns in aggregate, well-above our cost of capital. At Investor Day, every year, starting with the 2015 to 2017 period, we have been showing you on an EBITDA multiple basis, how we perform in those investments relative to our original assumptions. And we have performed very well. It's currently a challenging time from a supply chain standpoint, but we expect to deliver the current slate of projects even with a challenge here and there at very attractive returns. Our current backlog is $3.7 billion, up $400 million quarter-to-quarter and had an aggregate EBITDA multiple of 3.5x. Third, on renewals, we showed at the beginning of the year how our base business renewals in the 2023 budget are showing more increases, the decreases especially in our natural gas business as the network tightens with increasing supply and demand. So a strong balance sheet, a growing backlog and good signs in our base business. A few other broad points about the macro backdrop underpinning this performance. First, as it's becoming clear as time goes on and as Rich mentioned, hydrocarbon infrastructure is going to be needed for a very long time to come in its current use. The world needs reliable and affordable energy to advance human development, and it needs natural gas transportation and storage assets to backstop renewables. Second, our assets are also well positioned for the energy forms of the future. You can see that with the renewable liquid fuels and renewable feedstocks products -- projects in our products and terminals businesses. Third, our existing natural gas transportation and storage network is growing more valuable as the grid tightens with increasing demand over time, and increasing volatility. Compounding this effect is the difficulty of siting new infrastructure in many parts of the country. The value of the network was on display in the first quarter, where we had strong performance in our gas business and what was otherwise except for the West, a mild and unremarkable winter. Finally, on the other hand, our network is well positioned for expansion in those parts of the country where it is possible to build new infrastructure, the Gulf Coast primarily. Our gas transportation and storage network is well positioned in Texas and Louisiana, where over 90% of natural gas demand growth is expected to take place. This point is well demonstrated by the growth in natural gas projects in our backlog. With that overview, I'll turn it over to Kim.

David Michels:

Okay. Thank you, Kim. So for the first quarter of 2023, we're declaring a dividend of $0.2825 per share, which is $1.13 per share annualized, up 2% from the 2022 dividend. I'll start with a few highlights. We ended the first quarter of 2023 with net debt to adjusted EBITDA of 4.1 times, which leaves us with a good amount of capacity under our leverage target of around 4.5 times. We ended the quarter with over $400 million of cash on hand and nothing drawn on our $4 billion revolver capacity. We also issued $1.5 billion of bonds during the quarter, which addresses the majority of our funding needs for the rest of the year at favorable rates. We repurchased 6.8 million shares at an average price of $16.62 per share, and we entered into additional short-term interest rate locks. We have now eliminated short-term interest rate exposure on about half of our floating rate debt through 2023. That helps protect us from further interest rate pressure and the locks have an average rate slightly better than our budget. Our balance sheet and liquidity are strong, and we continue to create value for our shareholders in multiple ways. For the full year, we are leaving our 2023 budget guidance in place. It's still early in the year and a lot could change. We are facing pressure from commodity prices, as prices both realized to date as well as in the forward curves are below our budgeted prices. However, our forecast shows that pressure being substantially offset by better-than-expected operational performance, particularly in our natural gas and terminals business units. Before going on to the quarterly performance, you will notice that our financial disclosure has been updated. We believe this updated disclosure is more aligned with recent SEC guidance, particularly related to non-GAAP disclosure. Now on to the quarterly performance, we generated revenue of $3.9 billion, which is down $405 million from the first quarter of 2022. Our cost of sales was down $679 million to $1.2 billion. As expected, interest expense was up versus 2022. We generated net income of $679 million, up 2% from the first quarter of last year. Adjusted earnings, which excludes certain items was $675 million, down 8% compared to the first quarter of 2022. On our business unit performance, our business segments were up 3% from the first quarter of 2022 in total, and our Natural Gas and Terminals segments were up and our products and CO2 segments were down. Our Natural Gas segment was up with the largest drivers coming from greater sales margin on our Texas intrastate system and favorable rates on our recontracting at Midcontinent Express Pipeline. Our Product Pipeline segment was down mostly due to favorable first quarter 2022 commodity prices, which benefited our transmix businesses. Our Terminals segment was up mainly due to rate escalations and stronger volumes in our bulk terminals businesses, and our CO2 segment was down due to lower NGL prices and volume, lower oil volume and higher pipeline integrity costs. Our G&A and interest expenses were higher versus the first quarter of last year. And additionally, in the first quarter, we had sustaining capital higher versus last year. We budgeted to have higher sustaining capital for 2023 versus 2022. And currently, we're forecasting sustaining capital to be only slightly higher than budget for the full year. Well, we also had -- but also some of the quarter over last year quarter variance is due to some spend being accelerated into the first quarter. So our adjusted EBITDA was $1.996 billion for the quarter, up 1% from last year. Our DCF was $1.374 billion, down 6% from last year, and our DCF per share was $0.61, down 5% from last year. Moving on to our balance sheet. We ended the first quarter with $30.900 billion of net debt, and our 4.1 times ratio is the same as it was at year-end 2022. Our net debt decreased $52 million over the quarter. And here is a high-level reconciliation of that change. We generated $1.333 billion of cash flow from operations. We paid out $625 million approximately in dividends. We spent approximately $550 million in total capital, and that includes both growth and sustaining capital as well as contributions to our joint ventures, and we spent $113 million on stock repurchases. And that gets you close to the $52 million change for net debt. Finally, I'd like to remind our research analysts that we provide a quarterly breakdown of our annual budget on several metrics, EPS, EBITDA and DCF. And we do that since our expected yearly results are not evenly distributed. The main driver of that is our seasonality in our natural gas pipeline business, which typically generate greater margin on our first and fourth quarters due to strong winter demand resulting in higher rates and capacity utilization. Additionally, we have -- we usually have greater expenses in the second quarter due to estimated tax payments. So for example, we disclosed that our budgeted DCF for the first quarter was approximately $1.4 billion, while our budgeted DCF for the second quarter was approximately $1.0 billion reflecting that expected seasonality. Our actual DCF for the first quarter was $1.374 billion, a little lower than our budget, partially due to that accelerated capital -- sustaining capital spending. And at this point, there are a number of analysts estimates that appear to be out of line with this quarterly guidance. So we encourage you to revisit that guidance as necessary. With that, I'll turn it back to Steve.

Operator:

[Operator Instructions] First question in the queue is from Brian Reynolds with UBS. Your line is open.

David Michels:

Yes. I think that's -- I think the bottom line summary is commodity prices are pressuring our business in the CO2 business and a little bit in our natural gas business, and those are being largely offset with some of the items that you talked about largely offset so far for the year so that, that business operational performance -- outperformance is offsetting that commodity price weakness and a lot of that is coming in our natural gas business, particularly in intra-states and in poles and higher commodity price, higher capacity sales values across our system in the natural gas business, we're also seeing higher terminals, rate escalations than what we had budgeted.

Steve Kean:

Yes. Look, there's some upward pressure on CapEx, but it's not -- I don't think material to the overall investments that we're making this year, Really what we're seeing is there's been a slight uptick in our capital expenditures -- discretionary capital expenditures for the year, but that's largely due to new opportunities that have emerged over the course of the year. And look, we've been managing this since we started seeing inflation crop up over the course of 2022. We continue to do that and continue to examine our assumptions. And when we sanction new projects, we're always making sure that our cost and schedule estimates are up to date. We're monitoring on a routine basis, the lead times for various key components, et cetera. And -- and overall, like I said in my remarks, I think we're expecting to do very well on the capital that we're putting to work.

Operator:

Next question in the queue is from Jeremy Tonet with JPMorgan. Your line is open.

Steve Kean:

Good afternoon.

Steve Kean:

Yes, I mean, it's really kind of across the board. It's on contract renewals. It's on short-term business that we're doing, and it's on rates that we're getting for new business as well. Sital do you have any other comments there?

Jeremy Tonet:

Got it, that's very helpful there. And then just kind of shifting to the Permian as a whole. Natural gas egress, we've seen volatility in Waha prices and with PHP being pushed off a little bit here, I would imagine that would persist across the year. Just wondering your thoughts, I guess, for egress and when the next pipe of the Permian could be needed in Kinder could participate in that type of project. Just wondering an updated Permian natural gas egress thoughts on their side?

Sital Mody:

2026, 2027.

Jeremy Tonet:

2026, 2027 in service or when a new pipe would start construction?

Jeremy Tonet:

That's very helpful. Thank you.

Colton Bean:

Good afternoon. Maybe just sticking on PHP, it looks like the one to two-month delay there versus initial expectations November 1st. So, is first, any detail on which components are driving the shift? And then are those now in hand, or do we still need to see some supply chain improvement to hit the December in service?

Colton Bean:

Okay. So based on everything you're seeing today, it still seems like sometime before year-end?

Colton Bean:

Great. And then, David, you mentioned locking in roughly half the floating rate exposure through year end 2023. I guess can you comment on where that stands for 2024 and more generally, do you have interest in locking in rates for next year or contend to see how the market plays out for the time being?

Kim Dang:

And the slots at expire?

Operator:

Next question in the queue is from Michael Blum with Wells Fargo. Your line is open.

Steve Kean:

Anthony Ashley?

Steve Kean:

And just maybe two other points, Anthony. We're not a forced seller of D3 RINs. So we don't -- we're not forced for funding or financing or other reasons to come out into this market at this point. And then the other point is we do this routinely, but we look to stress test our project returns to make sure there's still good returns under different RINs pricing scenarios and the projects and the investments that we've made in this sector still look good.

David Michels:

Yeah, it's a good question, Michael. So no, we don't have an anticipation of changing our long-term leverage target of around 4.5 times. We have been operating below it, we think that's prudent. It can give us some cushion, should we have any headwinds, or should we see favorable opportunities out there to take advantage of, we could utilize some of that capacity to take advantage of those opportunities. I think we would just have to wait and see what those look like. I don't think you have any particular ones on our table right now. But I think we can -- we would say that, we'd be disciplined with the utilization of that capacity, because we do like having some of that cushion available to us.

Operator:

The next question in the queue is from Neal Dingmann with Truist Securities. Your line is open.

Steve Kean:

Yeah, So Neal, we've flipped from a backward dated curve to a Contango curve. We see the supply and demand fundamentals moving in a positive direction. And so when you just take a step back and look at storage, we're seeing volatility across the network. I think the value in terms of what we can get to is new build, right, the new build mark. We've been renewing storage at $3 mark as of late and probably north of that. And so I think – as we move forward, we continue to see longer-term renewals as well as higher-priced renewals.

Steve Kean:

Anthony?

Neal Dingmann:

Very good. Thank you.

Jean Ann Salisbury:

Hi. Good afternoon. Can you talk about the current backlog with a better multiple expectation at 3.5, obviously, than kind of your historical average. Does that reflect a raising of the bar generally, or is it specific to a couple of brownfield projects, big ticket items and the current backlog, and I shouldn't read into it too much for the long term?

Jean Ann Salisbury:

Great. That makes sense. And then after Winter Storm Yuri, as you guys kind of talked about, there should have been kind of willingness to pay more for gas pipelines and storage in Texas as a form of insurance, and it looks like that's been flowing through. I guess my question is, there's been some talk about this Texas energy insurance program. The thing about building out all of these insurance gas power plants for spare capacity. Would you view that as a positive or negative for Kinder Morgan if it does go through, in a way, I suppose it's sort of competing for insurance with your storage and pipeline capacity?

Jean Ann Salisbury:

Okay. Thank you. That’s all for me.

Spiro Dounis:

Thanks, operator. Afternoon, guys. Kim, first one for you. I think you had mentioned lower natural gas prices as a positive factor in attracting back some demand from power and industrial customers. Curious if you think we've maybe seen a lot of that demand elasticity sort of snap back and play out at this point, or do you think there's a lot of latent capacity in the system that maybe hasn't reacted to lower prices yet?

Spiro Dounis:

Got it. Okay. That's helpful. Second question, also on natural gas prices. And if I could, maybe just curious to get your all thinking on the trajectory of nat gas prices from here. And I guess as we look out beyond 2024 to 2025, you see a lot of LNG capacity coming, which should be supportive. But I think between now and then, there is an expectation here that supply could push prices down further. And just given you guys are close to your customers, just curious kind of what you're hearing and maybe how you'd expect producers to react if we do see prices fall maybe below $2?

Spiro Dounis:

Got it. Appreciate all the color. That's all I had. Thanks guys.

Sunil Sibal:

Yes. Hi. Good afternoon everybody. So I just wanted to flush the natural gas long-haul pipeline capacity in Permian a little bit. It seems like when you look at the volatility in Waha prices, it seems to have gone up over the last few months despite the fact that EPNG outage has been restored. So just clear if you could talk a little bit about the nature of your conversations with the customers with regard to building new capacity there? What are the major kind of sticking points before a big project could go ahead?

Sunil Sibal:

Got it. Thanks for that.

Rich Kinder:

Okay. Well, thank you very much for joining us today, and have a good evening.

Operator:

Welcome to the quarterly earnings conference call. At this time all participants are in a listen-only mode. [Operator Instructions] Today’s call is being recorded. If you have objections, please disconnect at this time. I’ll now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.

Steve Kean:

Thank you, Rich. I’ll give you a brief look back at what we did in 2022 and how well we have set ourselves up for the future. Kim and David will cover the substance and the details of our performance, and then we’ll take your questions. Next week, we have our comprehensive annual investor conference. So, as usually is the case on this call, we’ll defer to next week the more detailed questions on the 2023 budget and the outlook and business unit performance. As Rich said, we had a very strong year in 2022 and wrapped it up with a great fourth quarter. Late in the fourth quarter, for example, we saw some volatility in the gas market, and that creates opportunity for large transmission and storage operators like us and for our customers who procure transportation and storage services from us. We performed well operationally for our customers financially for our company. Thanks, as always, to the tireless preparation and execution of our commercial, logistics and operations teams. We saw that come through, especially during the holiday weekend, when our teams work seamlessly across organizational lines to prepare, respond and recover and deal with the upsets along the way. That requires a committed workforce and a strong culture, and we’ve got that at Kinder Morgan. Our work in 2022 also set us up well for the future. We added to the strength of our balance sheet, finishing the year at 4.1 times debt to EBITDA better than our 4.3x budget for the year and well inside our long-term target of approximately 4.5 times. We originated new business, which has grown our backlog to $3.3 billion made up of high probability projects at an extremely attractive EBITDA multiple of about 3.4 times. These investments are weighted toward our lower carbon future in natural gas, renewable liquid feedstocks and fuels in our products and terminals businesses, and investments in our Energy Transition Ventures business. And these lower carbon investments are all expected to yield very attractive returns well above our cost of capital. That’s how we told our investors we would approach these opportunities, and that’s exactly what we are doing. There are no loss leaders here. We also returned value to shareholders in the form of a well-covered modestly growing dividend and additional share repurchases. For 2022 alone, we’ve returned nearly $2.9 billion to shareholders in declared dividends and share repurchases. On the share repurchases, we have used a little under $1 billion of the Board authorized amount, and the Board has now upsized the total authorization from $2 billion to $3 billion. As always, those will be opportunistic repurchases when we use that capacity. Also, as we talked about throughout the year, we’re starting to see nice uplift on our base business, on renewals in our natural gas business and built-in escalators in some of our products and terminals, tariffs and contracts. We are putting behind us the contract roll-off headwinds in our gas group. Bottom line for investors, what we do today will be needed for decades to come. And as we are demonstrating in our products and terminals businesses, the assets we have today can accommodate the energy forms of the future. We are making the gradual pivot that the gradual energy evolution dictates, and we’re doing it at attractive returns for our investors. With the cash our businesses generate, we’re maintaining that strong balance sheet, we are investing in projects with good returns, which adds to the value of the Company, and we are returning the excess to our shareholders in the form of dividends and opportunistic share repurchases. We all appreciate Rich’s comments at the beginning, and I’m grateful to Rich and the Board for their support and confidence in us. I’m grateful to my 10,000 colleagues here who have been proud to come to work with every day. And I’m grateful to you on the call who I have interacted with over the years, I learned from you and benefited from your questions and perhaps your occasional criticisms and your ideas. Thank you. As you’ll hear more about next week, we have our balance sheet in strong shape. We have a bright future with rich opportunities before us. And most importantly, we have a great experienced leadership team around this table who are always ready to step up and all of our investors benefit from that. We look forward to seeing you in person at the conference next week. Kim?

David Michels:

All right. Thanks, Kim. So for the fourth quarter of 2022, we’re declaring a dividend of $0.2775 per share, which is $1.11 per share annualized and up 3% from our ‘21 dividend. I’ll start with a few highlights on leverage, liquidity, growth and shareholder value. There’s some repetition here with earlier comments, but it’s worth it. On leverage, we ended 2022 with the lowest year-end net debt level since our 2014 consolidation transaction, and we have plenty of cushion under our leverage target of around 4.5 times. For liquidity, we ended 2022 with $745 million of cash on our balance sheet in addition to our undrawn $4 billion worth of revolver capacity. Growth for full year 2022 versus ‘21 excluding the impacts from Winter Storm Uri, as Kim mentioned, we grew nicely. On a net income basis, we were up almost 3 times 2021. That’s partially due to an impairment taken in 2021. And on EBITDA, we’re up 10%, and on DCF per share we’re up 14% year-over-year, very nice growth. For shareholder value for full year 2022, we repurchased 21.7 million shares at an average price of $16.94 per share and our Board just authorized us to do more of that, should the opportunity present itself. We’re seeing healthy growth across our business. Our balance sheet and liquidity are strong as they ever have been, and we’re creating shareholder value across the Company in multiple ways. So moving on to our quarterly performance. In the fourth quarter, we generated revenue of $4.6 billion, up $154 million from the fourth quarter of 2021. Our net income was up -- was $670 million, up 5% from the fourth quarter of last year. And our adjusted earnings, which excludes certain items, was up 16% compared to the fourth quarter of ‘21. Our distributable cash flow performance was also very strong. Our Natural Gas segment was up 11% or $138 million, with growth coming from multiple assets, higher contributions from our Texas Intrastate systems, MEP and EPNG, increased volumes on our KinderHawk system and favorable pricing on our Altamont system. Those were partially offset by lower contributions from our South Texas gathering assets. The Products segment was down $29 million, driven by higher operating expenses as well as lower contributions from our crude and condensate business, and those were partially offset by increased rates across multiple assets as well as strong volumes on our splitter system. The Terminal segment was flat to the fourth quarter of ‘21 with slightly lower New York Harbor and Houston Ship Channel liquids refined product renewal rates, unfavorable impacts from the 2022 winter weather and unfavorable property taxes, offset by greater contributions from our Jones Act tanker business, nonrecurring impacts from Hurricane Ida in 2021 and contributions from expansion projects placed in service as well as other rate escalations that the segment experienced. Our CO2 segment was up $36 million from the fourth quarter of ‘21, driven mostly by favorable commodity prices. Our EBITDA was $1.957 billion, up 8% from last year, and DCF was $1.217 billion, up 11% from last year. Our DCF per share of $0.54 was up 13% from last year. Moving on to the balance sheet. We ended the fourth quarter with $30.9 billion of net debt and a net debt to adjusted EBITDA ratio of 4.1 times. That’s up from 3.9 times from year-end ‘21, but that’s due to the nonrecurring EBITDA contribution from Winter Storm Uri we experienced in 2021. Excluding that Winter Storm Uri, EBITDA contribution that year-end 2021 ratio was 4.6 times. So we ended the quarter and the year nicely favorable to the metric excluding Uri contribution. We’re also nicely below our long-term leverage target of around 4.5 times. Our net debt change for the full year of $278 million was driven by a number of things. So, here’s a high-level reconciliation of that. Our DCF generated $4.97 billion. We paid out $2.46 billion in dividends. We spent $1.1 billion on growth capital and JV contributions. We repurchased stock in the amount of $368 million. We made two renewable natural gas acquisitions for around $500 million. And we received $560 million approximately from the sale of a partial interest in our Elba Liquefaction company. Finally, we had a working capital use of around $825 million from several items, and that gets you close to the $278 million reduction in net debt year-to-date.

Steve Kean:

All right. Okay. Ted, let’s open it up for questions. And as usual, we have a good chunk of our senior management team around the table. We’ll make sure that you get a chance to hear from them as you have questions about their businesses specifically. So Ted, if you would open it up to questions.

Jeremy Tonet:

Just want to say congratulations to everyone, and Steve, best of luck going forward. And maybe just starting off, I guess, with capital allocation, wondering if you could touch on any updated thoughts there. It seems like the dividend uptick might have been a little bit less than expected. And then, at the same time, the share authorization levels were increased when it wasn’t fully utilized before. So just wondering, is it signaling any kind of shift in capital allocation or any other thoughts there on return on capital?

Kim Dang:

Yes. And on the dividend, what I would say is that it’s important -- we believe it’s important to increase the dividend when the Company is growing. And -- but we do -- we are one of the top 10 dividend yields in the S&P 500. And so, we already have an attractive yield on the stock. And so, it’s a small increase so that we continue to increase in terms of being a good dividend paying stock, but also recognizing where the yield on the stock is.

Steve Kean:

Yes. It’s -- so look, we had uplift primarily in our Natural Gas assets. And that’s attributable to what I said at the beginning, which is that when you have storage and transport capacity, particularly in this case, storage where -- Kim, I think the peak was 160 Bcf and we had some supply degradation. This is a nationwide look down to a little over 80 Bcf. The difference had to be made up with storage and people who had those assets and have the capability were able to do well in those. The net, though, we did have some operational upsets and repairs we had to make, et cetera. And so, we netted those out. And it’s not -- the storm itself is not a huge incremental contributor. It’s on the order of $20 million or so when you net everything. But I think just overall, experiencing the winter weather and the volatility that occurred in pricing both before and after that winter event, if you have storage and transport, you’re able to take advantage of that, and we did.

Operator:

Next question in the queue is from [John McArthur] (ph) with Goldman Sachs.

Tom Martin:

So yes, the KinderHawk volumes were basically flat from quarter-to-quarter, but we do expect a nice uplift as we move into 2023, and that is -- it is largely capacity constraints, both on our gathering system, we’re spending some capital in 2023 to create some additional capability there and then also a downstream capacity comes online as well. So, we see some really nice opportunities to continue to grow on KinderHawk and in the Haynesville play overall. And that’s not limited to just our gathering and processing opportunities, but we also see some nice interstate rate increase and utilization opportunities as we go forward. So yes, a nice story. Haynesville is a nice good story for us. And then, as far as the Rockies, I mean, yes, there’s -- we’re not seeing a whole lot of growth there. There’s a few a few pockets of green shoots in the DJ. But overall, we’re not seeing a great deal of growth there, although on our Altamont gathering system, we certainly, the Uinta, we’re seeing some nice growth there and expect that to grow as we go into 2023 as well.

Steve Kean:

Anthony?

Unidentified Analyst:

All right. We’ll save [the big] (ph) ones for next week. Thanks for the time. And congrats, everyone, on the new roles.

Jean Ann Salisbury:

Hi. Can you remind us where Kinder Morgan is on rate case settlements? Which ones have been settled and are incorporated into 2023 guidance? And which pipes, if any, could still see rate case this year or next?

Jean Ann Salisbury:

Okay. Thank you. And then what’s the latest on El Paso restart? I think you had a release that noted some positive progress last week.

Jean Ann Salisbury:

Great. That’s all for me, and congrats to you, Kim, and thank you, Steve, for all the time and thoughtful answers over the years. Best of luck.

Spiro Dounis:

Congrats all around. And Steve, I can’t believe you’re willing to walk away from the dollar a year salary...

Spiro Dounis:

Congrats. Two-part question, and my first one here is just along the Permian pipeline. First part, just between GCX and Permian Pass. Curious if one of those is kind of in the front of the queue and if maybe it would make more sense to kind of bring Permian Pass back up to the front. And second quarter, I believe last quarter -- or sorry, last quarter, you mentioned the possibility of maybe phasing the Permian Highway expansion in over time. I think you needed to do more engineering work to figure out if that was feasible. Just curious if there’s an update you can share on that.

Steve Kean:

I think the PHP, there was some discussion last time about when we put our compression in, once we get pretty close to the end, is there any channel. A little bit of capacity that’s available before the November in-service date. And so, I assume that it’s late in the going.

Spiro Dounis:

Got it. Perfect. Thanks for the color on that. Second question, maybe for David. Just maybe an update on how you’re thinking about maturities and the overall interest rate exposure for 2023 and beyond. Just kind of curious what options are available to you to perhaps maybe exceed the DCF budget by outperforming on interest expense?

Operator:

Next question in the queue is from Michael Blum with Wells Fargo.

Dax Sanders:

Yes. I mean the -- we’re not going to talk specifics on returns, but I would say they were very comparable with our traditional businesses. So, we’re doing the right things from a return standpoint. And I’m sorry...

Dax Sanders:

Yes. And this is primarily on the ETV side of things, and maybe Tom wants to talk about the Red Cedar JV part of it. But ETV will have minimum volume commitments in place on that transaction.

Steve Kean:

This is a good opportunity, for CCUS, it’s going to have to be part of the solution over the long term, and we have the capability to transport it put it in the ground and keep it in the ground. And so, there’s a good longer-term opportunity there, and this is a highlight that you can do these things and you can do them economically. And so, we’re happy about this transaction. It’s the first we hope of many -- but there are a number of things that have to be worked out. I think, the biggest is getting Title VI permitting for the sequestration through the EPA or having that authority delegated in Texas and Louisiana and other places, so that we can speed up the permitting process. Anthony and the team have found a way to use a different kind of permit in a different kind of well situation to enable us to do this. And there may be more of those to do as well. But this is a sign of things to come we hope and believe, but it is dependent upon an accelerated permitting process from the EPA.

Steve Kean:

Yes. I’d say a couple of things. So first of all, we had one operational issue in December that. As Kim mentioned, we were down 0.7% compared to the prior year. We had one of our major lines in California, the one that serves San Diego down for 12 days. And if that hadn’t been down, we would be back up to close to flat sort of quarter-over-quarter. And so, looking at 2023 and where we stand right now, and we’ll get into the budget more next week, we’re budgeting an increase of about 3.4% in aggregate. For gasoline, we’re looking at something below that, but for jet fuel and diesel together, we’re looking at something above that, close to 6.5%. But if you look at, starting with kind of jet fuel recall, we’ve been slower to recover in jet fuels and EIA given our weighting towards international flights. EIA for the quarter was down about 14% to 2019, whereas -- I’m sorry, EIA was down 10% to 2019, whereas we were down 14%. So, we still got a better recovery on the jet fuel front to close with the rest of the country as we see international, particularly Asian flights come back, we think that will help us. And recall, we’ve got our renewable diesel projects coming on line on the West Coast at the end of the first quarter. And those have take-or-pay contracts for north of 30,000 barrels a day. So, we think that will help with the diesel picture, so. And looking at what we’re seeing right now midway through January, we seem to be, from a refined products perspective, on top of budget.

Brian Reynolds:

Good afternoon, everyone, and congrats to you, both Steve and Ken. Maybe to start off on the Kinder-based business, which performed pretty well in the quarter. And I just wanted to talk a little bit about future growth opportunities there. Over the past few years, we’ve just seen a lot of competitors come into the market looking to erode that Kinder market share on LNG supply from the Permian and Louisiana. I was just curious if you could talk broadly about how Kinder has a competitive advantage there and whether you guys see yourselves well positioned for new LNG supply projects going forward, or whether effectively, the competition has made returns not attractive at this point? Thanks.

Steve Kean:

Yes. You’ll see a little bit more of this, Brian. But, what you’re seeing when we have a backlog that’s $3.3 billion, and we’re executing it at 3.4x EBITDA multiples is that our network is well positioned, and we’re able to make relatively modest capital efficient investments in our grid to expand, to serve the supply and demand growth that we’re seeing across the network. And so, that’s -- in the past, we had big long-haul projects that might have been done at a slightly higher multiple, still attractive returns. But I think this shows you the fact that we have dozens of projects that we’re doing and a relatively modest capital expenditures each but with really nice returns that we are finding that our network is extremely well positioned for the growth along end.

Anthony Ashley:

Yes. So, we have three of our original RNG projects that came through the Kinetrex acquisition, that will be in service this year. Two of them really in the first half of this year. There is one on EPC contract. So that capital is fully baked into our 2023 budget. And then, with regards to future opportunities, we’ve -- obviously, we’ve made three acquisitions to date. I think we are looking to grow fairly organically at this point in time. I think, there are opportunities out there to grow, and we’ll be looking at those on an individual basis. The EPA did come out with a new proposal recently, which opens up a new demand market for us. And so, there may be some opportunities there to convert some of these assets into electric service as well. So, I think there’s lots of different opportunities that we’re looking at right now in that space. We’re excited about growth.

Keith Stanley:

Congrats to Kim and Steve as well. I wanted to start, Steve, you said the backlog is at $3.3 billion now. So, that’s up another $600 million or $700 million since last quarter, which presumably, that’s why the growth CapEx of $2.1 billion for this year was higher than what you kind of pointed to initially. Can you talk to any of the specific projects you’ve added since last quarter because that is a decent amount?

Kim Dang:

Yes. And a number of the projects that got added to the backlog are in the other news, like part of the Evangeline Pass project, the TVA project, the terminals renewable diesel projects. So those are some of the projects that got added to the backlog in the quarter.

David Michels:

Yes, we would. We think about our capacity for buybacks or other opportunistic opportunities as being our balance sheet capacity as well as the excess cash that we generate in the current year. And so, we would be willing to increase our leverage a little bit. We’ll be real cautious around it, we’ll measure and make sure that we’re being -- we’re using that capacity in an appropriate manner, but that is the way that we think about our available capacity.

Neal Dingmann:

You all hear it mostly, I’m just -- my question is around first on the renewable diesel specifically. Just what future opportunities you see there beyond the Carson terminal and the committed projects? And you touched around this as well, maybe the second question, just hit this now as well, just the same thing on opportunities you see around the CCS.

Dax Sanders:

Yes. So just to comment, I mean, as we’ve said before, right now, every drop of renewable diesel in the United States wants to go to California. I think we expect that as additional state governments later on a third level of the tax credit similar to the one that California has in other states have them, Oregon, Washington, British Columbia that there will be more enthusiasm for projects there. We’ve got terminals there. We are having conversations with people. And so, I think that’s probably other areas in the West Coast or probably next places to potentially develop. And then certainly, with the two hubs that we’re developing in both Northern and Southern California, I think there are additional opportunities to potentially expand those. So, that’s the majority of it from the refined products perspective.

John Schlosser:

Sure. I mean we said last year when we announced the Neste deal that we felt that all boats would rise and there has created a number of opportunities to high-grade our assets, high-grade our customers at Harvey bring additional products in their raise rates, but it has also attracted other customers. And this is what we hope is the second of many projects we’ll be looking at, great opportunity to connect with a neighboring facility that’s involved in an expansion project, where we’ll be handling all the feedstocks into the facility under a long-term10-year take-or-pay. The other area to actually help us too is on our Jones Act vessels. We’ve seen a lot of movement as it relates to renewable diesel from the Gulf Coast to the West Coast and interest in that, which we think will further tighten an already tight Jones Act market.

Rich Kinder:

Okay. Thank you very much. Everybody, have a good evening. Thank you.

Operator:

Welcome to the Quarterly Earnings Conference Call. [Operator Instructions] Today’s call is being recorded. If you have any objections, please disconnect at this time. I will now turn the call over to Rich Kinder, Executive Chairman of Kinder Morgan.

Steve Kean:

Yes. Thanks, Rich. We are having a good year. We are projecting to be nicely above plan for the year and substantially better year-over-year Q3 to Q3, as Kim and David will show you. Some of the outperformance is commodity price tailwinds, but we are also up on commercial and operational performance. Just a couple of highlights. Our capacity sales and renewals in our gas business are strong. Gathering and processing is also up versus plan and up year-over-year. Existing capacity is growing in value on our natural gas network. And we are seeing it across our network on our major interstate systems and on our Texas intrastate system and we are seeing it in both storage and transportation service offerings and we are even seeing it on a previously challenged system, the Midcontinent Express Pipeline. In CO2, SACROC production is well above plan. And of course, we are benefiting from higher commodity prices in this segment, though prices are not as elevated as they were when we talked after Q2. We are facing cost headwinds, mostly because of added work this year. But while costs are up, we are actually doing very well in holding back the impacts of inflation. It’s hard to measure precisely, but based on our analysis of what we can reliably track, we are well below the headline PPI numbers that you are seeing. Actually, we appear to be experiencing about half of that increase. Much good work by our procurement and operations teams and much of this good performance is attributable to our culture. We are frugal with our investors’ money. Looking ahead, we are seeing good opportunities across our network and in gas, in particular, Rich emphasized LNG and that is clearly the biggest long-term opportunity and our network is especially well positioned. I will give you an illustration of that. We currently have 5.7 Bcf a day under long-term contracts serving existing LNG facilities. The associated investment for that 5.7 Bcf was $1.3 billion. That is very capital-efficient expansion of our network. There are other opportunities as well. We have identified and talked to customers on our Texas Intrastate system about over a Bcf a day each of power plant, industrial and utility expansions. Of course, not all that’s going to happen, but it shows the level of economic activity in one of our biggest natural gas markets. We now have a backlog of $2.7 billion of projects, that’s up $600 million on a net basis since last quarter, meaning taking into account the projects that rolled into service over the quarter and almost 80% of that backlog is in low-carbon investments, natural gas, energy transition ventures and renewable diesel and renewable feedstocks projects in our products and terminals businesses. On Energy Transition Ventures, we expect with what we have already acquired and with the projects under construction or development right now to invest about $1.2 billion at an EBITDA multiple of a little over 5x when everything is up and running. I will add that while we have experienced some delay and modest cost increases in this business, the returns are very good and the EBITDA multiple is strong. We also closed on the sale of an interest in our Elba Liquefaction facility during the quarter. The implied enterprise value to EBITDA multiple of the sale was approximately 13x. And so to think about in terms of use of proceeds, that can pay us very favorably to our expansion project multiple of 5.5x in aggregate over the last 3 years as well as through our share price multiple. Again, we are having a very good year and we are setting our business up well for the future. Our balance sheet is strong. We are seeing good value, particularly in natural gas and renewables. We are finding and executing on projects with attractive returns and we are returning value to shareholders. And I will turn it over to Kim.

David Michels:

Thank you, Tim. So for the third quarter of 2022, we are declaring a dividend of $0.2775 per share, which is $1.11 annualized and 3% up from our 2021 dividend. One highlight before I start on the financial performance. We continue to take advantage of our low stock price by repurchasing shares this past quarter. We added over $90 million of repurchases to what we reported last quarter. And so year-to-date, we have now repurchased approximately 21.7 million shares at an average price of $16.94 per share. We believe those share repurchases are going to generate an attractive return for our shareholders. Our savings from the current dividend alone without regard to the terminal value or dividend growth is 6.6%. For the financial performance for the quarter, we generated revenue of $5.2 billion, up $1.35 billion from the third quarter of 2021. The associated cost of sales also increased by $1.16 billion. So combining those two, our gross margin was $195 million higher. Our net income was $576 million, up 16% from $495 million in the third quarter of last year. Our adjusted earnings, which excludes certain items was up 14% compared to the third quarter of last year. On a distributable cash flow basis, our performance was also very strong. The Natural Gas segment was up $69 million with greater volumes on our KinderHawk system, Haynesville, higher recontracting rates on MEP, NGPL and SNG, greater contributions from our Texas Intrastate systems and favorable commodity prices impacting Altamont and Copano South Texas. Our Product segment was down $23 million, driven by a decline in commodity prices impacting our inventory values, lower crude volumes on our HH system as well as higher integrity costs partially offset by higher rate escalations year-over-year. Our Terminal segment was up $7 million with – as Kim mentioned, greater coal and pet coke volumes partially offset by lower contributions from our New York Harbor and Houston Ship Channel liquids terminals versus the third quarter of last year. Our CO2 segment was up $41 million, driven mostly by favorable commodity prices. So our EBITDA of $1.773 billion was up 7% from last year, and our DCF was $1.122 billion, our DCF per share was $0.49, both 11% above last year. For the full year, as Kim mentioned, we expect to be 4% to 5% above our budget. And for the quarter, DCF was ahead of budget by 6.5%. Some of that is due to a shift of sustaining capital into the fourth quarter. And as a reminder, at our Investor Day presentation in January, we said about 22% of our DCF would come in the third quarter of this year. If you apply that 22% to our budgeted DCF increased by 5%, which is what we guided you to last quarter, you would see that we exceeded that expectation this quarter. So, a helpful reminder that we provide useful information on quarterly shaping at our Investor Day. Moving on to the balance sheet. We ended the third quarter with $31.2 billion of net debt and a net debt to adjusted EBITDA ratio of 4.2x. That’s up from 3.9x at the year-end as the non-recurring EBITDA contribution from the Winter Storm Uri in February 2021, it was captured in that year-end ratio. The year-end ratio was 4.6x, excluding Uri EBITDA contribution. So we ended this quarter nicely favorable to the year-end metric excluding Uri. Our net debt decreased to $10 million or has decreased to $10 million year-to-date. So I’ll go through a high-level reconciliation of that. We’ve generated year-to-date DCF of $3.75 billion. We’ve paid dividends of $1.83 billion. We’ve contributed or repaid growth capital and contributed to joint ventures $700 million. We had $225 million of increased restricted deposits, which is mostly due to cash posted for margin related to our hedging activity. We’ve repurchased $331 million of stock through the third quarter end. We’ve had about $500 million of acquisitions, and that’s sort of the two renewable natural gas companies. We received approximately $560 million from the sale of our interest in Elba Liquefaction company and we’ve had about $750 million of working capital use, which is primarily interest expense payments and some other legal and rate settlements. And that gets you close to the reconciliation for year-to-date change in net debt. So that completes the financial overview, and I’ll turn it back to Steve.

Operator:

[Operator Instructions] First question in the queue is from Chase Mulvehill, Bank of America. Your line is now open.

Steve Kean:

Okay. Tom Martin?

Chase Mulvehill:

Okay, perfect. And unrelated follow-up, I know it’s a little early to talk 2023. I know you’re not going to give us exact numbers or anything, but maybe just some puts and takes as you see the overall business as we kind of look out to 2023?

Chase Mulvehill:

Okay, perfect. I will turn it back over. Thanks, Steve.

Jeremy Tonet:

Hi, good afternoon.

Jeremy Tonet:

Capital allocation is a big debate point in the market are focused, if you will, and just wondering if you could update us as how you see your capital allocation philosophy these days? On the one hand, there is a case to be made for repurchases, saw some in the quarter. But how do you weigh, I guess, maybe ramping up the pace of buybacks there relative to the other opportunities you have, especially with regards to RNG consolidation or other energy transition growth CapEx opportunities as you laid out there?

Jeremy Tonet:

Got it. Thank you for that. Very helpful. And just want to circle up with Elba real quick. Just wondering, could Elba be expanded and might you look to monetize more of that or similar assets in the future?

Steve Kean:

Yes. And to be clear, I mean we like our position in Elba, where we got a very, very nice – we made several very good deals at attractive multiples and actually have pulled in more proceeds than we’ve invested in the facility, and we still own 25% of it and the expansion opportunity that Tom is referring to is outside of the JV. And so if we are able to – and we’re not – it’s not in our backlog, we’re not projecting that for you today, but we are examining the opportunity to do an expansion, which would be to our account.

Operator:

The next question is from Marc Solecitto with Barclays. Your line is now open.

David Michels:

Yes. Since the last quarter, we’ve seen significant outperformance in the gas group. We’ve got lower sustaining CapEx. On the other hand, as you noted, commodity prices have decreased. We’ve seen lower volumes in the Bakken is – primarily because it took longer for them to recover from an April storm than we anticipated, lower refined products volumes and higher interest.

Steve Kean:

Yes. But we will start with terminals and ask products [indiscernible] too, John.

Steve Kean:

And Dax from a products pipeline...

Steve Kean:

And Marc, just to comment on probability here. I mean, I think that – and some of you have written about this, it won’t have the desired effect, right? It’s not going to improve things at the pump for U.S. consumers. This is a global and integrated market. And as a consequence, we think that as it’s thought through more, it becomes less and less likely to happen.

Operator:

Next question is from Neal Ding with Truist Securities. Your line is now open.

Steve Kean:

Yes, I will start and ask Anthony to – Anthony Ashley, who runs that group to weigh in. But I think, look, the – out of the IRA, the Inflation Reduction Act, there was an increase in the 45Q credit, which is a refundable credit and that increase in the credit has made more sources of CO2 economic for capture. So picking up things like ammonia plants, so we started with kind of processing plants and ethanol plants. Now it’s picking up things like ammonia plants, cement, some coal plants and some natural gas plants. And so we had active discussions going on that kind of pause while we were seeing how that worked out. And then those discussions started picking up. Anthony?

Neal Ding:

Got it, guys. Great details. And then just one follow-up. I don’t know if you could say anything, just what do you say currently with – you mentioned the downtime of the volumes associated around Freeport, and I just didn’t know if there is any update you could say what’s going on there?

Neal Ding:

Got it. Okay, thank you all.

Keith Stanley:

Hi, thank you. I wanted to start on RNG. Just curious if you have any takeaways from the BP, Archaea deal and I guess how you’re thinking about the competitive landscape over the long run? And relatedly, are you open to a larger platform deal like this? Or is it pretty clear you’re going to focus more on organic development there?

Keith Stanley:

Thank you. Second question just on interest rates. So the higher rates, if they are sustained over time, does that make you rethink the leverage target at all? Or is it more kind of what you alluded to on maybe keeping a little financial cushion. And then I guess related to that, just – I believe in the past, you’ve hedged some of your variable rate exposure heading into the current year. Have you done any of that to-date? I think you had done that for this year for a fair amount of it.

Steve Kean:

And as you know, Keith, it’s worked very well for us over the years. So, over the long term, the approach has been proven value creative.

Steve Kean:

Yes. Yes, we are. Now as we said and as David said at the beginning of the year, we are targeting to be better than that. And we do think that there is value in having that capacity to take advantage of share repurchases, potential for projects, potential for asset acquisitions, and that sort of thing. So, we have trended a little lower. We are lower right now, yes. Thank you.

Operator:

Next question is from Jean Ann Salisbury with Bernstein. Your line is now open.

Tom Martin:

And we will just have to see how we get into the year if that’s possible to do. Certainly at – see the same need in the marketplace that you do and we will look to do that if we can, but nothing that we can really speak to with certainty today.

Tom Martin:

Yes, nothing really new to report there, continuing to market it. As we have talked about in the past, the fuel is sort of the issue in the marketplace at these higher gas prices, but as prices come down, there could be some opportunities there, but nothing really new to speak to right now.

Operator:

Next question is from Brian Reynolds with UBS. Your line is open.

David Michels:

Yes. Brian, we will have a lot more information at the Investor Day. Having just – having completed our budget yet, we have just really just begun our budgeting process. And so we don’t have a lot of detail to provide to you. But I guess just generally speaking, interest rates are much higher now than they have been in the recent past and have been for many years. And so I think we are going to take a patient approach towards locking in rates at these levels. We have the $4 billion of revolver capacity right now that’s available to us. We are sitting on a healthy amount of cash. In addition, so we have flexibility, and we will be patient.

Steve Kean:

Tom?

Steve Kean:

And look, I think I tried to illustrate the proximity of our network to these outlets, right, to the liquefaction facilities and the capital-efficient nature of the expansions we can do of that network by talking about the 5.7 Bcf that’s under a long-term contract. There is more than that, that’s flowing on our systems, really more like 7 Bcf, but that 5.7 Bcf that’s under contract. The capacity was created with about $1.3 billion of investment. And as we look ahead, look, there could absolutely be chunkier projects, right, bigger builds as you get to the 28 Bcf that Rich mentioned. There could be some bigger ones, but there is also a fair number of $150 million to $300 million projects, call it, roughly that are not ready for prime time. But as we look at people who have not yet FID-ed, but may and we look at where they are sitting on our network, we think we can reach them with expanded quantities with relatively capital-efficient investments.

Operator:

Next question is from Michael Lapides with Goldman Sachs. Your line is open.

Steve Kean:

Tom, start with EPNG.

Steve Kean:

David?

Michael Lapides:

Got it. Thank you guys and thanks guys. Much appreciate it.

Michael Cusimano:

Hi. Good afternoon everyone. To quickly follow on to – I think it was Keith’s question earlier on RNG. Could you maybe speculate on the value attributed to KMI versus what the Archaea valuation was and how you feel about the options or – curious how you feel about the option you mentioned earlier about maybe like a separate public vehicle down the road?

Michael Cusimano:

Got it. That’s helpful. And then on the product segment, can you give a little extra detail on the lower crude volumes maybe where it stands today, if those have fully recovered from the weather outage? And then also, if you can talk a little bit about how like lower refined product prices affected margins. Trying to think of like what’s structural and what’s variable to this quarter?

Michael Cusimano:

Okay. Great. And then any comment on the refined product pricing maybe impacting margins and how to think about that going forward? I guess it’s mostly on like the transmix business.

Michael Cusimano:

Specifically about any variability in your margin that you receive from maybe transmix volumes that fluctuate with refined product commodity prices?

Michael Cusimano:

Got it. Alright. That’s all for me. That was helpful. Appreciate it.

Jeremy Tonet:

Hi. Thanks for squeezing me back in here real quick. Just want to see, after Matterhorn, what your thoughts are on cadence Permian gas production and the need for incremental infrastructure, what type – what year do you think that might materialize at that point?

Jeremy Tonet:

Yes.