Kinder Morgan Stock

Good afternoon, and thank you for standing by. Welcome to the Kinder Morgan's Third Quarter 2026 Earnings Results 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 call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

Let me begin by sharing some projections from credible third parties that once again support our belief that the demand for natural gas is destined to dramatically increase both in America and the rest of the world in the coming years and even decades. Shell projects that global LNG demand will grow to nearly 750 million tons per year by 2050 and that's an increase of 65% from 2025. That's an enormous increase and 1 that we believe will especially benefit the U.S. given the preference of international customers for sourcing their supply here. On the domestic front, the North American Electric Reliability Corporation is predicting that peak demand for electricity in this country will grow by between 225 and 245 gigawatts by 2035. And obviously, much of that astounding growth will be met by natural gas generation. These 2 estimates just reinforce and strengthen what we believe is a bullish natural gas story.

Now let me turn to our own story at Kinder Morgan. The third quarter was another good quarter for us with results exceeding both the comparable period in 2025 and our budget for this year. Perhaps more importantly, we made substantial additions to our backlog of new projects. Our additions constitute 1 of the largest increases in any 1 quarter in our corporate history, and our backlog of U.S. natural gas projects now stands at an all-time record. And I would add that we expect these new projects to lead to even more expansion opportunities over the coming months and years. In a broader sense, I believe the existing new projects we announced demonstrate the strength that comes from a large national midstream footprint. That footprint, which we are constantly expanding and extending allows us to offer more diversified connectivity to our customers as they seek alternative and expanded sources of supply.

To put the size and utilization of our natural gas network in perspective, I remind you that we deliver about 40% of all the natural gas in America, including approximately 40% of all LNG feed gas and over 50% of gas exports to Mexico. Our network connects almost every producing basin with the great majority of demand locations throughout the country. I'm highly confident that our assets will allow us to continue to serve the multifaceted needs of our customers, and at the same time, deliver real and sustainable value to our shareholders. As I've said before, but it certainly deserves repeating, our strategy is not complicated. We have assets that generate large amounts of recurring cash flow.

We are in a business that is in need of substantial additional infrastructure. Because of the size and reach of our system, we're in a unique position to capture a substantial portion of that need by developing projects supported by long-term take-or-pay agreements with creditworthy entities. And our strong cash flow allows us to build that infrastructure by using primarily our own cash without undue leverage. We are able to earn good returns from these investments thus increasing our EBITDA and EPS in the years ahead. For me it's hard to think of a better strategy that combines consistent growth with minimal risk. And now let me turn it over to Kim.

Okay. Thanks, Rich. This was another outstanding quarter for Kinder Morgan. Adjusted EPS increased by 21%, adjusted EBITDA grew by 9%, and every 1 of our business segments contributed to that growth. Those results reflect both the strength of our assets and the outstanding execution of our employees. For the full year, we expect adjusted EPS growth to exceed budget by more than 13% and EBITDA to exceed budget by more than 6%. Our financial position continues to strengthen as well. We ended the quarter at approximately 3.5x debt-to-EBITDA, the low end of our targeted range, Combined with our roughly $3 billion of annual cash flow available to fund expansion CapEx we have significant flexibility to fund our organic growth while maintaining a strong balance sheet. That flexibility is important because our project backlog increased from [indiscernible] this quarter.

We added $5.4 billion in new projects and placed $700 million of projects into service. The backlog multiple remains very attractive at 5.7x. In the $5.4 billion of additions are 2 highly strategic joint venture projects, SNG's Southeast Connector and NGPL's Permian Link. Together, Kinder Morgan's share of these projects is approximately $4.7 billion. Both projects are supported by at least 20-year take-or-pay contracts with creditworthy shippers, providing the type of long-term stable cash flow we seek to create. Importantly, Southeast Connector is contracted with strong investment-grade utilities while Permian Link is contracted with an A-rated hyperscaler. These projects also highlight the quality of opportunities we see in front of us.

Southeast Connector is a transformational project that connects diverse supply with 1 of the fastest-growing natural gas demand regions in the country. Large load interconnection request across the Southeast now exceed 200 gigawatts, which could represent roughly 8 Bcf a day of natural gas demand, if it all came to fruition and tied it was all served by gas fire generation. Southeast Connector is designed to meet that need by delivering approximately 2.6 Bcf a day of natural gas into the region. In addition, we expect this project like many of our other large projects to drive future expansion opportunities. Permian captures a similar compelling opportunity by moving abundant low-cost Permian natural gas north to meet growing power demand in the Texas Panhandle.

Together these projects demonstrate how our network is uniquely positioned to connect growing supply basins with growing demand centers. More broadly, as Rich mentioned, the long-term outlook for natural gas remains exceptionally strong. Wood Mackenzie projects North American natural gas demand to increase by approximately 46 Bcf a day by 2035, driven primarily by LNG exports and power generation demand. Projects of this size and quality do not happen by accident. The commercial creativity, customer relationships project management and legal expertise and the patience and perseverance required to bring these opportunities together are remarkable, And I could not be more proud of what our team has accomplished.

Finally, these projects extend our visible growth runway. Before this quarter, most of our EBITDA from our backlog was expected to be online by the end of 2029. With Permian Link and Southeast Connector entering service between 2030 and 2032 we have meaningfully extended the period of high-quality cash flow growth supported by approved projects with long-term take-or-pay contracts. Simply put, we are delivering strong results today while continuing to build a longer runway for high-quality future growth.

And with that, I'll turn it over to Dax to give you details on our business performance.

Thanks, Kim. Starting with the natural gas business unit, transport volumes were up 3% in the quarter versus the third quarter of 2025. We incremental demand was primarily a result of increased LNG feed gas deliveries on Tennessee Gas Pipeline and incremental demand on our intrastate system. Natural gas gathering volumes were up 14% in the quarter from the third quarter of 2025 with most all the increase coming from our KinderHawk system in the Haynesville, which was up 40%. As we've continued to say, demand for gas on our pipes remains high and our system remains highly utilized. While we announced the sanctioning of 2 very important projects today, looking forward and consistent with Ken's comments, we continue to see significant incremental project opportunities across our natural gas pipeline network driven primarily by power and LNG, and we will continue to pursue them aggressively. .

In our products pipeline segment, refined products volumes were down 3% in the quarter compared to the third quarter of 2025 and crude condensate volumes were down 11%. More than half the decline in crude volumes is explained by the removal of H from service for the NGL conversion early in the third quarter of 2025 with the remaining decrease resulting from fewer well connects at Highland crude. As previously announced, we, along with our partners, we're proud to reach a final investment decision on our Western Gateway project during the third quarter. The project which will fundamentally change the way clean products are delivered to the Desert Southwest and Southern California will ensure the availability of these products to consumers for decades to come. Kinder Morgan's $300 million total cash investment, which includes our $250 million contribution to the JV and a $50 million investment in our non-contributed assets has been added to our project backlog and is expected to reach in-service in 2029.

In our Terminals business segment, our liquids lease capacity remained high at almost 93%, and Market conditions continue to remain supportive of strong rates and the utilization of tanks available for use is just under 96% at our key hubs on the Houston Ship Channel and in Carteret, New Jersey. While the temporary Jones Act waiver has added some market uncertainty, our tanker fleet remains exceptionally well contracted. Assuming likely options are exercised, our fleet is 100% leased to the rest of this year, 97% leased through 2027 and 80% leased through 2028. We have opportunistically chartered a significant percentage of the fleet at higher market rates and have an average length of firm contract commitments of almost 3 years. The worldwide shortage in refined product supplies and the associated price dislocations have both been significant positives for our export terminals in the Houston Ship Channel Hub.

In Q3, we saw 427,000 barrels a day move across our 11 docks, which represented an increase of 39% over Q3 2025 and an all-time record. The CO2 segment saw 8% higher net oil production volumes compared to Q3 2025 which was led by an 11% increase in production at SACROC. NGL volumes were 9% higher and CO2 volumes were 3% lower. Finally, RNG volumes increased 18% as the significantly improved operations that are driving both greater uptime and hydrocarbon recovery at our facilities continued in the third quarter.

And with that, I'll turn it over to David.

Okay. Thank you, Dax. We're declaring a quarterly dividend of $0.2975 per share, which is $1.19 per share annualized and an increase of 2% over 2025. We delivered a record-setting quarter once again with net income attributable to KMI and adjusted EBITDA reaching record levels for the third quarter. Our third quarter performance was also ahead of internal expectations with EPS 15% above budget and adjusted EBITDA 6% above our budget and as follows the first half of the year during which we achieved similar outperformance.

Turning to the quarterly financial performance. We had another very strong quarter. For the third quarter, we generated net income attributable to KMI of $764 million and EPS of $0.34. Those are 22% and 21% higher than the third quarter of 2025, respectively. Adjusted EPS was $0.35, so that's 21% up from last year. Adjusted EBITDA grew by 9% to $2.18 billion for the quarter. Importantly, as Kim mentioned, the strength was broad-based with all 4 business segments delivering higher adjusted earnings year-over-year. Natural gas saw greater contributions from EPG, KinderHawk, TGP and ex Intrastate System. This performance was driven by greater volume and rates on capacity sales, parking loan contributions expansion project contributions and greater gathered volumes.

Our Products segment benefited from favorable commodity pricing as well as greater butane blending volumes, partially offset by lower crude and refined product volumes. Our Terminals segment benefited from expansion projects placed into service, higher commodity prices, stronger coal and petroleum coke handling activity and higher Jones Act tanker rates. And our CO2 segment benefited from higher commodity prices, strong volume growth, particularly at SACROC, which was up 11% from last year. Stepping back from the quarter, our year-to-date results have been exceptionally strong. Year-to-date versus 2025, EBITDA has grown 13% and adjusted EPS is up 32%. As Kim mentioned, we now expect our full year adjusted EBITDA to be more than 6% above our budget and adjusted EPS to be more than 13% above our budget. That represents well more than $515 million of additional EBITDA.

As we've previously noted, during 2026, we benefited from a handful of large items that may not be recurring. Winter storm Fern and extended cold weather in the Northeast, a terminals contract buyout, a favorable FERC rate true-up and unusually favorable Waha to Houston Ship Channel spread Collectively, these items contribute approximately $225 million to our outperformance in 2026. In addition, favorable commodity prices have contributed an additional $175 million versus our budget. If you recall, our budgeted WTI price was $60 per barrel. At the same time, tightness continues across our U.S. infrastructure and that provides opportunities for us to capture additional margin when disruptions occur. We expect those conditions will persist.

Moving to the balance sheet. Our net debt to adjusted EBITDA ratio ended the quarter at 3.5x, which is down from 3.8x at the beginning of the year. Despite spending more this year due to our Monument acquisition and greater than budgeted CapEx, we expect to end the year at 3.6x leverage, and that's an improvement from the budget of 3.8x driven by the EBITDA outperformance and that puts us well below the midpoint of our leverage target range. Year-to-date, net debt increased $513 million and here's a reconciliation of that. We generated $5.04 billion of cash flow from operations. We spent $1.98 billion in dividends. We've spent $3.07 billion in capital and that's growth sustaining and our contributions to our JVs and then the Monument acquisition was approximately $500 million and that gets you pretty close to the $513 million debt increase for the year.

Now I'll turn it back to Kim for Q&A.

Okay, Michelle, if you'll come on, we'll take questions.

[Operator Instructions] Our first caller is Theresa Chen with Barclays.

Congratulations on these major commercial milestones I want to ask first on TGP. Following the successful nonbinding open season for the 2019 South project, Can you talk about the progress made on solidifying customer shipper commitments at this point? And how are you thinking about the ultimate size and scope for this project, given the elevated amount of interest beyond the half be offered as well as the downstream growth opportunities, especially on the heels of the Southeast Connector FID? Do you think TGP will play a meaningful role in serving this incremental demand on SG?

Teresa, this is Sital. Well, one, I'm going to break this question up in a few parts. So the open season that we had the nonbinding 1 in terms of interest, over 2 Bcf of interest in that open season where we are right now with our customers. Clearly, we've been intimating to the market and you guys that there's a demand equation here. And ultimately, we'll need to be solved with incremental molecules. We do feel 2019 in some form is going to help contribute to that molecule shortfall. When we think about what the project ultimately looks like, that's going to depend on who signs at the bottom line. One of the things that we're seeing right now is timing. There are some customers that are further along than others. We're managing through that to try and see how we can stage these projects and maybe come in multiple forms. If I had to kind of gauge where I see the CapEx landing there, roughly around $1.5 billion depending on ultimate interest, we could adjust from there. So a strong interest. We do see the need. I think when you think about the downstream Southeast Connector Tennessee is well positioned to serve that.

But not only that, it's also that middle system power corridor that we have that I talked about on the last call. We see that corridor from Ohio, Kentucky, West Virginia and Tennessee. That's a growing demand center. And so all in all, I think the opportunity set there for incremental supply bodes well.

Thank you for that detailed answer, Sital. On the Southeast connector, the press release mentioned that the project can be scaled further with additional customer commitments. What is the realistic upside here beyond the $3.1 billion net to KMI? How much bigger can this project be?

Well, so not too early. We're in the midst of the open season. I will tell you, we had significant interest in the open season, and this was a binding open season. We're still in the process of working through the present agreements, the interest with the -- on the commercial side as well as a very important credit, making sure we have the credit behind. And so we're working through the details. But needless to say, we can scale this up to 3.5, 3.5 Bcf is positive.

[indiscernible] we have enough signed commitments today. to support going forward in FID in the project. And then there are other customers that came in during the open season that are interested that we're working with on PA and they may come in later and that would cause us to scale the project.

And ultimately, it depends on who signs, right? I mean that's always the driver.

Our next caller is Julien Dumoulin-Smith with Jefferies.

I got to hand it to you, impressive here. Let's keep focusing on the Southeast Connector while it's topical here. Maybe just to go back to that point you're bringing up on the middle system here in the prior quarter. How do you think about the size and scope of that opportunity, the timeliness here? I mean you alluded to having some open season pending here, but just what is the scope of contemplated there? You talked about scaling it up to 3.5 Bcf a day a moment ago in parallel. But can you elaborate maybe some other parameters and texture around there?

So if you're focused on Southeast connector, we've got that open season. We'll close, we'll get some clarity around that. As far as the middle system, there are several power projects that have been evaluating capacity, particularly in our 2019 South project. And so really, the timing there is what we're talking about. There's some that are further along than others. And so what we're going to have to do is really, really position ourselves to sanction parts of the project to be able to accommodate the immediate demand. And then the team is still creatively thinking on how we can accommodate the broader interest in terms of incremental scope. And so that's going to take a few quarters to kind of button up in some form or fashion. And then ultimately, as usual, we're going to have -- we'll function when we get customers that fine to the bottom line.

Excellent. And a little bit bigger picture. After adding $5 billion this quarter, how is the greater than $10 billion commentary or opportunity set change, right? Should investors view the Southeast Connector in Permian Link as conversion from the shadow backlog into a more formal backlog? Or as you just alluded to a second ago that was continued customer activity like effectively replenish that funnel. I don't want to put words in your mouth, but I'd love to hear how you kind of frame that shadow today.

So I mean the shadow backlog today, there is substantial remaining shadow backlog. And I'd say that as we talked about in our comments, adding these big projects leads to further opportunities. And so we think that and we've talked about some of them on this call, but as a result of getting these signed up, this project signed up. It will create bottlenecks in other places that we will have to alleviate that will lead to more projects. And so I think the industry fundamentals in natural gas, as we talked about also in our opening comments, remain very, very strong. And so we are confident that there will be meaningful additions, conversions, if you will, into the backlog over time. .

All right. Fair enough. I'll leave it. Actually, just quickly, lastly on Southeast Connector in particular. How does it fit into the broader permitting reform regime just quickly, if you can comment on that.

How does it fit into the permitting reform? Okay. So the bill is in Congress, obviously haven't passed yet. Now the current permitting regime, I think we are very comfortable with and had very good success working with the FERC to get MSX and south of some for both permits from the first within a year, which is the fastest and recent time on permits of this size. And so I think that the current permitting regime, we will be able to get this project done. No concerns there. I think the permit bill that is in Congress is a good one. And I think it does some things that could help on where we've seen certain projects not ours run into problems, but for one, it eliminates the space ability to what I'll call game, the 401 water permits. It eliminates vacatur as a remedy of the court and it strengthens the Nationwide 12 program. So I think it would be great if it got passed. We think it'd be very helpful, and we are very supportive, but we are very comfortable completing these projects under the current -- in the current permitting environment. .

Our next caller is Jeremy Tonet with JPMorgan.

Just wanted to follow up on the capital opportunity set, as you've been describing here. You announced some pretty sizable projects here. I'm just wondering, I guess, as you think about what could be coming forward here, do you see other projects of this type of size? Or were these kind of like the 2 big ones that you've seen? And how do you think about run rate CapEx at this point?

Okay. let me say, it's hard to project exactly what is going to be coming in. But I mean Sital just talked about another $1.5 billion project, and we've talked about other projects that we think will come about as a result of Southeast Connector. So I think the reason for the shadow backlog back in the beginning was because people did not believe in the opportunity set that we were seeing on natural gas. And so we were providing this number to try to hope you understand the opportunity side. I think at this point, with the $14.4 billion backlog, hopefully we've established some credibility about being able to bring these things to fruition. So with respect to run rate, I think the -- it's probably going to be around $4 billion-ish for the next few years in terms of the CapEx that we would expect to.

Got it. That's very helpful there. And David, I wanted to pick up, I think, on some of the comments you laid out when looking forward to '27, some onetime upside optimization that I would imagine it's not baked into the guide for next year. And it seems as far as major projects coming online, it's more tried in, but that's very late '27, more '28 weighted. I know it's premature to ask, but just any other thoughts as we think about '27 when we are modeling it, the EBITDA.

Yes. Yes, we're going to avoid given previewing the 2027 guide for right now. But yes, I think it's important to note that some of those items that we experienced this year it's unlikely that we're going to see those again next year. Winter weather is always hard to predict, But we -- we're not going to budget a colder or more severe winter weather than we normally do. And then the commodity price uplift piece, that just depends on -- you guys all have your own commodity price deck, so you can put that in there. We'll give you the sensitivities that we'll have in the budget.

And let me just address growth for the longer term other than 2027. As David said in the middle of our budget process, we'll get through that. no concerns here about our ability to grow long term over the next 3 to 5 years. As you can see, we've got $14.4 billion in projects that will bring in quite a bit of cash flow. But it is true that because those projects don't come on evenly over all the years, the growth is not going to be even every single year. An example of that is try to -- only 30% of the contracted EBITDA comes on in 2027, because it helps to these items, it's going to be a difficult year to replicate. But the underlying business here, all of our underlying businesses here remain very, very strong. and the projects are going to deliver enormous benefits as they come online.

Our next caller is Praneeth Satish with Wells Fargo.

Congrats on incredible quarter here with project FIDs. Maybe just going back TGP 219 South, I guess we were a little bit surprised with the $1.5 billion CapEx estimate seems lower than we would have thought. I guess does that $1.5 billion get you all the way to 2 Bcf per day project? Or is that based on the 500 per day open season that you went out with, I guess, where does this project transition from brownfield to greenfield.

Well, it ultimately depends on the shipper receipt deliveries, right? I mean I can tell you if we scale to a 2 to 3 Bcf number, it would be higher than the $1.5 billion. we're really focused on, at this point, just a brownfield component. And then ultimately, we'll adjust accordingly with incremental volume at, and that's the way I would think about that.

Okay. That makes sense. And then maybe switching to the Permian here. So Permian Link adding another 2.8 Bcf per day of takeaway I guess how do you think about the risk of overbuilding in the Permian? I mean I know that you're protected on this project because of the take-or-pay contracts. But I guess I'm thinking more about some of the other pipes, some of your older pipes like Gulf Coast Express and when those come off contract, do you see any risk there on the recontracting side? Or do you think we're all too conservative with our Permian supply growth estimates here on the gas side and there's going to be enough gas to fill all these pipes? .

So here's, what I think, of both those types. Our intrastate system I talked about this on the last call, our Permian highway and GCX, They're in the heart of the demand centers that are coming and further developing. Our focus has shifted from -- to really focus on these demand pools. What we see there, especially across our P&P pipeline system is we see a power demand center forming. And so to the extent that there's any push pullback by any of the producers that are underpinning the project. We see demand pull. The same thing is out there in our Gulf Coast system. They were both of these pipes were some of the first flights both from a cost perspective. relatively low on the cost spectrum. And so what we see there is GCX. There's so much incremental LNG demand that is yet to come. And so I think we feel pretty good about that. And then overall our focus has been on market pull, right? And so we see those underpinned by long-term contracts. So from a portfolio perspective, we feel pretty good.

Yes. I mean point, we've got like 6,000 miles of intrastate pipe and 145 Bcf of storage and those pipes tie into that -- or part of that system and tie in to a lot of demand. And so we feel good from a demand pull standpoint that we can continue -- those pipes will continue to have opportunities. .

Our next caller is Manav Gupta with UBS.

Just for the record, we always viewed your claims of $10 billion shadow backlog very credibly. And you did say that the 2 projects add further credibility, even if they would not have been announced, we would have been very confident that your backlog would end over -- well over $10 billion before year-end. So I just wanted to put that out there. A quick question. I wanted to go a little to Trident. There's a lot of gas getting on the Gulf Coast and you have the ability to eventually move it around. So can you give us an update on what the Phase I and Phase II of Trident is looking like and how you'll be able to help other industrial companies and LNG producers by being able to move the gas around Gulf Coast?

Okay. Let me talk Trident is on time and on budget and shipping delivered in February of next year and Sital, you want to talk about the market?

Yes. So I mean, look, we've talked about this when we sanction the project. Trident, we saw a need -- there's an industrial corridor developing around Trident, both from a power perspective and then on the industrial side. But beyond that, we pull -- you get down to the LNG corridor and we saw the need to go from there further west to the Gulf Coast corridor we see incremental demand. And so that, coupled with our Texas Header, our KMLP header and the KMP expansions that we've got, we've got an ability to serve the Texas, Louisiana Gulf Coast, and we see significant demand developing there as well. So as Rich alluded to earlier, when you get these stems inside and you get ancillary -- and tertiary expansions off of [indiscernible] we feel pretty good about that, and we think we can help from the on the demand side as this demand development. .

My quick follow-up was a little bit just focused on the Florida gas market. It's a steadily growing gas market. If you could comment on it, and obviously, talk a little bit about your next phase of expansion at FGT, how that is progressing.

Okay. Well, I will talk broadly. As you know, we're not the operator of FTT, We'll let Energy Transfer talk about the details. But I will tell you this. We've been talking about this thematically in the Southeast. We see strong demand in Florida. We do FTT sanctioned a few projects already. We're obviously in discussions with other customers on future potential expansions. And we see the demand profile as being strong. And so I'll just leave it at that. And as you know, we're not the operator there. We work with the operator, but we feel pretty good about the asset as well. And it's not just SGT, [indiscernible] who also can help serve some of that growing market.

Our next caller is Jean Ann Salisbury with Bank of America.

Congrats on the great quarter. Can you speak to whether the anchor hyperscaler of Permian Link is planning to be online prior to when Permian Link starts and you'll kind of replace it as the gas source or if you're planning to ramp together and so your timing is basically linked to their timing.

Well, without getting into the customer details, I'll tell you, we are trying to accommodate multiple customers on this project. I mean we've got an anchor hyperscaler, but we had significant interest. We're also talking to those other customers I think the anchor tenant obviously is driving the need for speed. And I think 1 of the benefits that Permian Link brings to the power market we talked about before is the length of storage and the flexibility and reliability that helps these hyperscalers achieve their reliability. I think that's a real differentiator here. The next phase, we look at all of our storage facilities to see where we can kind of enhance service and flexibility, and that's what I think differentiates this.

That makes sense. And then building on Theresa's earlier question, do you anticipate all the gas that's feeding Southeast corridor like will it substantially all originate from Appalachia? And if that's the case, would you potentially require even more expansion than just TGP can provide?

Well, so look, 1 of the beauties of kind of the locations we picked is we've got access to multiple pipeline corridors, right, Tennessee, previously, we want to grow Tennessee, but we have interconnects with Columbia Gas. We've got interconnect with Tetco. We've got interconnects planned with several other major interstates there. And ultimately, those types also have forward haul backhaul capabilities. And so when you think about where the supply could come from, we've always said we need incremental molecules to move not just gas on gas competition. And so you basically could get a molecule from the Gulf Coast to that point via all of these major shrunk pipes, including Tennessee and then also from the [indiscernible] Marcellus, Southwest Utica, down to that point. And so it's multiple basins that can kind of serve that takeoff point. That's the beauty of it.

Our next caller is Brandon Bingham with Scotia Bank.

Wanted to maybe kind of go back to the U.S. Gulf Coast LNG dynamics. And in particular, as it relates to Permian and Haynesville as the supply source obviously, some puts and takes with both. But just with the rate of change in Permian gas here and maybe not the most favorable price [indiscernible] development. Just -- how do you see those 2 basins playing out in the fight for U.S. Gulf Coast capacity and who could be the primary driver there?

Well, we thought all along we believe it's going to be all of the above. You're going to need -- we see the demand profile that Rich started off with, it's significant. That's significant growth and it's going to take more than those basins to satisfy that growth. So we think there's plenty of resource. The key is going to be building that infrastructure in the middle, which we're really, really focused on. And then ultimately, the price will take care of itself.

Yes. And I mean if you look at what [indiscernible], I think they're pretty similar to our internal numbers. They've got Haynesville growing by 13 Bcf Permian growing by a little over 10% and Marcellus growing by 13%. So those are the 3 big producing basins that are helping to get that 46 Bcf of growth that we referenced between now and 2035. We need them all.

No, it's Yes, absolutely fair. And then just maybe quickly kind of going back to those Wood Mac numbers or just anybody who's kind of put together the longer-dated total gas demand picture, would be kind of curious to hear your commentary and perspective just around like a capture rate to Kinder Morgan of all of that. Like looking at the SNG, the comments that you've made in [indiscernible].

So I mean there's no science behind us other than we move about 40% of the gas in the U.S. market. And so we move about 50% of the gas in Mexico, 40% going to LNG and 45% of the power demand across the South. So I mean, if you want -- I mean, I think that's as good a number as any.

Our next caller is Keith Stanley with Wolfe Research.

First, I wanted to clarify the SEC projects you're sanctioning today, does that include the SEC extension line up to the Nashville area? And then if you could comment at all on the phasing for both FCC and Permian Link, they start up in the fourth quarter of 2030. When would you get to the targeted build multiple?

So yes, it does include -- SEC does include the greenfield line. And on Permian Link, it comes online -- and then on SEC, it comes on 2030, 2031 and 2032. That comes on over 3 years.

Got it. Second 1 on Western Gateway. So you're investing $250 million and contributing SFPP for your interest and PSX, I think, is constructing most of it. How does risk sharing work in that JV for the investment in the event there were cost overruns or delays there in construction, would you have to fund your share of that? Or is there a separate mechanism given how you're contributing to the JV?

Let me say a couple of things on that. One is, I think we're being very prudent about how we're approaching this project in terms of spending capital until we get more comfort around the ability and make sure we're very confident that we can get built through the states that this has to get it through. And then secondly, what I'll say, and I'm not going to go into a lot of detail about it. But -- there are -- we do have certain cost protections against cost overruns on that project.

Our next caller is John Mackay with Goldman Sachs.

I wanted to pick up on kind of the general tone of this. And Kim, you answered it a little bit and certainly, the backlog increase is a bit of an answer but there has been at least a perceived kind of slowdown in kind of broader contracting activity some volatility in the markets. I'd love just to hear from you guys, like, has the tone with customers changed all that much over the last couple of months, compared to, let's say, earlier this year.

No. I mean, we haven't seen a change. I think our customers continue to engage, and we continue to look for opportunities. I think they see this as we become an increasingly globally connected market. I think there's been more focus on how to handle some of the volatility through our storage assets. And so we've just seen the dialogue continues. It's been good.

That's great. And then when we look at the implied returns on these new projects being sub 6x or if you look at something like the billion CapEx per Bcf of capacity numbers kind of going up over time. Can you just touch a little bit about kind of customer willingness to kind of take some of these higher implied rates? And what that means maybe from looking at a kind of producer side versus the demand side customer?

A couple of things. One, I think what you're referencing is the cost per pipeline mile or whatever has gone up, and that's largely -- that's going to be a function of a couple of things. One, steel prices with the flash pipe prices have increased compression costs have increased. So that's what you're seeing in the cost numbers. We have not seen customer pushback in terms of -- I mean we didn't change our return thresholds, right? We're still targeting the same return thresholds. And so -- we haven't increased those or decrease those. And again, they will vary with risk and return. But we have not seen a lot of customer pushback as a result of the increase in the materials cost that we've seen.

Just any comments on kind of customer mix in terms of producer willingness to engage versus the demand side?

Well, generally, the projects that we're expecting to the -- I mean, well, all the projects we're sanctioning today are demand pull. And that is our preference when we do these projects because I think that demand can be -- basins can come and go to some extent, some of them have been there for a long time. But the demand pull it is there for decades. And so we feel very good about the customers on these projects.

Our next caller is Spiro Dounis with Citi.

I want to start first with project timing. You talked about adding cash flow after that 2032 time frame, but it sounds like you're still filling in some growth for 2019 and 2030. Kim, you also mentioned a $4 billion spending cadence from here and -- on my math, TGP 219 South should pretty much get you to that level once it's FID. So I wanted to understand how you're thinking about, I guess, what's needed to fill up more growth in 2019 and 2030 or if we should expect most of the major project announcements from here beyond TGP, of course, maybe to be more weighted or added it to 2030-plus time frame?

Well, '29 and 2030 is, we're getting SNG -- South System 4 is coming online. 2028 and Q4 of 2029. So that will drive growth in 2019 and 2030. In -- so -- and then I think MSX is the second phase midyear 28. So that will drive additional growth in 2019. And then these projects, you'll get fourth quarter probably, roughly, you'll get the Permian Lincoln. So -- as I said, it's not going to be exactly the same growth rate every year. It will vary year in and year out. But at -- with this backlog and 5.7x multiple, that's $2.5 billion of cash flow that will be coming our way as soon as we get these things built because these are, again, backed by take-or-pay contracts with either credit or the entities or that have significant collateral posted.

Got it. Second question, talked about Trident, but I want to go to the other side of the Permian and go to Arizona. Hearing more on the utility side about maybe the potential need for another pipeline, just given some utility plans in Arizona, West Valley and some data center development there. you, of course, had Copper State Connector at 1 point. Just curious about maybe the prospects you see to make another move into Arizona.

Well, look, I mean, on the Western side, we do see opportunities. We have both of our legs pipeline growth in Arizona in Mexico. And I would caveat, I would characterize it, as we do see significant power demand area. We also see traditional conversion, coal plant conversions as opportunities on the western side. But it's too early to comment on kind of where and how those we do have discussions ongoing out West as well.

Our next caller is Gabe Moreen with Mizuho..

I'm not sure if it's allowed, but I'd like to ask some questions on your nonnatural gas businesses. One, I was going to ask, just with the forward curve on crude oil have moved up nicely here in '27 and beyond, whether that puts some CO2 expansions back into play potentially? And then also, I think there may be some inorganic opportunities out there on RNG. I'm just curious your thoughts on potentially expanding that business as well.

Gabe, thank you for [indiscernible] Yes. No, as you know, EOR projects take some time to develop, right? So and the curve has come up, but it's still pretty backwardated. And so I would say, yes, we're looking at all of the projects that we can do and our ability to accelerate, but it's really no different in terms of how we view investment in that business over time. It's going to be looking at that curve and will be stentizing that curve as well. for lower oil prices in case those arise as well. Obviously, the oil price is there's a lot of geopolitical risk associated with that. And so there is some concern to extend the war ends, where crude prices end up. But we're pretty careful in terms of how we look at our investments and we demand higher returns than we do on [indiscernible] businesses for -- to take account of that risk. .

And then on R&D, I don't think we can really kind of talk about ongoing third-party processes. We're aware of those out there, and we'll continue to kind of look whether it makes sense to grow that businesses. We've had some operational issues in that business. I think we'll be careful to the extent that we want to step into a bigger show there, and we'll have to come with a higher return as well.

The other thing I'd say on the RNG business, I mean, we did have to struggle, but we do have a team that has learned and who knows how to operate these at this point. So I think we've developed some expertise there. But we also have a lot of lessons learned, but we would take into account anything we look at. And then I mean to Antony's point on the CO2 stuff, I mean, when we look at those, those are long-term projects. And so we tend to run some kind of fixed oil price to make sure that we get to our returns. So we don't just jump because the current year goes to 80% of projects because the current year goes to $85.

And if I could just squeeze 1 more on the Bakken. I'm just curious sort of on a double. And how rigor update? It seems like there's some shifts going on there in the G&P landscape in the Bakken. Just wondering if that makes you more or less inclined to invest more capital up there? .

Look, we've invested significant capital up there. We've got -- I think we're pretty well positioned for what we see coming. And we can always adjust if we see the macro environment change a little bit. I think where I would take it is we're sitting in a good spot. We've got the infrastructure we need to accommodate any growth that might.

Our next is Zack Van Everen with TH Research.

Maybe back on gas supply, whether it's Waha, the Gulf Coast or the Southeast, it definitely feels like there's a fight for gas. As a part of any of these projects, have you helped customers or was it contingent on them also signing supply agreement with producers just to make sure they could fill their FT.

The answer to your latter question is no, we don't do anything contingent. But I mean, look, we explained the macro environment, they have to make their own judgment. I think there's plenty of resource -- it's a price function. There's a dry gas window. There's an associated gas window and then there's other basins in and around that can help meet the demand. It's -- once again, assumptions supply and demand and there's other business that can feed through our networks and ultimately get in to serve the pipelines that we have from different areas, for example, the Eagle Ford can go the other direction as well. So that's how I would leave it. I think it's broad enough. I think folks understand that there's -- they need to see a molecule. I think we make sure that's clear, and the rest invested that. .

Got it. That makes sense. And then maybe a quick clarifying note, when you mentioned the 200 gigawatts in the Southeast equating to about 8 Bcf a day. Is that a risk number because it feels a little lower than the general 150 MMcf a day per gigawatt that most people use.

Yes, I can -- I mean, we -- I just -- to keep my mindset that inefficient plants beneficial plans.

And look, that probably likely will all happen, right? That's all the connection requests, assuming they all go, and that's all natural gas. And so it will be some combination -- the point is there is a huge amount of demand growth in the Southeast, and that's part of what Southeast Connector is addressing.

Our next call is Jason Gabelman with TD Cowen.

I wanted to ask about Permian Link and your kind of targeted IRRs. You've you talk about kind of, I think, mid-teen after-tax IRRs. And I wonder, given this project with only 1 anchor shipper has some perception of higher risk did that require you to kind of construct the project for a higher IRR? Or do you feel like the risk profile of this project is similar to your existing business?

Look, we approach this project the same way. We approach all of our other projects. And so what I'll say is this, which is can move up and down on the risk return threshold and our value proposition, meaning that if a customer is willing to share in some of the cost then we can move down the return threshold a little bit if the customer is not willing to share in cost overrun, so we need a higher return. And so we have some flexibility in how we arch that -- and then as we negotiate our customers at times, have a preference between, hey, I don't want to cost share. I want you to take the cost risk and -- and that's 1 rate, and we put them on rate. And then if they want to share in the cost risk, there's another rate. The other thing I'd say is Permian Link, it has the ability to upsize by adding compression. And so we can add more shippers to this over time. And that will lead to even higher returns.

Yes. It's important when we talk about the scale of this -- I mean, the scope of this project, we have capabilities to serve incremental. And we're talking to incremental customers to basically fill the rest of the basket, if you will.

Got it. My other question is a bit separate. As you kind of pursue connectivity to move more gas from the Marcellus. I'm wondering if there's anything to be gained to move further kind of upstream into Marcellus -- would you get anything? Is there any commercial value for controlling more of the gas upstream from your pipes or not really at this point?

I mean, look, we have some pretty good customers of our own that are very sophisticated in doing that. And I think we stick to what we do best, which is build large-scale infrastructure, very similar to the Power story. We're not focused on power -- we're focused on building pipeline infrastructure. And so I think we would collaborate with to our customers to do that. And I think that's probably the best part for us.

Yes. And I think there's a very established players very established mature players in that. And so typically, they're going to have an incumbent advantage.

Our next caller is Harry Mateer with Barclays.

Both Southeast Connector and Permian Link are being developed at JVs. I'm curious how you plan to balance contributing capital into those JVs from KMI, at least initially versus using what I think appears to be pretty decent balance sheet capacity, both those JVs during the construction phase.

Yes. I think it's going to be a combination of the JV funding a portion of it and us contributing in capital. So I think those JVs have nice cash flows that can go to find a portion of the CapEx. We can take on incremental debt at those JVs. If we do that, though, our plan is to do it in such -- well, we will do that, but our plan is to do it such a way to maintain the existing ratings at those JV pipes. And then there will be some capital required above that, in which case, we will make equity contributions from owners. And so now if we also have the flexibility given where our balance sheet is and our cash flow that if we wanted to or needed to, we can fund that 100%, we could fund that CapEx 100% from KMI.

Mr. Kinder, at this time, we are showing no further questions, sir.

Okay. Well, let me just conclude with 2 -- again, I want to say -- and Kim mentioned this number that if you look at the returns expected on this $14.4 billion of backlog. That's $2.5 billion of additional EBITDA. And if you look at that in terms of where we are presently, that pushes us between $11.5 billion, $12 billion of EBITDA. The other thing I would mention is, last call, there were some let me call it skepticism about whether we could really bring these projects along. And I think I made the remark, well, we have to get the horses in the corral. I just want to say, we've got a hell of a lot of those horses in the out with the saddles on but we got more horses just outside the corral. And I think you're going to see them and they want to come in -- that will be the message for the future. But thank you all for your good questions. We appreciate it's been a great quarter, and we hope to bring you more good news in the future. Thank you.

Thank you. This concludes today's conference call. You may disconnect at this time, and have a great rest of your day.

Okay. Great. We're continuing our midstream fireside chat here. Very happy to have David Michels, CFO of Kinder Morgan, joining us. David, why don't you give some opening remarks on the company, please?

Sure. First, thanks for having us here, Keith. Appreciate it. Good set of meetings so far. Looking forward to the rest of the day. So as we'll talk about more during this meeting, this is a pretty opportunity-rich environment for midstream companies, natural gas infrastructure development opportunities are as strong as we've seen in decades. So it's creating a lot of interesting opportunities for us for additional growth. Our base business remains very solid. We'll talk about the full utilization of networks across the space, which has led to the ability for us all to capture additional value when we see periods of time of disruptions, weather events.

And then on top of that, these new opportunities to satisfy growth in the LNG space, growth in the power generation space is allowing us to add projects and grow additional -- add additional EBITDA on top of our base business. So it's a great place to be right now, and it's very exciting. So we're pretty enthusiastic about the outlook for the company and looking forward to the conversation to get into that a little bit more.

Great. So maybe we could start high level. I think about a year ago now, you put out a $10 billion shadow backlog. You talked to $3 billion plus per year of CapEx. I think you've sanctioned about $2 billion of projects since that time. How are you feeling on executing that shadow backlog and the ability to get to a $3 billion-plus CapEx type profile over the next 5 years or so?

Yes. So first, let me just remind everybody what -- so our project backlog is -- because everybody defines it a little bit differently. Our project backlogs are projects that have been sanctioned by the Board. They have binding contractual commitments with offtakers for, in most cases, north of 90% of the capacity for the infrastructure that we're building. And so they are real projects. In most cases, they're under construction. So we're highly confident that those are going to be brought to market and add to the EBITDA of our business.

The projects that are outside of that in this shadow backlog have not yet been sanctioned and are not as certain. But in this current environment, we're continuing to see very strong interest in new infrastructure development, and so we feel pretty confident given where we are in the negotiations and how the shipper conversations have progressed that we will continue to see more projects being sanctioned to at least replenish the projects that are being put into service in the coming quarters. We talked about in the second quarter that $1 billion plus would be sanctioned between -- at that point, second -- that point was July until through the end of the year. I think we'll -- I think we're pretty confident we're going to see that happen and maybe even some more.

What gives you confidence on the $1 billion plus? I mean, you have contracts in hand that are just getting finalized? Or how do you have visibility you have over $1 billion of projects to move forward before year-end?

We're working on multiple projects at the same time. Some of those are smaller and don't get the public attention, but those are likely to contribute to some degree to the $1 billion plus. And then we have a handful of larger projects, some that have gotten some publicity that are in various stages of development, but a couple that have progressed to a point where it feels more likely than not that we'll see one or two of those get sanctioned between now and the end of the year.

Some of your projects, so obviously are feeding a lot of utility demand centers that -- and a lot of the utility demand growth is driven by data center build-out. Are you seeing any pause in your conversations with utilities on what their gas needs might be, just given some of the uncertainty on the data center development and the ultimate power demand growth?

Not really. It's certainly been a topic of conversation with us and the shippers, but the order of magnitude of the demand that we're seeing in certain areas is so large that even if there is a little bit of pause or postponement in some of the development of data centers, the underlying power generation growth is still there, and these projects are still going to be needed at some point. And so we've had some conversations, but they really haven't paused the development of the specific contractual arrangements that we're talking about.

Okay. Do you see a scenario -- I guess there is a scenario though where the utilities -- so the utilities are going to procure the gas for their power needs. You're contracted on that. So from your end, that's done. And then if the data centers are slower to develop, from your contractual perspective, you're locked in anyway on your investment.

That's right. Yes. That's how we go about trying to protect ourselves in these situations. And the utilities have -- and again, this is speaking to the point that I just made, have a big enough demand pull on their grid that even if you have one or two of these data center development facilities that get postponed or don't get developed at all, we're seeing not just data center development, but you're also seeing population migration, electrification of certain industries, industrial demand that are all contributing to additional power generation needs in these utilities grid. So I think that's helped facilitate these conversations even though in some states, there have been some pauses in data center development or some conversation about pausing data center development.

Maybe we could go to some exciting news two weeks ago, you put out this open season with Southern Company on the Southeast Connector for the SNG pipeline. You only put out two weeks ago, it already ends next week, I think. You have one customer in place based on that document. Can you talk to the strategic drivers of this project? And in particular, you're already expanding SNG. I don't even know if you started construction on SSE 4, but that comes on in 2020 -- late '28 and late '29. And now you're doing an open season for yet another expansion of the SNG system. So talk to some of the drivers for that project and what you're seeing in the Southeast.

Right. So when you look at all of the utility -- or some of the more major utilities in the Southeastern states, Southern Company with Georgia Power and others, Dominion, Duke, FP&L, TVA. If you look at their large load connection requests, it combines to north of 200 gigawatts, north of 200 gigawatts across all of those utilities. And that's 40 Bcf a day if it was all gas and all got developed. If you look at those that are in advanced stages or in executed contractual positions, that's north of 50 gigawatts a day. So again, a very large amount of power generation growth in those Southeastern states.

So yes, we're already building South System 4. It's well underway. It's currently on budget and on schedule. Haven't actually started construction on it yet, but we're in really good shape. We've got our permit and are working on the right of way, securing right of way right now. But the utilities are seeing so much additional power generation demand that we're already working on ways to solve the next wave, and that's what this connector project will help achieve. And it's just one part of the puzzle, right? It's just one piece of the puzzle. We're going to need connections north of it and potentially south of it, and we'll see how that grows. But we're pretty excited about this. The open season is going well. You're right. It's a relatively short open season, closes on October 7. So we'll have a lot more information to talk about on our earnings call, but it's going well so far.

Okay. You could be prepared to give an update on this by the earnings call based on the open season results.

We'll have some more detail to provide at that point. Don't know exactly what that's going to look like, but we'll definitely have some more detail on it.

I guess if the utilities are really going to develop, you said advanced stages is over 50 gigawatts.

That's right.

I mean it's not all gas, but if that was all gas, you're talking 8 Bcf a day or something like that actual gas demand in the Southeast.

Correct.

Okay. That's a big amount of gas. Okay. So it sounds like Southeast Connector is from a customer perspective because it's the SNG system, you would be targeting multiple utilities as part of this project that you could serve their needs for. It wouldn't just be one utility.

Without getting any detail, absolutely. We'd be looking for multiple counterparties and utilities would be the preferred way to for us to play it.

Any sense time line-wise on how long a process like this takes to kind of get to a final investment decision from where we are today with the open season?

No. Every project is different. Every project has its own considerations and potentials for delay. So I really don't have anything to add on that front. I know that's totally unsatisfactory, sorry, Keith.

Any questions from the audience on Southeast Connector?

What's your threshold for that 50 gigawatts to advanced stage? What's the threshold for advanced stage?

That's really just reacting to what the utilities have put out in their resource planning. And so everybody defines it a little bit differently. So TVA's advanced planning may be different than a Southern's, but we kind of try to bucket into the very likely, it seems like, and that's what that 50 gigawatts appears to be is likely development.

[indiscernible] I guess this is one. Can you keep it -- is this like once you do this investment to it, is it kind of like full capacity? Or are there other additional expansion opportunity?

Great question. I think there are additional expansion opportunities. So we're building South System 4 right now. There was 1, 2, 3, now 4. We've talked about a 5, this connector project may feed some of the expansion need in that area. But yes, I don't think that SNG itself is done with its growth. We've got a lot of growth coming in that corridor right now. So maybe for right now, it's satisfied, but...

And then for funding it, would you consider that new [indiscernible]?

So for the way that Kinder Morgan is positioned, we've got enough cash flow from operations where we would prefer to fund our capital through our cash flow first. We have some spare capacity on our balance sheet. So we would likely next look to that because we have so many projects that we're building, our leverage is likely to decrease once we get a number of these projects online. And so we think we're going to have spare capacity in the next few years.

So between now and then, we would prefer to continue to just fund internally. To the extent that we're funding projects at a JV level like at SNG or NGPL, we would prefer to just provide our equity contributions into those JV facilities using that cash flow and spare capacity on our balance sheet.

To speak to the size of what that looks like, we can fund about $3 billion, $3.5 billion a year of growth capital investments from our cash flow from operations. And on our balance sheet, we're currently at 3.6x debt to EBITDA. Our long-term leverage target is between -- it's a large range, but it's a range between 3.5 and 4.5x. So the midpoint is 4. And I think if we were to use capacity up to 4, that would provide another $3 billion, $3.5 billion worth of capacity.

So in any individual year, that could be $6-plus billion, $6 billion to $7 billion of total capacity for growth projects. So I don't think we're going to need any external capital. But if there was an acquisition or something that came at the same time as some of the funding -- the heavy funding years for some of this growth capital that might put us in the position where it might make sense for us to do something like that.

What about on that [indiscernible] obviously, pipeline is not their core business. Obviously, they have a lot of growth in themselves. And if they were to consider divesting the stake in that pipe, like do you guys have a right of first refusal on that? Or how does that work?

We -- I don't know exactly what our right is in our JV agreement. So -- but if they were interested in divesting that, we would be very interested in talking with them about it. And it would just depend at that point on a price. But I will say this right now, I don't think Southern Company is interested in divesting their stake in SNG. I think it's a very valuable piece of infrastructure, and they recognize that.

An excellent balance sheet [indiscernible] in long-term rates being as [indiscernible] as they have been, like are making long-term investments, underwriting cases and the rates moving and spreads moving in general, does that change? You guys start to bake in any of that in your underwriting or your necessary returns? Or how do you think about that?

Yes. Every year, we look at our cost of capital, and we update our -- as needed, we'll update our return requirements to reflect the appropriate cushion between our cost of capital and the required return. It hasn't moved enough yet to actually adjust -- to force us to adjust our return requirements. And so currently, our return requirements are pretty consistent with where we've been.

We have seen the cost of debt come up, but we've seen our cost of equity offset that to some degree. And so we -- on our overall weighted average cost of capital, we're in pretty good -- pretty consistent shape with where we've been.

As interest rates continue on the trajectory that they've been on, then that might change things. But we have a very large cushion between where we're requiring our returns to come in and where our cost of capital is. And so that also gives us a fair amount of cushion before we actually have to formally adjust where the return comes out.

Just a quick question on petroleum product pipeline business. Obviously, the diesel having gone through the roof and additionally, [indiscernible] are sold out. It is clearly going to be some innovation and substitution moving around, I think, in the end markets, certainly more outside the U.S. [indiscernible] U.S. How do you guys view the volatility side of the end markets you don't have control over, or which could have flow back into the long tail of intrinsic value of those [indiscernible]?

Right. Well, we think our main business is natural gas and transporting and storing natural gas. And we think that's the hydrocarbon, the fossil fuel that has the longest lead time. So we're pleased to be in that business. Between 60%, 65% of our business is natural gas and even more of a percentage of that is where our growth investment capital is going into. So it should continue to increase as an overall percentage of our portfolio. And we're pleased to see that because as you're right, I think there are going to be some -- I think there's going to be a near-term potential impact on domestic demand for other hydrocarbons, especially in certain parts of the country.

As it relates to our business specifically, where we have refined product pipelines, which are gasoline, diesel, jet fuel, those assets have a regulatory regime around them that if you see volumes come down a little bit, you can adjust the rate in order to kind of keep your revenue pretty flat or maybe slightly growing even. So we have some built-in protections there, but it's something we talk about. Our internal projections suggest that there's little decline in that -- in the volumes that we expect across our footprint, actually a little bit of an increase for the next -- I think it's 1.5 decades, maybe 2 decades before we start seeing that level off and then potentially decline a little bit.

And the increase is mostly coming from jet?

Gasoline, and I think jet stays increasing a little bit. But for us, our main product is gasoline. So that's where we're focused on. But you're right, jet doesn't seem like it has a decline eventually. It looks because there's just not much of an alternative. And the gasoline impact eventually it looks like it's more hybrid related than pure electric vehicles. It seems like that's where the demand has really materialized that in efficiencies of ICE vehicle engines.

David, maybe we can go to the Tennessee Gas Pipeline open season, the 219 project, and that's closed now the open season. Any sense of how demand came in on that? I think you were soliciting around 500 million cubic feet a day. Just any update on demand for that project?

Yes. So this is our TGP 219 project, which, just over 0.5 B a day of demand within the open season. The open season was very, very positive. It was a favorable open season. It was nonbinding. And so it will take a little bit of time to go back and solidify shipper commitments and so forth. But the open season results were very strong and positive. And so we'll see where that goes eventually. But it's -- there's definitely a lot of demand there. So this moves -- this would move gas out of the Pennsylvania area to Tennessee. And so -- and we would expect that we would have demand to potentially feed power generation demand along the way. And it's just another piece of the puzzle to solve the incremental demand for power generation load in that part of the country.

And the company has talked about potentially a larger expansion of Tennessee Gas Pipeline, which could feed into the Southeast. How capital efficiently can you do that and go above the 500 million cubic feet a day? And kind of what are the limits on how big you could go on a TGP expansion pulling gas out of Appalachia to the Southeast?

So I'm not going to comment on the specific upper threshold because I think it's going to depend on the amount of the rate that shippers are going to be able to bear because it's not a cheap expansion to go much higher than the one that we had in the nonbinding open season. And so -- but it could be multiple times the 500 million.

Multiple times 500 million cubic feet a day that you could eventually get to?

Right.

Okay. Interesting. Any other questions from the audience? Okay. So beyond -- I guess we've -- well, one follow-up just on the Southeast piece. You've historically talked about expanding Mississippi Crossing, which will bring gas from the West from TGP into the SNG network. Is that project still something that you're actively assessing to bring gas into SNG? Or is the new Southeast Connector taking kind of a different approach on how you source gas into the Southeast?

It's something that is not going to be as focused as much for now. I think for right now, the connector is going to be a priority, but it is something that we've continued to have at least early-stage conversations with potential counterparties on it.

Okay. And then beyond kind of bringing gas out of Appalachia and then bringing it to demand in the Southeast, maybe you could talk about what other areas of your footprint you're seeing growth, whether that's Florida, the West, Upper Midwest even? Just other areas you're seeing growth across your footprint.

Well, one area that we're seeing growth in is Texas, power generation demand, LNG demand still and then, of course, demand for additional supplies to reach all of these different markets. One of the projects that we've talked about publicly is this Permian Link project, which would be feeding demand in the Panhandle, a little bit in New Mexico, maybe reaching into Oklahoma. It would be an NGPL project, and it's gotten some really good traction, I would say, it's not in our backlog, but it's something that I think we have some real demand to feed power generation, and those negotiations are going well.

How does the new WhiteWater pipes because WhiteWater kind of went big and not one pipe, but we're going to build two monster 48-inch pipelines out of the Permian. How does that impact discussions on doing a project like Permian Link where you're pulling gas out of the Permian?

Right. Great question. This one is uniquely positioned, I think, because it's a demand pull project. It's not a supply push. So we think it's relatively insulated from an impact from Solitude.

M&A?

The other piece -- I'm sorry, one other key comment there is because NGPL has some well-positioned storage, I think that's also an added advantage for that project relative to pipelines that are just pulling out of the Waha area.

I wanted to ask on M&A. I mean, the company seems to do smaller tuck-ins, it seems maybe every couple of years or so. How important are acquisitions as part of the strategy from here? And is that part of what you want to accomplish over the next 5 years to try to further build out the platform? Or is that less of a priority because of all the organic growth you're seeing?

I think I view acquisitions in this environment that we're sitting in, and I think it speaks to the latter point that you just made as just bonus as extra because the opportunities that we have to build organic projects and build these new infrastructure projects across the country are adding nicely to our bottom line. To the extent that we can also execute on some acquisitions that are accretive to the company, I think it's just bonus. And we have had some really good opportunities here recently in the last 5 years to make some acquisitions that have made a ton of sense.

As you know, we don't really compete well on acquisitions just from a cost of capital standpoint. So the acquisitions that we've achieved are those that have integrated into our system really well. The NET Mexico acquisition in South Texas, the Monument acquisition that we did this year in the Houston area that integrates into our Texas intrastate footprint, allowing us to serve our customers more efficiently, provide more options to our customers. Those types of acquisitions are really nice because it's not eating into the balance sheet capacity because that comes with real-time cash flows. And in most cases, the reason we are successful in those acquisitions is because we're able to add certain commercial synergies by combining our 2 systems. And so it gives us better opportunities to serve our existing customers and maybe serve the customers on the acquired assets more efficiently or more effectively.

Any last questions from the audience? Okay. Maybe -- we've talked a lot about projects and future growth. I mean I don't want to overlook. The company has actually had a really great year performance-wise. You're well ahead of your budget. There's some kind of debate a little bit of how much of that is more onetime-ish based on market conditions this year and how much you see as repeatable into the future? How would you characterize that and the amount of outperformance this year?

We've had in the neighborhood of $225 million of kind of onetime nonrecurring business this year, and that's the FERC -- sorry, the fern cold weather storm in the wintertime, plus some extended cold period that we enjoyed in the Northeast area. We had some FERC retroactive billing relief, a contract buyout in our terminals business, the Waha blow out -- the Waha basis spread blowout.

Those are all what I would characterize as nonrecurring necessarily. I mean some of those things like cold weather, you could see that from time to time. You could see basis points blow out and the spreads blow out, especially in today's environment where these natural gas pipelines are full. And so if you have disruptions from period to period in geographies, you have a great opportunity to see additional margin as a result of that. But as it relates to our actual outperformance this year, it's been about $225 million that we don't -- we wouldn't put into our budget for next year.

Plus we've had some commodity price benefits from the Iran war. We don't have a lot of exposure to commodity prices, but our budget was for $60 oil, and we've seen year-to-date average north of $80 per barrel. So $20 per barrel swing, it makes an impact, and we estimated around $100 million for us. So kind of $325 million or so collectively that some of that is commodity price, and we'll see what the forecast looks like next year.

The rest of that outperformance, though, has just been market conditions, and we think that those market conditions are largely contributing -- or should largely continue into next year. Our ability to generate additional margin on our Texas Intrastate business, our ability to recontract capacity in our interstate business, higher rates, greater volumes, provide additional services to our customers. I think those are the things that we should see continue into next year. We've had some additional outperformance on our CO2 volume side as well. I think that was a little bit more questionable whether or not that will continue to next year, but really good outperformance in that area, too.

Great. We'll leave it there. Thank you, David, for joining us with us.

Thank you.

Good morning, everyone. Thank you so much for joining us. My name is Theresa Chen, and I'm the midstream and refining analyst here at Barclays. It is my pleasure to introduce our next company, Kinder Morgan. With us from Kinder is CEO, Kim Dang. Welcome, Kim.

Thank you, Theresa. Nice to be here.

Thank you very much for being here. There is quite a bit happening across your footprint. We're going to go segment by segment effectively, but maybe beginning with the natural gas side of things. I want to begin with a discussion of your project commercialization plan through year-end. As highlighted in the second quarter earnings, you expect to sanction at least $1.4 billion in new natural gas projects by the end of this year. Would you be able to provide any color on these late-stage opportunities and how they could strategically enhance Kinder's broader transmission footprint?

Sure. So let me start by saying that the natural gas segment is about 2/3 of our business, and it is the area where we expect the most growth. So as you said, on our second quarter call, we talked about at least $1.4 billion of projects. And just so that -- to give a little background for people, at the end of the first quarter, our backlog was about $10.1 billion. And then it reduced in the second quarter to about $9.6 billion as a result of projects that we put in service.

And so what we said -- and for the balance of the year, so the back half of the year, we expect to put another $1 billion of projects in service. And so what we said is that we think that we will at least get back over $10 billion in our backlog by the time we get to the end of the year. So expecting the backlog to be $10 billion or likely more by the end of the year. And I think it's important also that people understand a lot of different companies have backlogs and GE has a certain backlog. Our backlog so that people understand what it is, is approved -- Board-approved projects. And generally, 90% of them are backed by take-or-pay contracts, the ones that are in our CO2 business and some smaller gathering projects that have dedications as opposed to take-or-pay. And generally, those types of projects have higher returns. So these are projects that we are moving forward with.

But I think the reason that we have so much confidence about adding projects to the backlog is just a result of the environment that we're in and all the opportunity set that we're working on. The opportunity set that we're working on that's not in the backlog is like $10 billion. We won't get all those projects, but we'll get our fair share. And it's really driven by the growth in the natural gas market. WoodMac shows that the natural gas market is going to grow from like 115 Bcf a day, almost 115 Bcf in 2025 to like 160 Bcf by 2035, like 46 Bcf a day of growth in the natural gas market, primarily driven by export LNG and power. The export LNG number is like 23 Bcf and the power number is like 17 Bcf.

And so that's just driving enormous opportunities for us. A lot of those opportunities are across the Southern United States. The $10 billion is composed of some really big projects and then a lot of singles and doubles kind of like our existing backlog is today. But the growth combined with the asset footprint that we have, the 80,000 miles of pipe, we serve 40% of the natural gas demand in the United States. We move 40% of the volumes that go for export LNG. We move 50% of the exports to Mexico. Those 2 things combined, the nature of our footprint and the tremendous amount of demand is what gives us so much confidence that we'll be able to replenish that backlog over the course of this year.

That makes sense. And I mean, I'm happy that you touched both on the macro outlook for natural gas as well as defining what backlog means to you because understandably, Kinder's backlog is sanctioned bona fide carved in stone, and that word means different things across your competitors. So as these late-stage natural gas opportunities materialize and move into the sanctioned backlog and looking at that sanctioned set of projects in general, how should we think about the impact to your medium-term earnings growth trajectory?

Sure. So what we do for people is on the backlog, we give them a multiple, right? And so if you look at our backlog, 90% of it roughly is in these take-or-pay type of contracts, and that's the ones we put a backlog on. So $8.2 billion or $8.5 billion of the $9.6 billion is associated with those type of projects, and we have a 5.6x multiple on those. The $1.2 billion of other projects is gathering and processing and also the oil and gas production in our CO2 business. And those projects actually come at higher returns than the 5.6 multiple. It's just that the nature of that cash flow is that it increases and then over time, it begins to decrease. And so you get more of your return upfront. So actually, the upfront multiple on those projects is even better.

So to make it simple, just take the 5.6 on the full $9.6 billion, that's $1.7 billion of incremental EBITDA that we expect and the average in service on our backlog is really the first half of 2028. And so those projects will largely contribute growth, some in '27, but a lot more in '28 and in 2029. As we add projects, that will extend out that growth because as you add projects and they are FERC -- a lot of them will be FERC regulated. They'll take a couple of years to get permitted or 2 to 3 years probably to get permitted and come online. So it will extend out. So the projects that probably are in the -- the projects that are in the at least $1.4 billion are going to be things that come in online and service in the end of 2029 and into 2030. So what it does is it extends out the growth trajectory that's coming from the growth backlog.

Just by nature of the time it takes to bring these projects to fruition and when they will actually contribute earnings certainly. Now understanding that the vast majority of your business is insulated from direct commodity price exposure and largely indirect as well given the volumetric commitments or cost of service nature of the contracts. But for your supply push assets, even if they themselves are not bearing commodity risk, I am curious as far as your customer discussions with your producer customer base as they frame their own expectations into the next year against the backdrop of sustained commodity price volatility. Curious to hear, from a volumetric perspective, where do you see the most near-term growth potential across your diversified footprint given this commodity price outlook?

Sure. So if you look at our gathering assets, our gathering and processing business is about 9% of Kinder Morgan overall. So as you said, not a huge driver of growth. But the -- and natural gas is like 90% of that. So 8% of the 9% is all in natural gas. And it's largely in 3 basins. It's in the Haynesville, it's in the Eagle Ford and it's in the Bakken, are the 3 primary basins where we have the gathering. And certainly, that is going to be a tailwind for us. If you, again, go back to WoodMac and the 46 Bcf a day of demand, where is that supply coming from? And that supply is projected to come from 3 primary basins. It's coming from Marcellus/Utica, which is like 13 Bcf a day. It's coming from the Haynesville, which is about 13 Bcf a day. It's coming from the Permian, which is roughly 11 Bcf. Those are the 3 primary, but then they also have the Eagle Ford growing by like 4 Bcf or 5 Bcf, I think.

And so if you overlay that with our footprint, our biggest gathering position is in the Haynesville. We've seen big volume increases over the first half of this year in the Haynesville and expect with those demand -- the growth numbers that WoodMac is projecting for that to continue over the near term, medium term. The Eagle Ford will benefit from that growth as well. And then in the Bakken, that's primarily an oil play. We expect oil volumes to be relatively flat. But because of increasing GORs, we expect that the natural gas volumes will continue to increase. So definitely on the 9% that gathering, we see some nice tailwinds there.

Okay. That's very comprehensive outlook and answer to my question. Thank you. Okay. On the transmission side of things and turning to the unsanctioned backlog. I want to ask you about TGP. This is a critical corridor, key asset within your system, critical corridor for not just Kinder, but producers and consumers at large. Your proposed TGP expansion following the conclusion of the nonbinding open season in August, a, can you elaborate on the strategic benefits in general of this project? And how observed customer demand, how did that come about compared to your initial expectations given the competitive landscape?

Sure. So what Theresa is referencing is an expansion on TGP, which would take volumes from the Marcellus/Utica sort of in Northwest Pennsylvania and move them south down into Tennessee for near Nashville kind of is where the delivery point is on that. And it would be a little over 500 million cubic feet a day is what was open season. It is not binding. We got tremendous interest in that. Really, the play here is -- the Marcellus/Utica right now is constrained in terms of getting gas out by pipeline, lack of incremental pipeline capacity. And I think ultimately, most of that gas is going to need to come south. I mean there will be some -- expanding north is difficult. And there's some small incremental expansions here and there to the north, but really to get the level of supply out that WoodMac suggests, you're going to need expansions coming to the south to get that 13 Bcf a day out of the Marcellus/Utica. And so this is a project that would start that and would get 500 a day. It really goes into Tennessee. So it's intended to serve power plants that are in Tennessee, Kentucky, West Virginia largely, potentially Ohio. And so that's really the driver of that demand.

And so right now, what we're doing is we're following up with all the parties that bid in the nonbinding open season to determine when is their need, where exactly do they need the deliveries, et cetera. And then based on that, assuming that we can get the customer interest that we believe is there, then we would have a project. But those things take a couple of quarters to all come together.

Okay. Very fair. And understanding that the corridor to and at Tennessee, incredibly important to solidify that interest into binding commitments. But I know your ambitions lie beyond Tennessee as well on TGP. So if this expansion as contemplated materializes, can you talk about how this project could pave the way for future expansions across your Southeast footprint, including MSX as a stepping stone for SSE5 on SNG. And then how do you view the competitive landscape given Borealis has been out there local politics notwithstanding as well, but feel free to comment on any future...

Yes, sure. So I think the Marcellus/Utica needs outlets for its gas in order to grow. And the Southeast is going to have a lot of incremental demand. And a lot of that's going to be driven largely by power, but you can get those molecules also potentially into the export LNG. So meeting really the 2 big drivers of demand. And so longer term, I think the play is to get those molecules out of the Marcellus/Utica down into export LNG and down into power demand across the Southern United States. And so one way to do that would be to continue the expansion.

TGP, you can continue south on TGP from the Tennessee area, down south where TGP actually connects with one of our newer pipeline that we'll start building this fall called Mississippi Crossing. And so you can take it south. It requires expansion of TGP. It would definitely require some line looping potentially. But -- and then you could move across MSX. MSX has a very small amount of capacity left on the initial build, but you can also do some compression expansions and then ultimately, you could do some looping. And MSX feeds into South System 5. And then you can also get the -- you can backflow the molecules as well to get into export LNG. So there's a lot of different ways to feed that demand, but that's one of them. And it's a great opportunity for us in the Southeast for sure.

Got it. And then on the Texas side of things, your transmission footprint there. So the initial phase of Trident is set to enter service early next year, followed by Phase 2 in the fourth quarter of 2028. And given your comments earlier about the emergent call on U.S. LNG, are you observing incremental demand for a possible Phase 3 of Trident beyond the 2 Bcf per day of sanctioned capacity at this point?

Right. So Trident is our pipe that moves gas that's in construction right now. The first phase will be finished in the first quarter of next year. It moves gas from the Houston area, Katy -- up around Houston down over to Port Arthur, so over into East Texas and then ultimately connects into pipelines that go into Louisiana. And so the first phase will be complete in 2027. And then the second phase will be done in late 2028. But we do have the -- there is a small amount of incremental capacity left on the initial Phase 1, Phase 2 project, but it's relatively small. And so beyond that, there's expansion capabilities. And depending on how much you want to add, it depends on whether it's just compression or whether you need compression and piping. But I think we can serve both the Texas LNG demand and also potential demand over in the Southwest Louisiana. And so longer term, that is a nice opportunity for us as well.

Okay. Great. And in the Permian, when we look about other conduits of expansion, so the introduction of incremental residue capacity has driven Waha basis narrower and faster than previously expected, with more to come still. So how has this impacted your expectations for the timing of the next wave of Permian residue egress given how quickly this first phase has filled up? And would you touch on maybe your outlook on a previously discussed small-scale Westward expansion of EPNG?

Yes. So I think at this point, based on what's been announced that there is enough egress capacity from the Permian to the Gulf Coast for the foreseeable future. I think what we see right now and what we're talking to a lot of customers about is demand in and around the Permian. And I use around broadly because a great example of that would be the nonbinding open season that we just held on NGPL for a project called Permian Link, which would take Permian molecules up into the Texas Panhandle. And that could be -- and that's largely driven by power demand, had huge interest in the nonbinding open season that we held. And so now again, like on TGP, we're following up with customers, trying to nail down the timing of that demand and try to sanction a project from that. But those are the type of opportunities that we're seeing is power plants, data centers locating in and around that gas supply and then being able to build off of our existing pipeline system to take that gas to those demand centers.

Okay. Understood. We've somehow gone 20 minutes without discussing Western Gateway. We're going to move to the product side of things. Okay. So this was recently FID-ed with your JV partners, Phillips 66 and DINO in August after months of negotiations between partners and customers, I'm sure. Can you talk about the strategic merits of this finalized JV structure and what it means for Kinder?

Sure. So it's a -- we're a 35% interest in the joint venture with HF Sinclair and with P66. I mean it's a great partnership because they're very strategic partners and that they are Mid-Continent refiners that want to take barrels to California. And so the whole -- the premise of this project is you have California refineries shutting down. California refineries serve not only the California market, but they also serve the Phoenix market, the Las Vegas market and the Reno market. And so what's happened as these refiners have shut down is California is having to bring more barrels in over the water. And with the international situation, that is becoming more and more expensive.

And so the idea behind this is to bring Mid-Continent supply to Arizona, to Phoenix specifically and then on to California. And so the JV is building a new pipeline from the Borger Refinery in the Panhandle of Texas to Phoenix. And then we have an existing line that goes from California to Phoenix to feed Phoenix from California. We're going to turn that pipeline around and then we can not only -- the new pipe can not only feed Phoenix, but it can also move barrels out to the west to solve California's supply issue. And so I think it's a great project. It's underpinned by a number of different customers, but some very strategic -- but very strategic partners and very strategic customers. And on this, we get our 35% interest by contributing assets. Those assets have been valued at roughly $1.5 billion. And then we've got $250 million in cash equity that we are contributing. And we expect that we are targeting -- expect to earn incremental return on that $250 million above the existing assets. So it's a great partnership for us.

And it sounds like based on the project as it's contemplated, there could be expansion capability down the line if demand warrants it.

Sure. I think the capacity on that pipe is about 230 Bcf a day, but we have the ability to get up over, I think, 320 Bcf a day. And so there is expansion capability.

Wonderful. On your CO2 footprint, really jumping around across your segments, okay. So commodity price tailwinds have supported earnings upside relative to initial expectations, at least. As we look towards 2027 and understanding that you'll be giving guidance in due time, how do you expect volumes to trend relative to this year? And to what extent hashow do you expect volumes to trend relative to this year? And to what extent has Kinder been able to hedge those 2020 volumetric expectations at currently elevated prices?

Okay. So again, just a little context for people. CO2 segment is about 7% of Kinder Morgan overall. The oil and gas segment, which is where we produce oil and gas versus the CO2 supply business. The oil and gas piece of the CO2 business is about 4% of Kinder Morgan overall. And generally, we are hedging our oil exposure. And so going into a year, we're typically 90% hedged roughly on any given year. And so right now, for 2026, we're about 90% hedged. And so we do get a little bit of upside from commodity prices. But as you can tell from the percentages, it's really -- it's small, it's on the margin. Now when crude is up $20 a barrel, that's some nice dollars. We're very thankful for it. But also our CO2 volumes, our oil and gas volumes are doing very, very well this year, outperforming our budget. So that segment is doing well. And we have put on some additional hedges for 2027 during this time. Right now, we're about 75% hedged for 2027 at kind of mid-60s price range. But we'll continue to lay on additional hedges as we get closer to 2027. And so right now, I think the forward curve for '27 is in and around the mid-70s.

Very good. Yes, the backwardation, it is what it is. But yes, you have to manage through on a ratable basis, totally understandable. And then finally, with respect to capital allocation, you have an incredible amount of growth opportunities ahead of you, and we can only see the organic piece of it that you've spoken to, right? How do you plan to balance organic growth opportunities with potential inorganic opportunities as well? Are there specific areas of your portfolio that you see gaps? You've been no stranger on the inorganic side, most recently with the Monument acquisition. I'd love to hear about how comprehensive you want your portfolio to be over time and where those pockets are.

Okay. So let me say, first is we can fund over $3 billion of annual expansion CapEx with cash flow. So that gives us a lot of flexibility. Then added to that, we've got a fair amount of balance sheet capacity. So right now, our balance sheet is about 3.6x debt to EBITDA. And our target range on our balance sheet is 3.5 to 4.5x. So we are at the very low end of the range. And so every 0.1 turn on the balance sheet is about $800 million of capacity if you're talking about an expansion CapEx project that has no cash flow coming with it for a couple of years, right? And so if you say, okay, well, we're going to go from 3.6 to 4, that's an incremental $3.2 billion of capacity. So having that flexibility has been great because as we've seen these bolt-on acquisitions come up, and we've seen roughly one a year over the past couple of years, it's been easy just to fold those in using our balance sheet, not having -- no need to raise any equity or anything like that.

And the other thing is acquisitions are coming with cash flow. So when you talk about balance sheet use, $1 billion acquisition only uses 0.05x leverage if you do it at reasonable multiples, right? And so you're not using a lot of balance sheet capacity to be able to go out and do these bolt-on acquisitions that we've done. We've been very successful and where we're most successful is where we find these bolt-ons that really fit into our existing system. And so this year, we did Monument that folds into the Texas Intrastate system. I think the year before, we did a Bakken acquisition that folded into that position. The year before that, we did a different Texas acquisition. So we've had a lot of success at being able to do those and fully fund our expansion CapEx. And so I think that our balance sheet position gives us a lot of flexibility to be able to execute on opportunities when we see them.

Certainly not financially constrained in any way from your internal balance sheet capabilities as well as just the plethora of external funding options that we've observed across some of your competitors as well. But look forward to the next announcement on organic and inorganic side.

I want to come back really quick. Just -- I talked about the opportunity in the Southeast. But I mean, just to give people more of a feel for that. If you look at the Georgia Power large economic development report, they show 75 gigawatts of power -- potential power to be added between now and mid-2035. And all that won't be gas. But I mean, if you just translate that, I have to translate gigawatts into Bcf for me to be able to understand. I mean, horseshoes and hand grenades, that's like 15 Bcf a day. I just divide by 5 as rough justice. Now again, that won't all be gas and maybe all that doesn't come on. But that's just a huge opportunity, and that speaks to the opportunity to take those molecules out of the Marcellus and move them down into the Southeast markets because that's just one utility in one state, but that's endemic of what we see going on.

The demand is expansive, to your point.

Right.

Very good. Thank you so much, Kim.

Thank you, Theresa.

Welcome to Kinder Morgan's Second Quarter 2026 Earnings Results Conference Call. Today's conference is being recorded.

I will now turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Ted. Before we begin, as we usually do, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

My remarks for this investor call can really be summed up in four sentences. First, the second quarter was another strong quarter for KMI as both our EBITDA and EPS continue to exceed both prior year and our own budget for 2026 by significant margins. Second, the natural gas growth story remains very positive as demand for LNG export volumes and gas for electric generation continues to grow. Third, this growth is leading to numerous additional opportunities to build new midstream infrastructure supported by long-term contracts with creditworthy customers, and we expect to FID very substantial additional CapEx projects during the remainder of this year. Finally and very importantly, we can fund these projects almost completely with our internally generated cash flow while still continuing to pay a solid and growing dividend and maintaining a debt-to-EBITDA ratio at the lower end of our targeted range.

Now for some of you, those four sentences may not make a compelling case for investing in Kinder Morgan, not an exciting enough story. But I will remind you that this unexciting company has, over the last 29 years of its existence, grown its enterprise value at a compound annual rate of approximately 22% while also paying out over $40 billion in dividends. Now just maybe that gives us what we say, a little bit of credibility.

And with that, I'll turn it over to Kim and the team.

All right. Thank you, Rich. We're extremely pleased with our second quarter results, another fantastic quarter for Kinder Morgan, big one that reflects both the strength of our underlying business and the outstanding execution of our employees across the company. We significantly outperformed both last year and our budget expectations. Adjusted EBITDA increased 12% compared to the second quarter of '25, while adjusted earnings per share increased 32%. Importantly, growth was broad-based, with every one of our business segments contributing positively to the quarter's strong performance.

Given our results through the first half of the year and our confidence in the outlook for the remainder of 2026, we are increasing our guidance. We now expect full year adjusted EBITDA to be at least 5% above our '26 budget and adjusted EPS to be at least 12% above our original budget.

Turning to growth capital. Our backlog remains one of the strongest in our history. During the quarter, our backlog decreased from approximately $10.1 billion to $9.6 billion. This decline was primarily the result of successfully placing more than $650 million of projects into service, partially offset by the approximately $200 million of new project additions.

While our sanctioned backlog was down modestly this quarter, today, the Board contingently approved almost $400 million of projects, which are in advanced contract negotiations and will be added to the backlog upon contract execution, virtually offsetting this quarter's decline. In addition, we anticipate, as Rich said, adding significant projects from our over $10 billion opportunity set before year-end, likely more than offsetting the approximately $1 billion of projects we expect to place into service during the second half of 2026.

Our 3 largest natural gas expansion projects that are underway continues to make excellent progress. Mississippi Crossing, South System Expansion 4 and Trident are each progressing on schedule and on budget. These projects represent critical infrastructure supporting increasing electric power generation, growing LNG exports and broader natural gas demand across North America.

For Mississippi Crossing and South System 4, we received our final FERC environmental impact statement in June and expect to receive our FERC certificate by the end of this month, an important milestone as both projects move towards construction. Trident continues to advance well and is now approximately 60% complete. Financially, we remain in an exceptionally strong position. Our balance sheet ended the quarter at approximately 3.6x leverage, providing significant flexibility to fund attractive growth opportunities while continuing to maintain our disciplined capital allocation framework.

Finally, I'd like to spend a moment on the broader market backdrop. The fundamentals supporting our natural gas business have never been stronger. According to Wood Mackenzie's most recent outlook, U.S. natural gas demand is expected to exceed 160 billion cubic feet per day by 2035. That represents approximately 46 billion cubic feet per day of incremental demand growth compared to 2025. The primary drivers continue to be increased LNG export capacity and rapidly growing power demand.

The scale of this projected demand growth underscores the critical need for the infrastructure we own and the projects we are developing. With one of the largest natural gas transmission systems in North America, a premier portfolio of expansion opportunities, a strong balance sheet and a highly experienced management team, we believe Kinder Morgan is exceptionally well positioned to continue delivering value for our customers and shareholders for many years to come.

And with that, I'll turn it over to Dax.

Thanks, Kim. Starting with the Natural Gas business unit, transport volumes were up 7% in the quarter versus the second quarter of 2025. There were multiple drivers for the incremental demand, including increased LNG feed gas deliveries on the Tennessee Gas Pipeline, incremental demand on our intrastate system, incremental power demand along our El Paso pipeline and greater exports to Mexico. Natural gas gathering volumes were up 26% in the quarter from the second quarter of 2025 and increased across most of our gathering and processing assets, with the largest impact coming from our KinderHawk system in the Haynesville, which was up 54%.

As we have continued to say, demand for gas on our pipes remains high and our system remains highly utilized. Looking forward and consistent with Kim's comments on our shadow backlog, we continue to see significant incremental project opportunities across our natural gas pipeline network. For example, we are in various stages of development on projects to serve more than 10 Bcf a day of natural gas demand in the power generation sector and approximately 3 Bcf a day in the LNG sector.

In our Products Pipeline segment, refined product volumes were down 5% in the quarter compared to the second quarter of 2025 and crude and condensate volumes were down 16% in the quarter compared to the first quarter of '25, with most of the decline in crude volumes explained by the removal of Double H from service for the NGL conversion early in the third quarter of 2025. Excluding Double H volumes in both periods, crude condensate volumes were down about 5% in the quarter compared to the second quarter of 2025.

Regarding Western Gateway, KMI and Phillips 66 are steadily moving the project forward. While progress on our partnership agreements has been significant, the process has taken longer than initially anticipated primarily due to the complexity of the proposed arrangement. Our aim is to complete the documents within the next month or 2, at which point, assuming satisfactory progress continues, we would plan to FID the overall project.

In our Terminals business segment, our liquids lease capacity remains high at 93%. Market conditions continue to remain supportive of strong rates, and the utilization of tanks available for use is approximately 99% at our key hubs on the Houston Ship Channel and at Carteret. While the temporary Jones Act waiver has added some market uncertainty, our tanker fleet remains exceptionally well contracted. Assuming likely options are exercised, our fleet is 100% leased through 2026, 97% leased through 2027 and 80% leased through 2028. We have opportunistically chartered a significant percentage of the fleet at higher market rates and have an average length of firm contract commitments of almost 3 years and over 3 years when considering options that are likely exercised.

The CO2 segment saw 10% higher net oil production volumes compared to Q2 of 2025, which was led by a 15% increase in production at SACROC. NGL volumes were 9% higher, and CO2 volumes were 5% higher. Finally, RNG volumes increased 8% as the significantly improved operations that are driving both greater uptime and hydrocarbon recovery at our facilities continued in the second quarter.

And with that, I'll turn it over to David.

Thank you, Dax. We're declaring a quarterly dividend of $0.2975 per share, which is $1.19 annualized and an increase of 2% over 2025. As you've heard, we've delivered record-setting -- we had a record-setting quarter, with both net income attributable to KMI and adjusted EBITDA reaching record levels for the second quarter. That performance was also meaningfully ahead of our internal expectations, with EPS more than 24% above our budget and adjusted EBITDA more than 9% above our budget. This follows a first quarter where we achieved similar outperformance. So we completed our first half of 2026 that was extremely strong.

For the second quarter, we generated net income attributable to KMI of $867 million and EPS of $0.39. These are 21% and 22% above the second quarter of 2025, respectively. Adjusted EPS was $0.37, a 32% increase from last year, and adjusted EBITDA grew 12% from last year. These are very strong results. And as Kim mentioned, it was very impressive that each one of our business units contributed to the year-over-year growth.

The Natural Gas business saw higher volumes and favorable margins across the Texas intrastate network. We also had greater gathering and processing volumes as well as increased contributions from park and loan services, growth project contributions, capacity sales and utilization increases across multiple assets. The products business benefited from improved commodity pricing as well as greater butane blending volumes and rates, partially offset by lower refined product volumes.

Our CO2 segment saw greater contributions from commodity prices as well as very nice volume growth, as Dax mentioned, especially at SACROC, which is up 15% from last year. In Terminals, we had increased volumes and rates in our liquids business as well as favorable commodity pricing. Those were partially offset by some favorable onetime items that we experienced in 2025. The year-to-date versus 2025, EBITDA has grown 15% and adjusted EPS has grown by 35%, very impressive growth.

So for the full year 2026, as Kim mentioned, but it's worth repeating, we expect to be more than 5% favorable to our budget on adjusted EBITDA and more than 12% favorable on adjusted EPS. That represents more than $430 million of additional EBITDA contribution. We think this is a clear demonstration of the enhanced value of energy infrastructure in the U.S., particularly as we suspect we will continue to see growing demand for natural gas across the country.

Moving on to the balance sheet. Our net debt to adjusted EBITDA ratio ended the quarter at 3.6x, which is down from 3.8x at the beginning of the year and is down from what we have budgeted. And now we expect to end the year at 3.6x leverage as well, and that's down from the budget of 3.8x despite spending more on our Monument acquisition and increasing our growth capital relative to what we had budgeted. And that's all driven by our EBITDA outperformance.

This also puts us well below the midpoint of our target leverage range of 4.0x. Year-to-date, our net debt increased $311 million. And I'll walk through a high-level reconciliation of how we get to that increase. We generated $3.45 billion of cash flow from operations. We paid out $1.315 billion in dividends. We spent $1.92 billion in total capital, which includes growth capital, sustaining capital and our contributions to JVs. And with the Monument acquisition of $500 million, it gets you pretty close to the increase in net debt for the year.

Now I'll turn it back to Kim for Q&A.

Okay. Thanks, David. [ Ted ], if you'll come on, we will take questions.

[Operator Instructions] The first question in the queue is from Praneeth Satish with Wells Fargo.

I wanted to start with a high-level question. So you talked roughly about spending about $3 billion per year of growth CapEx, which you mentioned kind of keeps you around free cash flow breakeven. But I guess when I look at the size of the data center opportunities, power-related opportunities across your footprint, I'm wondering if that's the right target anymore? Is there a scenario here where the backlog becomes large enough maybe with SSE5 or something along those lines where you significantly outspend free cash flow and move to a more leverage-neutral approach? On our math, I mean, you can spend up to $6 billion per year of growth CapEx and keep leverage unchanged. So I guess I'm just wondering if there's enough demand in the potential backlog to get to those levels? And then also, would that level of CapEx spend fit within your guardrails?

Let me say a couple of things on the over $3 billion in expansion CapEx per year that we projected is based on the current backlog. So they're roughly $10 billion. And as I think Rich alluded to and I said is we do expect that we will be adding significantly to that backlog. With the current backlog, what happens to our debt-to-EBITDA is it comes down over time as we add incremental EBITDA and the debt balance essentially stays flat.

So right now, we're at 3.6, [ pending ] the roughly $3 billion per year debt to EBITDA comes down. At 3.6, if we needed to take that up to fund incremental CapEx in excess of our cash flow, if we wanted to go to 4x, we have $850 million of capacity for every 0.1x. So if we wanted to go up to 4x for example, that's $3.4 billion of incremental balance sheet capacity. So we absolutely have the ability to finance incremental cash flow, I mean, incremental CapEx stay within or at the middle potentially of our balance sheet target range. And look, I think we expect that we will be adding projects to the backlog. And that's -- a lot of that's really around power is the primary driver of those incremental expansion projects.

Got it. That's clear. And then maybe shifting gears on TGP, looks like there was a nonbinding open season project [ 219 South ]. Can you talk about how you're thinking about the competitive landscape here for building a takeaway project out of the Northeast down to the southern markets? I guess, what drove the project size and the scope of it versus potentially pursuing something larger? And then is this fundamentally a brownfield expansion or more greenfield? And then how do you think about kind of execution and permitting?

Praneeth, this is Sital. So just as you just take a step back and the way we look at this corridor, what drove the open season is we're seeing not only the demand in the Southeast and the South, but we're also seeing demand through the 4-state corridor, Tennessee, Ohio, West Virginia and Kentucky, or we're starting to see a power corridor form. And so given the interest that we've been seeing out there, our thought was to put out.

We know we have somewhat of a brownfield opportunity with the smaller case. We are evaluating a larger case. But I think what we're -- our objective here, we typically go out with open season with anchor shippers in hand. But the market here is still evolving. And so our thought initially was to put the project out of a smaller size. And if the market indicates the need for a bigger one, we can evaluate it. We have the ability to morph this into something bigger if needed.

The next question in the queue is from Jeremy Tonet with JPMorgan.

I just wanted to pivot towards Permian linked, if I could. I was just wondering if you could walk through a bit what you see the competitive advantages of that project arm, when do you think you might be in a position to take FID?

Okay. Well, I'll answer the second one first. Our modus is we have a contract and we go to FID. We are in discussions with customers. As you know, we had an open season, significant interest in the project. I think what differentiates this project is our -- when you look at the NGPL footprint, we basically have a little power corridor forming across the pipeline. But the real differentiator here is the link to storage. And hence the name Permian Link.

And I think as you see these power opportunities via data centers and organic power growth develop, that 765-kV line is -- [ ERCOT's ] approved that, and that's going through there. So we're starting to see a lot of activity. And that's the foundation for kind of the path that we've picked. Where we are today is we're discussing with our customers in the open season. And as you know, there's lots of interest out of the Permian to get additionally egressed projects. We will sanction the project if we have contracts that support it with the returns that are acceptable.

I was just wondering if time line, any thoughts you might be able to share there as well?

Well, I think we've got this thing targeted for a 2030 type in-service, right? I mean just by the nature of the long leads. I mean, obviously, the sooner we get the contracts signed, the faster we can go and start getting the long leads ordered. It's still competitive, but I would -- the discussions are going well.

That's helpful. And just one more, if I could. If I think about Permian Link, if I think about TGP [ station to 19 South ], these projects, depending on how they come together, could be fairly sizable in nature, things that are more in $1 billion range as opposed to even a $400 million range. And I was just curious, as you look at your project portfolio, what you see is possible out there? Do you see many other projects in that size, that chunky size? Are there smaller projects? Just wondering, if you think about these larger projects, do you see more than just like a couple out there?

Yes. I mean, I think there are -- I mean, it's like our existing backlog. There are a handful -- our opportunities has a handful of the $1 billion-plus and then a lot of $100 million to $500 million projects. So it's somewhere in terms of size and scope and number of projects.

The next question in the queue is from Julien Dumoulin-Smith from Jefferies.

Maybe just to pivot from the last two questions here. So on the approval for the almost $400 million of projects not yet in backlog, can you give color on those or what needs to happen for those to move into backlog? And then to really square it up. How do you think about the time line for some of that shadow backlog to convert in FIDs? Is that still kind of a 2026 time line when you think about these larger, lumpier projects?

In terms of the $400 million, so on those, we've got the project designed. We've got the cost. We have agreed on commercial terms with the customers, and we are a long way through agreeing on a contract. And so it's weeks to a month or something probably before you get contract signatures on those. So I think those are the -- on the lip of the cup.

And then your second question was with respect to converting the shadow backlog. And I think it's hard to predict exactly when projects are going to be FID'd. But as we have all said on this call, I think, one, there is a lot of opportunity. We are not seeing a slowdown in the opportunity side. If anything, we're seeing increases. And second, I think we expect to add significant projects in the back half of this year.

Got it. Excellent. So this year, indeed. And then just specifically, if you can comment a little bit on NGPL here. And as much as, obviously, you've gotten very regional dynamics there working in your favor as a tailwind. Can you talk about where specifically you might see incremental demand and the potential scale and timing on that front?

Yes. So just when you look at the NGPL footprint, you've got the Permian Link corridor, if I will, the [ stat 765 kV ] line, there's a lot of activity there. We've got activity in the market area up in the north. There's a convergence of inquiries coming in. And so you've seen some capacity reservations where we were trying to target that demand up in the Northern half of the Northern section of NGPL. Once again, these are all fluid, want to get highly competitive. But we're -- our goal is to try and get these done as fast as we can.

Next question is from Manav Gupta with UBS.

A quick question first on the Western Gateway. Even with the minor delay, it looks like both parties are very strongly interested in the project. Clearly, California has massively short product. And clearly, the strategy of trying to import only from Korea or other places has gone wrong. So where are we with this project FID process? And how confident are you that you will get to FID probably within the next 2 or 3 months?

Yes, Dax.

Yes. This is Dax. As I mentioned in my comments, I think we've progressed the documents along pretty far. We've made a lot of progress, and we would expect, based on what we see right now to FID the project in the next month or 2.

All right. My second quick follow-up here is you have a big footprint in Haynesville, and we are seeing an incremental demand from Haynesville given the demand for natural gas. Do you think Haynesville would be a core basin to meet the growing demand for natural gas? And can you remind us of your footprint in the Haynesville?

Yes. We've got a very significant footprint in the Haynesville. And if you look -- I mean, whether you look at our numbers or Wood Mac numbers, I think we're expecting significant growth coming out of the Haynesville between 2025 and 2030. So on our number -- on Wood Mac's numbers, it's like 7 Bcf a day. And on our numbers, it's 10 Bcf a day.

And this quarter, we're seeing sort of the start of that. Our volumes in the Haynesville were up as [ backside ] of over 50%. This quarter, I think we averaged 1.9 Bcf a day for the quarter, and volumes got to around 2 Bcf during the quarter and so over 2 Bcf during the quarter. So we're just -- we're in the process of completing a $500 million investment to bring on incremental transport and creating capacity. And that project is on time and on budget.

And Manav, just to remind you, that's another Bcf of processing capacity, and we just hit a peak here in June in the Haynesville.

The next question is from Theresa Chen with Barclays.

On the Project 219, the return in terms of the competitive dynamics, would you be able to elaborate on what advantages your project brings versus other contenders along similar corridors, including [ Boardwalk's ] proposed Borealis project nearby?

Well, look, I'll talk about Tennessee and the benefits of Tennessee. I mean, ultimately, each -- I'm not going to talk about [ Borealis ], but I mean Tennessee is -- what we view as an advantage for Tennessee is it's in our existing corridor. We've got 4 pipes going through that corridor. There's a developing market through that same corridor. And we have some capabilities using some of our existing footprint to help facilitate.

I think that's -- I would call advantage #1 for the base smaller project. In terms of access to supply, we can reach back all the way to the [ 219 Mercer ], Pennsylvania area, which has additional supply points from the Southwest Marcellus. You've got some of the traditional supply. When you think about the [ Clarington ] pportunity, we can even look to link to access to [ Clarington ] area along the way. So supply diversity is there, the South of the Utica.

I think when you look at that diversity, I think that's an advantage. And then you have market advantage in terms of all the access that you get along the way in that developing corridor, plus we can get the volumes all the way to our Mississippi Crossing project and then ultimately into the Southeast. That's kind of the design and the nature of the base plan. So I think that's it in a nutshell, diversity.

Understood. And sticking to the same region in the Southeast. Following that Southern Company's recently announced agreement with OpenAI for a data center project in [ S&M ] highlighting the growing gas demand associated with AI infrastructure in general in that region, How do you view the opportunity set for the SNG system? Could this drive future expansion projects or incremental gas to power opportunities for the [ Kinder-Suthera ] JV over time?

Yes. Let me say a couple of things, and then I'm going to pass it to Sital. But there is a clear need for additional expansion in this region. I mean, Georgia Power, earlier this year, filed their large load economic development report, which showed over 75 gigawatts of potential power demand between now and the mid-2030s. And that is 1 utility in 1 state.

And so projects will be competitive on sell comment a couple this. But our asset position in the Southeast market, I think, is -- puts us in a great spot between SNG, MSX that we're developing, bridge that we're developing, our 50% interest in FGT. So it is an exciting market.

Yes. And so Theresa, we're -- obviously, we're evaluating projects to serve the entire Southeast, right? And we're trying to see what we can do is highly competitive. So we're obviously very cognizant of that fact, but we feel good about the opportunity set and we're trying to get some of these across the finish line.

I would say, in terms of the Southeast in particular, it's not just the FNG footprint, we got EEC, we've got other assets in the basin that can help solve some of these long-term needs. And so the teams are working hard to try and get these across the finish line.

Next question is from Jean Ann Salisbury with Bank of America.

Now that Double H has ramped in NGL service, what are your latest thoughts on the potential to add volumes to that system and what would that take?

The potential to add volumes in terms of the capacity, we -- like I said, when we had the last call, we have capability to bring incremental molecules down. We're in a pretty competitive market here. And so until we get another contract, I'm not going to comment on that, but we have capabilities to further expand. And I think that's -- that will involve some collaboration with other parties. And because it's so competitive, we're just going to stop there.

All right. Fair enough. And then as more turbines are shifting into power generation, are you seeing any constraints on getting compression for future pipeline projects? And how are you mitigating that risk if so?

So one, we're starting to see -- we are starting to see pressures on some of the time lines. Obviously, we have relationships with some of these providers, and we do to make sure we stay ahead of it. Our team is focused on the opportunity sets that we see in front of us. And we're trying to manage that. We're trying to factor that into our project economics as we're starting to bring these projects across. And the team is just trying to do -- they're doing a incredible job staying on top of all the variability. So I think the way -- when we see this developing, we're just trying to stay ahead of the impending, I guess, delay in the supply chain that may develop over time.

And I'd say it hasn't lengthened out that much recently. This has been an ongoing phenomenon. And so we've been on top of this since we started doing MSX and South System 4. So it's something that over the last 2 years, we've gotten very good at taking into account and dealing with.

The next question is from Spiro Dounis with Citi.

Want to go back to the backlog quickly and really just go back to your comments on how you're thinking about it into year-end. As you mentioned, you've got several large scale projects in development. Many of them have come up on this call already to kind of offset that $1 billion, I say, more than offset that $1 billion coming into service.

So I guess I'm just curious, are all these projects you sort of talked about or could we be surprised by what you end up announcing later this year? And as you think about the complexion of the projects, are these primarily gas related, maybe with the exception of Western Gateway, which I assume is included in that $1 billion figure?

The answer is yes, other than Western Gateway, they are primarily gas-related. And what I would say with respect to what projects they could be, I think everybody knows the themes is what I would say, where the demand is growing and the areas that need pipeline capacity. And so I don't think you will be surprised by the underlying drivers of the demand.

Got it. That's good color. And then just going to the balance sheet. Maybe for you, David, but just now at 3.6x, $3.4 billion of capacity from here. You talked about the organic growth potential, which might end up consuming a lot of that capacity. But just curious to check in here on the M&A side and see where that fits in, how you see that landscape today? And if this maybe opens up room to do something larger in scale?

All right. So on the M&A side, as we announced an M&A deal with last quarter that we have now closed, $500 million. And that's consistent with -- we've been seeing opportunities of about that size over the last couple of years and have been able to roll them in without an issue because those come with cash flow. And you don't -- so it's not as dilutive to your leverage metric initially given the in-place EBITDA.

The other thing I'd say about those is that everybody looks at the going in multiple and says, "Oh, well, expansion is better opportunity than the acquisition side." And what I would say about that is you can't just look at the going-in multiple on something because on an acquisition, you get the cash flow immediately. On an expansion project, you have a little bit of a drag. And so you could have a higher going-in multiple on an acquisition than you have on an expansion and still have similar IRRs. And so they all -- those things all compete for capital. But right now, we don't feel like we are capital constrained at all.

The next question is from Keith Stanley with Wolfe Research.

First, I just want to confirm the full year outlook being 5% ahead of the EBITDA budget. It seems like that just reflects the outperformance in the first half of the year. Why wouldn't the second half outlook potentially be better given the momentum you're seeing year-to-date?

Okay. So I think, one, obviously, in the first quarter, we had a winter storm. We've had some Waha spreads. We had a little bit of which about one-times. In the second quarter, we don't have that much, in fact, nothing material that I would call onetime. And so the second quarter reflects pretty strong performance across the base business. I also think that it's debatable whether all the winter storm is a onetime because I think if the system is as tight as it is and when you're going to get volatility, you're just going to -- the demand for our services and our assets is just going to be greater for the foreseeable future.

I think generally, we try to be somewhat conservative when we project out for the balance of the year. There is some outperformance that is baked into this guidance for the balance of the year, just not as much as what we saw in the first half of the year, given some of the things that happened in the first quarter.

Okay. Second question, it's kind of a high-level question on how to think about the shadow backlog concept. So you introduced the $10 billion shadow backlog I think about a year ago now. I think you've sanctioned around $2 billion of projects. You indicated kind of you'd expect to sanction at least another $1 billion in the second half of the year today. So it's about $3 billion over 18 months. Looking forward, would you expect the pace of converting that shadow backlog to a sanctioned backlog to be faster over the next year or 2, a similar cadence? Or is it too hard to say?

I think it's hard to say when things come to fruition, but I think we see a good line of sight of sanctioning a fair number of projects in the back half of this year. And so I mean, I think we are bullish on the opportunities of adding.

I'd also point out that the $10 billion hasn't decreased despite the fact that we added $2 billion and are looking to add at least $1 billion in the back half of the year. And so our opportunity set has continued to grow.

The next question is from John Mackay with Goldman Sachs.

I think I'm actually going to ask to both of Keith's questions in another way. But just looking at the backlog and again, to the point of kind of potentially announcing another $1 billion of projects later this year to offset the $1 billion coming online. I mean, is $10 billion generally where you expect the backlog to be able to hold going forward? Or is there room for that number to move meaningfully higher?

There's room for the number to move higher.

Appreciate that. And then...

Putting off to this $1 billion number, I think what Kim is trying to say is we have a lot of opportunities, and we expect to do at least that kind of thing, that $1 billion threshold. So I wouldn't take that as that's all we're going to do in the last half of this year. There's a lot of opportunities out there. And I think we're poised to move quickly on them. But again, we have to get the horses in the corral.

Understood. That makes a lot of sense. And then just on the '26 guidance, I mean, I understand the point of being a little conservative around the back half guide. But it was such a strong quarter. I guess I'm just wondering if you could point to maybe a little bit more of on the ground, from an operational standpoint, what some of the outperformance was coming from? And again, maybe framing up why that could be a new run rate earnings level for some of these segments?

Yes. I'll highlight a few, and then Kim can.

So one, I would point out that the CO2 oil production was very strong. That's one of the larger outperformers for the quarter versus our budget. We had -- SACROC is year-to-date up 15% over last year, which is better than what we had expected. Commodity prices, obviously, with the Iran conflict, contributed to outperformance across multiple assets, across multiple business units. So that contributed in the quarter.

Our Natural Gas business, both in the Texas intrastate and across other interstate systems, continue to squeeze out additional margins, margins in the Texas intrastate business and then capacity sales at greater rates and greater capacity than what we had expected in the interstate business.

And so some of those are hard to call for the rest of the year if that's going to continue for the rest of the year. Commodity prices are out of our hands. And so that's probably part of the reason why for the rest of the year, we haven't projected as much outperformance for the rest of the year relative to what we experienced in the second quarter.

And Kim already touched on the first quarter, we mentioned a lot of these, what I would characterize as kind of nonrecurring -- potentially nonrecurring, really stronger winter weather relative to historical norms and extended cold periods that led to some outperformance across some of our natural gas assets. We had a contract buyout in our Terminals group.

So some of those are the things that have led to a little bit of outperformance in the first quarter. So for the rest of the year, while we're still expecting that these kind of nonrecurring items are less than half of our overall outperformance for the full year, we've probably taken a little bit more of a conservative guide for the second half of 2026.

Next question is from Jason Gabelman with TD Cowen.

I wanted to go back to the discussion of adding $1 billion perhaps in new projects by the end of this year. I'm just trying to understand how Western Gateway fits into that because there's going to be, as I understand it, a cash contribution to the project and then you're going to contribute assets as well. So as you think about how Western Gateway accounts for some of that $1 billion, is it the total cash plus asset that you're contributing to the joint venture? Or is it just the cash portion?

Let me point out two things. Like Rich, just what we said is at least $1 billion. And so it could be more than that. Absolutely. And again, I think it's absolutely possible that the $10 billion, we go above the $10 billion backlog.

And so I think we're saying the opportunity set here is just really tremendous. What is hard to call is the timing of it. And so we want to be somewhat conservative about calling our timing because we're negotiating with customers, and they don't -- everybody doesn't always move at the pace that you expect.

With respect to Western Gateway, when we talk about the $1 billion, we are not talking about our asset contributions to that. To the extent that it would be part of the $1 billion, we would just be counting the cash contribution.

Great. And my follow-up is on the startup of GCX expansion. And I think the market's been a bit surprised that just with a little bit more egress out of the Permian Basin, Waha spreads have really come in. So just wondering if you saw that GCX expansion fill up pretty quickly immediately or if there's some space left on it?

No. So I think it was waiting on capacity. So as soon as we got it up, it pretty much was full. And that's been the case on all of our part projects out of the Permian, they've been pretty full as we brought some facilities on. So I think what you're probably seeing is maybe less of the maintenance activity around that also probably contributed to some of that. But GCX in itself has been full.

And the next question is from Sunil Sibal with Seaport Global Securities.

I just had a follow-up on your comments regarding the Haynesville volumes. So I think you mentioned that you expect another Bcf per day of Haynesville volumes coming online in the near term. I was curious, do you see any price sensitivity to those volumes? Or those are kind of pretty much visible because the minimum volume commitments or offtake on the demand side that you may be seeing?

Yes. Sunil, what I was saying is we are adding a Bcf of processing capacity, treating capacity. And so we have right now, where we are as our system is effectively full. And so we're offloading any volumes that come on to our Haynesville system. And so we're trying to catch up those offloads are from a margin standpoint, not as accretive as us keeping those on our own system. So we're adding a Bcf of treating capacity. And if the demand profiles hold up, the production should be there to support it. And we just got to have the capabilities to get it from point A to point B. And so that's all we're saying.

And then on price sensitivity, I'd say -- our largest customers have hedged. And so I would expect that most of those volumes that we're expecting are going to be price insensitive.

Understood. And then thanks for your comments on the GCX volumes. I was curious, you know, although there are a number of gas pipeline projects in pipeline, are you starting to see discussion with customers on the next phase of growth in Permian, considering that what we are seeing in the commodity markets?

Yes. Look, I mean, we are -- our Permian Link project is just one example. There's a lot of discussion going on. It all depends on where the demand. I think one theme you're seeing now is where the demand is going to show up is where -- that's where the molecules are trying to point. And so as those demand centers start developing, that's where those discussions will lead. But I mean, we are in discussions today with customers about several options out of the Permian.

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

Good. Thank you, all. I hope everybody has a good evening. Thank you.

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

Good morning, and welcome to the second session of the first morning of the 42nd Annual Strategic Decisions Conference. I am Bob Brackett, Co-Head of Energy and Transition here at Bernstein.

We are not expecting a fire drill. And so if the alarms ring, please take that seriously. The primary exit will be straight out the back door, down the right to the escalator area down to the street level and out. If for any reason, that path is blocked, you'll go straight to one of the internal stairwells right outside the door, go down and follow the lighted signs there. This is your conversation. scattered across the room are little blue cards with QR codes. Those QR codes will take you to the Pigeonhole app, type your questions, and those will get delivered up to the front of the room. And from there, I can ask them.

While I wait for your questions to come in, I'll start my conversation with Kim very much as a pyramid. We'll start with talking about macro issues. We'll move down into strategic issues, financial issues, and sort of specific assets, operations, projects, et cetera. So that's how the conversation will proceed.

With that, I will sit in 1 second. But first, let me thank Kim for joining us, Kimberly Dang, the Chief Executive Officer of Kinder Morgan.

Thanks, Bob.

So we're going to start with macro and you all do much more natural gas than most anybody and more natural gas than anything else. And on the gas macro, we'll start with volume, which we both like, and then we'll talk about price where I'm more perhaps engaged requiring it than you are. If we think about gas demand growth in the U.S., we talk about your numbers, something like 26, 27 Bcf of growth to 2030.

To put that into context, the oil demand globally is likely to rise less than 1 million barrels a day each year to 2030. If we take something like divide by 6 and take 27 Bcf, that's 4 million barrels of oil equivalent growth just in the U.S. just for gas in the next 4 years. It's more than global oil demand growth, right? How do you get there? You do your own work on that. Why are you above consensus, if we call WoodMac consensus on those volumes?

Yes. So you're right, our number is 26 Bcf a day, going from 115 Bcf a day market in 2025 to 141 2030. Driven largely LNG is the biggest driver. It's about 18 Bcf of that. Power is the next biggest driver. It's about 5. And then you have exports to Mexico and industrial, et cetera, that balance out the rest. The biggest places we're higher than WoodMac, which is at 19 on both LNG and power. And I think that we will, at some point, update our external forecast.

And I think, quite frankly, I see the 2030 number getting higher, likely based on everything that's going on around power and maybe a little bit on LNG. And I think that what's happening in the Middle East and the Strait of Hormuz, long term is good for the United States in terms of being able to be a supplier for the global markets and being able to be looked at as a reliable supplier. And so I think that is also potentially incremental demand driver from what's in our numbers today. And so I think that creates a great backdrop for us where we've got 2/3 of our business is natural gas. We've got 58,000 miles of gas pipelines. We've got a $10 billion expansion -- approved expansion project backlog where almost all of that is associated with gas. So I think there's a $10 billion opportunity set on top of the $10 billion of approved projects that we're working on. And so I think it just puts us in a fantastic position.

And arguably out to 2030, big driver of growth around LNG, big around power demand, data centers and other things. And LNG is fairly locked in. We're sitting here mid-2026. We probably won't be surprised. Everything that's cutting steel today on the LNG side will be there, pretty hard to come up with a new project. And then beyond, you just have it continuing to grow on both of those drivers. into the mid-2030s?

Yes. I mean we haven't done our number -- updated our numbers to the mid-2030s yet. But we'll be turning to that in the next 6 months or so to get into 2031, 2032. But yes, I think that there's the potential for more LNG, and I think there's the potential for more power. And I think as Mexico's gas demand continues to increase and their domestic supply continues to decline, there's potential for more exports to Mexico as well.

And for each molecule of demand, there has to be a molecule of supply, how the physics work. How do you think about that? And we'll spend a lot of time in the Permian, right? And so where does -- have you thought about where all that gas comes from?

Yes. So when you think about -- I think there's three primary basins. It's going to be the Permian. It's going to be the Haynesville and it's going to be the Marcellus-Utica. I think the constraint on the Marcellus-Utica growth is really pipeline capacity out. From a dry gas perspective, it is the most competitive supply out there, but it is expensive to get it where you need it, which is primarily on the U.S. Gulf Coast.

And then I think the Haynesville, Haynesville is a higher cost to produce, but it's born in the right place, right? It's right there by all the LNG supply and by a lot of where the power demand will come across the Southern United States. So -- and then the Permian is just a byproduct, right? And so -- and there seems to be a fair amount of gas waiting on capacity out there. And so I mean, there's -- we've got a pipeline project, 570 a day that's coming on in the second quarter, and then there are 2 more projects coming on in the third and the fourth quarter, and that should bring some incremental supply to the market.

And if you put that context, that 26 Bs of growth, that's like two more Haynesville. It's sort of another Permian. It's a huge jump to where we are already in Appalachia or it's some blend, but it's a significant number. Talk to the Permian then. We watch negative prices in the Permian. There's sort of a build fill, build fill cycle. You've got GCX expansion coming. will there be a day? Do you expect those lines to fill quickly?

I do. I think they will fill very quickly. And -- but -- the other thing is, as you look -- those lines all come on this year. If you look at the spreads in '27 and '28, I mean they're still wider than the cost of transport. So they're well over $1 in '27 and '28 to move that gas out of the Permian. So that would support the premise that there is pent-up gas that is waiting on pipeline capacity. And I've heard numbers anywhere from 1.5 to 2.5 Bcf.

And if we talk about connecting that demand or that supply to demand, I know where all the LNG terminals are going to be built. The great state of Texas, the great state of Louisiana. I'll bet against almost any other coastline for any other state. Power demand, which is that other driver, has a choice. And so that power demand could be in places that you can connect to on the supply. It could be in places where you don't really need to move that gas. You could drop the data center into the Permian. How do you think about the location of future power demand growth for gas?

Yes. I think a couple of things on power demand. With respect to AI specifically, I think the Texas market is going to be the leader in terms of data center supply added. And I think closely behind that is Georgia. Virginia is the other state that's got big. So I mean, the Texas market is a fantastic market for us because you've got the Permian and -- but you've also got Eagle Ford supply and you've also got now what we call the Western Haynesville, which is also in Texas. And then you've got huge amounts of demand coming from export LNG. It's coming from the data center development. It's coming from population growth and needing more power to serve the population.

And it's coming from backing up the huge renewables that the Texas has built. So there is a huge demand for power growth in general in the state of Texas. We have seen data centers. You see some that are building relatively close to what I'll call major metropolitan areas. They're not going to be too close because those things require tremendous amounts of land. A lot of times, they're building the data center and putting the power plant next to it. And so they need a tremendous amount of land.

We've seen them locate, as I said, next to major metropolitan. We've seen some want to locate out in the Permian Basin. But even those that are locating out in the Permian Basin, we're seeing there's the potential for projects there because they're not -- you can't go locate in a field where you've got all these wells drilled, right? You've got to be somewhere outside of that. And most of our pipelines out there are full. And so there is the potential for projects out there as well. And we've got -- we've seen coal conversions in the Texas Panhandle. That's driving power demand. So I mean, I think our probably largest footprint is in the Texas market, and the Texas market has one of the best growth profiles I think, for natural gas.

You mentioned population growth. You mentioned the East Coast. You mentioned the South Coast. You left off one of the coasts. Is there an opportunity where there's population growth and data center growth as we move west of Texas?

Yes. I think there is currently a proposed project that's contracted that is expected to be built to the west by another firm. And that should serve a lot of the demand with respect to data centers in Phoenix and the power plants in Phoenix. But I think there may also be opportunities around the West Coast of Mexico, around export LNG and maybe some incremental power as well. So I don't think it's near term, but I think longer term, there may be some incremental opportunity out there.

And maybe talk a lot -- we're going to end up talking about your $10 billion of projects line of sight clear.

$1 billion.

There's another $10 billion you've talked about. How do you engage with your customers on the demand side? I understand how you engage with your customers on the supply side. Talk about what do you have to do to engage with future customers on the demand side? How long do those conversations take?

Some are quicker than others. So it's -- look, we've got a great demand picture and then we've got a great asset base. And so when you marry those two things up, I mean, there are a lot of people that are coming our way in terms of customer conversations about potential supply. And so I think the quickest projects are ones where it doesn't require much expansion capital, maybe you're building a small lateral and it's for one customer. It's just easier one-on-one to get something done.

The ones that take longer are the bigger projects. So where you need multiple customers to support a project and they all have different deadlines. And so those take a little bit longer. So -- but we like them all, right? We like the singles and the doubles. They come with less risk. A lot of times, they're probably better returns. The greenfield projects, they come with a little bit more risk. A lot of times, they're more competitive.

But they -- at the end of the day, they're a lot larger and deliver a lot more meaningful bang to the bottom line. So we've got all sorts of different projects in the backlog. The 3 largest projects in our backlog are total about $5.3 billion, so about 50% of it. And so those are the large ones. And then obviously, the other half is smaller-sized projects.

And we've talked about volume of demand volume of supply price, price matters a lot for my E&P coverage, especially my levered E&P coverage. Dollar move in gas for me makes me look like a fool or a genius on the left side of that right now. $15 move in oil, which is what we've seen in the last week amidst a backdrop of a potential Strait of Hormuz deal, both of those units move your revenue, your EBITDA a few percent, 1%. So do you care about oil and gas prices? And then if you do or you don't, where are they going?

Yes. Okay. All right. I'd say yes and no. So in the short term, we are pretty insulated from any commodity price moves. As 65% of our business is take-or-pay contracts, meaning people have to pay for the service, whether they use it or not. 26% of our business is fee-based, meaning there is no variation in the price. You could have some variation in the volume, but no variation in the price. We've got another 5% that's hedged, that has commodity exposure but hedged and generally and then we've got 4% that's unhedged. So relatively modest exposure based on the way that we contract with our customers.

That being said, what impacts our customers impacts us. And so in the long term, we do care about where commodity prices are. In the short term, it's not so important. When we think about long-term commodity prices, though, I think there's a broad range from our perspective that is pretty acceptable. And the reason is that it's at the extremes where we see demand or supply getting impacted and really long-term demand and supply getting impacted. And that's what impacts people's willingness to sign up for capacity.

So if you see -- if we saw gas prices at $8, that would probably negatively impact demand, which would not be good. If you see prices at $1, you're probably going to negatively impact supply, which would not be good. So we don't -- we prefer not to see the extremes in our business. I think though, when you look at the situation in the United States, we've got plentiful supply for the foreseeable future. And I think you've got a strong demand signal coming from power and LNG. And so I think it's unlikely on a sustained long-term basis that you see really high prices which I think is -- that is really good for our business.

And then I think you have seen the E&Ps be more disciplined in their investments. And they've also gotten more flexible in terms of their ability to manage those wells and turn them on and off as they see what I'll call shorter-term pricing. And so that also helps, I think, mitigate really strong downside risk. We'll continue to see volatility in this market. That can be caused by extreme demand and weather. That can be caused by supply constraints. So I'm not saying we won't see a lot of volatility, but I do think that prices will remain in somewhat of a reasonable range that will be supportive of our business.

Part of your business is refined products, and we'll talk to that later. We have a question around tank bottoms. And what are you seeing in the U.S. around inventories for refined products. How long can the Strait of Hormuz continue before there are physical disruptions?

Yes. So it's our customers' product, and so I can't exactly comment on that. But I would say we are moving tremendous -- one of the outcomes of this is we are moving tremendous amounts of petroleum products across our docks in Houston. So we have -- we've got rough over 40 million barrels of clean product storage in the Houston Ship Channel. And we've got four ship docks. We've got barge docks. And so we are seeing a large amount of product move. as a result of what's happening.

And I think long term, that is really good for the United States that we can potentially, again, be the reliable supplier for more of the world's market. I think to the extent that you get any decline in motor fuels, although we're not seeing that right now, then you can export. We've got the most efficient refining capacity, I think, almost in the world here. And a lot of that's being fed into our terminals in Pasadena and Galena Park. And so it's presenting -- it's a great opportunity for our customers to take advantage of.

It's not clear if we're not in the beginning of the crisis in Strait of Hormuz, and maybe we're closer to the end of the middle. If we stayed in the middle, people worried that you would have limitations, right, just physical limitations, and that gets solved one or two ways, either with a price signal, which we're clearly not getting much higher price or you get it through policy levers. We've seen one policy lever, and I'm going to ask about that, but I just more broadly talk about what policymakers should do. Talk about Jones Act tankers and how you think about that as a policy and how you've used that within your portfolio?

Yes. So we have 16 Jones Act tankers. For those of you who aren't familiar with the Jones Act, they have to be -- to move from U.S. port to U.S. port, you need to be -- it used to be U.S.-made, U.S. manned vessel. And so it -- and the idea behind the Jones Act originally, and I think still has a lot of important rationale for us today is that you want to be able to maintain shipbuilding capacity in the U.S. You don't want to be entirely dependent on the foreign market to be able to build ships.

And then secondly, I think from a national security perspective, it's an important policy as well. It's been in effect since the early 1900s. And I think there's bipartisan support for it in Congress and for good reason. We've seen a temporary waiver of it. Jones Act ships tend to have higher day rates than the international shipping market. Although early in this crisis, the international rates soared above the Jones Act rates. Now I think they've come back down below the Jones Act rates, but they tend to be a little bit more expensive because of the U.S. crews and the U.S. made, et cetera.

So our contracts on those with our customers are over 3 years on average. We don't really have anything that's significant that's coming up. I view the waiver as a temporary effort to try to address supply. And I think on a long-term basis, there's good rationale and good support for the Jones Act.

You keep the Jones Act to keep the ability, right? FDR, I forget which President, but the idea is you want a homegrown Navy and you want a homegrown ability of sailor, right? So having merchant marines that can feed a potential Navy in the future is probably a good thing. So it sounds like temporary waiver makes sense, permanent doesn't, if you're thinking longer term.

I think that's right.

One would think, given the role of the Navy in the Strait of Hormuz, abandoning the Jones Act doesn't feel like a long-term answer.

I agree with that, and the temporary waiver has had no impact on us.

What else could, should and should not policymakers do given today's disruptions?

Well, from our perspective, what we think is really important would be some type of permitting reform. And I think that would give more durability and more stability in terms of building the needed infrastructure across the United States in the long term. I think right now, the environment is great, but environments can change as administrations change. And so I think that if we had more long-term durability in those policies, that would be good.

Things like making the standards for courts to overturn certificates, a higher standard. Maybe it had to be -- the issuance had to be arbitrary and capricious. Making it more difficult, I think, for states to get in the way of projects, I think, would be good. I think if you look, the Northeast could desperately use more gas. And it is -- there's very close supply to the Northeast that is easily easy to get here but some of the state policies haven't allowed that.

So when you get to the winter, the Northeast is running fuel oil importing a lot of LNG. And so the marginal price on gas is the world market for the Northeast. So I think if you could help alleviate some of the state bottlenecks, that could be very good as well.

Yes. Touching on that a bit. If we could bring Northeast New York -- I'm sorry, Northeast Pennsylvania gas across New York into New England, -- that's interesting. There is a strong seasonality to New England. There's the permitting issues. But if you -- if the permitting was fixed, does the economics work to run a pipe to New England when there's such seasonal demand? Would the tariffs work for everybody?

I mean they would have to sign up -- either they would have to sign up for your own capacity or you would have to -- the seasonal service would have to come at an extreme premium to make it work. I mean when we tried to build into the Northeast back 2015-ish, the problem wasn't only permitting. Part of the problem was with respect to the independent power producers. They really couldn't sign up for some of the capacity because it was -- they couldn't get the capacity charges reimbursed. They couldn't recoup those, which made it uneconomic for them. So -- and that hasn't really particularly changed. So I mean, the Northeast market is a difficult one to solve.

If we talk about your strategy, 2/3 gas focused, big chunk refined product, carbon capture -- a carbon business, and we have a question on that. It would be great if you can touch on your upstream assets, CO2 flood in the Permian Basin. Is that a very economical side project in -- or does this provide a window into Kinder Morgan's future plans?

Okay. Let me talk a little bit about the background of how we got into this business, which I think is important. So we had a sales and transport business. So we were -- we were producing CO2 in Southwest Colorado. We are transporting it by pipe to customers who are using it to get oil out of the ground in tertiary recovery.

And what we found was a lot of people didn't know how to do that. And so we developed an expertise over time, all the reservoir engineers, et cetera, to help them get that out of the ground. And so we thought, well, hey, if we can do this on an opportunistic basis, meaning we can buy some of these fields on a good return on just a rundown basis and then get in there. And if we get a CO2 flood and that CO2 flood is successful, we can really blow things away, hey, wouldn't this be a good business? And that business, we require -- and so we did.

And we have 2 significant fields, SACROC and Yates. This overall, just to put in perspective, the oil and gas production business is 4% of our overall business. So it's not a large part. And then the sales and transport of CO2 is like 2% -- so overall, it's not overly significant. We require higher returns on that business to pursue investments there. So on a risk-adjusted basis, I think we get good returns in that business. And we have an expertise that I think is pretty scarce in the market. There aren't a lot of other people who know how to do this.

I think two things that, that positions us well for the future. One is to the extent that you can ever do CO2 flooding in some of these fracked fields and get more oil out that way, that would be a tremendous opportunity. I mean there's studies being done on that at this point in time. So unclear if and where that will be a potential. But if it is, it could be significant.

And then the second is we understand how to put CO2 in the ground, and we understand how to keep it there. And so CO2 sequestration conversations have slowed way, way down in the last 1.5 years, 2 years. But to the extent that ever picks up again, that would be an opportunity for us as well.

You all know how CO2 moves through the Permian better than anybody. That unconventional opportunity -- and you've chosen high-quality porous reservoirs with a lot of oil in place. And so you've picked the better pieces -- is there an unconventional CO2 flood? Is that something you spend time on? Or do you want maybe the E&Ps to go do the work there and then you can come to...

Right now, I would say we are mostly watching the pilot projects that some others are doing.

And then if we back up one level of strategy, I've often said people in the room might know, strategy to me is what you won't do as opposed to what you will do. I'll ask you that question, and I'll put it in the frame of international expansion, for example. What won't Kinder Morgan do?

So we have looked internationally a number of different times. And I think most significantly in Mexico, we also invested heavily in Canada over 2005 to 2015 period. And ultimately got out of Canada, found that it was hard to get infrastructure and especially regulated infrastructure built in that market. And so we sold out of that market.

In Mexico, we found it difficult to get returns that compensate us for the risk. And generally, that's what we found in other international markets as well. So I wouldn't say it's off the table. I think if we can find the right returns and an opportunity set that's big enough, I mean, I don't think you go do one project. But if you can find an opportunity set that was big enough at the right returns, that takes into account some of the incremental risk that you face, for example, currency when you go to the international market.

Then it's not totally off the table. We just haven't found that to date. Another thing that we have not done, which is more -- which is an adjacent business is the power development business behind the meter power. I think we've got tons of opportunity on our existing asset base. And I think generally, new businesses are hard, at least the first few years of them. And so I don't -- it doesn't make sense to divert our focus at this point in time. So I think what I think -- when I think about our growth, we're sticking to our knitting. We're doing what we know how to do. And so I think we have high-quality growth for our investors.

That growth comes from $10 billion backlog and you could -- another $10 billion, I don't know what you call it, it's not quite a backlog. Of the $10 billion backlog, 60% is power demand.

60% is power demand, 20% is LNG.

And what's the other 20%?

The other 20%, well, some of it is not natural gas. So there's about 12%, well, that's gathering and processing on the gas side and CO2. And then you've got a little bit of some of the other business products and terminals. And then it could be exports to Mexico. It could be industrial demand, other things on the natural gas side.

And of the $10 billion back backlog, what -- can you share a little flavor there? I don't know that you're going to give percentages or projects, but is it power demand heavy or comparable ratios?

I think it's power demand heavy is what I would say. And the reason we don't share a lot on the opportunities, the $10 billion opportunity set is it's a competitive market. And so we've got to go out there and compete against a lot of other pipeline companies and others for business. And so we want to make sure that we're not compromising our competitive position. But I would say, in general, it's kind of more of the same. Power heavy, a little bit of LNG and potentially the West Coast, potentially West Coast on the products pipeline side.

Is it a similar scale of singles, doubles, triples and home runs, right? You talked about half.

It is. It is. It is diverse in terms of that. So you've got singles and doubles and then you've got a few out there that are really big. And so it's a combination. I'd say it's largely heavily focused across the Southern United States, just like the existing portfolio of approved projects is.

And if I think about monetization...

Largely natural gas.

Largely. If I think about monetizing that $10 billion backlog, think about roughly $1 billion a year of maintenance CapEx for you all, $2.5 billion to $3 billion of dividend. And you're comfortable spending about $3 billion a year of CapEx to sort of move that backlog through the system. Is that the right math? Is $3 billion the right number? How do you get there?

I think $3 billion is the number that we can finance out of cash flow. So when you start looking at cash flow that's coming from our assets, after you pay the dividend, after you pay sustaining, there's, give or take, $3 billion. Now that $3 billion, I expect it to go up over time for a couple of reasons.

One, you're going to get more EBITDA as projects come on. And two, your debt-to-EBITDA is going to continue to come down over time. And so that's going to create more balance sheet capacity. Right now, we do have excess balance sheet capacity. And so if we have expenditures over $3 billion a year, we can easily accommodate that. So the target range on our balance sheet is 3.5 to 4.5x. Right now, we are sitting at 3.6x. So at the low end of the range, we expect we'll end the year about 3.7x because we did a $500 million acquisition.

We don't get all the earnings this year. So that will push it up a little until we get a full year of earnings. But every 0.1 turn on the balance sheet is worth $800 million of capital. And so you can spend significant capital on top of the $3 billion that we can spend just from cash flow that we produce.

And in theory, further down the line, JVs or partnerships would be another source of...

Our view is that there is unlimited capital for good risk-adjusted return projects. And so where we target to do our projects, I think if we needed to go get external financing to supplement our own internal financing, I don't see an issue with that at all.

And so then when you get these projects across your desk or across the board room on the table, what are the yardsticks? You've got the 6x CapEx to EBITDA ratios. You've got different projects of different scales. But ultimately, how do you allocate that capital? What project gets the green flags?

So a couple of things. One is when we're looking at it internally, we're looking at really the life of the project. So we're looking at an IRR, not a year 1 EBITDA multiple. The year 1 EBITDA multiple is more to facilitate for investors sort of the cash flow that we expect to come off of the EBITDA we expect to come off of these projects.

So we're looking at a 20, 30-year cash flow time horizon and the return that these projects generate. In terms of the $10 billion backlog with the exception of the 12% that I said is in gathering and processing and CO2, all those projects are already approved. And so really, we're talking about the incremental projects. The way we think about it internally is all of our business units know where the return hurdles are. And they vary.

For example, CO2 has a higher return hurdle than a natural gas project. A natural gas project does. And a gathering and processing natural gas has a higher IRR target than a transport project that's backed by a 20-year contract with a utility. So people generally know where those return hurdles are. And then we tell people, if you're close, or there's something unusual about this project or go ahead and bring it in and let's talk about it. And so we're talking about anything that's even close to our return hurdles. And then at this point, we haven't had to ration any capital. So if they're hitting the return hurdles and we're getting the right credit and then I think those projects are getting approved.

Any organizational capacity limits, where do you have an organization that can spend $3 billion, $4 billion, $5 billion?

I would say, right now, when you look at the $10 billion backlog, we are in really good shape. In terms of getting those projects built in terms of project management and operation staff you hire as you bring those on. But I think from a project management standpoint and execution of those projects, we're in good shape because we're prepared for that.

I think if you added significantly to that, then we would probably have to look at adding resources. But what I would say also is that generally, you enter into a project and then especially on the regulated side, there's a number of years to get your permit and to get the procurement done. And so a lot of times, what those projects are going to do at this point is they're going to start filling out the back end of the build cycle.

It's -- and the projects that come on more quickly, and so they might fill in during the existing build cycle, those are going to tend to be smaller just because they're going to get -- they're going to either not need a 7(c) from the FERC or they're going to be intrastate projects where you don't have the same approval process or they're going to be gathering projects.

But I think the big, big projects largely at this point will probably come towards the tail end. Right now, the existing project backlog has an average in-service date of the first quarter of 2028. So if you think about we're in mid-'26 and you need a couple of years on those big projects, that will start pushed towards the tail end of the term.

And then process, filters, appetite for M&A and then dispositions, how do you keep them pruning?

So everything competes for capital, right? And so I think we just did a recent acquisition, $500 million, not overly sizable, but a decent -- a single is what I'd say. And so it competes for capital the same way the expansions do. I think that when you look at those acquisitions, they come with in-place cash flow. So you're getting cash flow earlier. You don't have the same build risk with those. But you -- it also comes with a few unknowns. So they -- on a risk-adjusted basis, they compete with the expansions as does share repurchase. And as we said, we don't have any programmatic share repurchase. Our share repurchase is opportunistic.

Some questions are coming in. One is we can't have a session without talking about turbines. With materials, turbines, compression lead times, et cetera, so far out, what type of time line are you operating on for new projects? And maybe more broadly, what are some of the constraints you would worry about?

Sure. So we have lots and lots of discussion with our vendors on this. And so right now, historically, what you've seen is the long pole in the tent has been on big projects. So let me talk about the big projects that require seven Cs. The long pole in the tent has been the FERC 7(c) application. But with this administration, they have moved back, brought in the time to get a permit. And so with that, you start getting closer to the procurement to the time lines for procurement. But we're not quite there yet, okay?

So with a little bit more permitting improvement, then what you'll see is procurement could become the longer pole in the tent. But we are -- the way we handle it is as soon as we approve a project, we order the pipe and we order the compressors for the pipeline. And we've been in discussions with our vendors about that for months in advance of that.

The day that government permitting is faster than the supply chain. I don't know, is that a good thing or a bad thing?

Yes. And the other thing is a lot of the suppliers are adding capacity. Now it's not available right away. But in a couple of years, we should be in a better place.

And a follow-up on CO2. You're one of the few companies who has created an actual end use for CO2. Are there other sectors CO2 can be economically viable as an actual product besides green initiatives?

Not in our -- in the midstream space, not that I am aware of.

And then a question. You all are very careful with capital and returns that move the needle. The question about the small projects pop out? Or do small projects compete for the same returns as large projects?

It depends on the risk profile. So obviously, larger projects, you're going over long stretches of land. That comes with a certain risk. Smaller projects or typically, you've got a shorter build, right? So that -- it may have less risk from that perspective. It's all -- but you have to look at the counterparty credit. When you're doing the longer builds, you may have a utility credit, you're doing shorter builds, you may have somebody that doesn't have as good a credit. So all those factors go into the return and to the credit that we require as we go through and approve these projects. But I wouldn't say that we have a bias towards bigger or smaller. The bias is about the risk and the return.

Yes, the upstream side, sometimes you can do the large anchor project live with a 12% to 15% of return because all of the tiebacks are super high returns.

So that analogy works in terms of we still have to have a reasonable return on the big project, but would we accept at the lower end of our return threshold because this project has all sorts of potential offshoots, absolutely. And that is something that we frequently consider. I think we need to get to a certain minimum level of return on the anchor project. And -- but yes, I mean, we see that all the time where we build a project and we get a lot more benefits than what we expected in our initial underwriting.

And then on the project portfolio, we talked a little bit about GCX expansion. What should investors watch for in terms of delivering projects over the next 12 months?

Delivering projects, we've got a schedule of the projects that deliver over the next 12 months. Let me just talk about the big projects that we're working on. So if you look at those three, Trident, which is moving around Houston to the Southeast side for LNG and a little bit of power. That project, we are under construction today. And that project delivers in the first quarter of 2027.

Now that project had multiple phases. So it stages in over '27 and 2028. MSX, we're expecting our FERC certificate this summer, and then that comes in, in mid-2028. And then South System 4 comes in at the end of '28 and '29. It also has 2 phases. And as I said, most -- our average in-service date is the first quarter of 2028 on the entire $10 billion. So we've got a lot of growth coming over the next few years. I think '27, probably less of it than '28 and '29 have more of the growth that comes from the backlog.

And then in our last 2 minutes, ultimately, what's the value proposition for investors in the room beyond owning your stock?

Yes. I mean the -- it's an attractive dividend and nice growth. And the dividend is about 3.5% right now. We have been growing that dividend modestly. That dividend is well covered. It's about a 40% payout on cash flow from operations. We cover it by about 2.5x. It's underpinned by 65% take-or-pay contracts, 26% fee-based business.

We've got a very strong balance sheet, BBB rated -- BBB+ rated equivalent across the board at the low end of our leverage range. So very stable cash flow base to support that dividend and tremendous growth, high-quality growth in the -- with -- largely take-or-pay contracts in a business that we know well on the $10 billion approved backlog and the potential for more to come.

Fantastic. Thank you, Kim. Thank you, audience. I look forward to seeing you in further sessions.

Good morning, everyone. My name is Theresa Chen, and I am the North American midstream and refining analyst here at Barclays. It is my pleasure to host a fireside chat with Kinder Morgan, one of the premier U.S. midstream companies under my coverage with assets spanning across the country covering multiple commodity value chains across natural gas, crude oil and refined products.

And with us is President of Kinder Morgan, Dax Sanders. Welcome, Dax.

Thank you, Theresa. Really happy to be here. And I've also got with me Peter Staples and Sean Pogue, our 3-person massive European entourage here. So great to be here, and thanks for hosting.

Love it. So diving right in, maybe we look at the macro side of things first, Dax. Over the past 2 months and change into the U.S.-Israel war with Iran, how do you think the energy landscape has fundamentally changed with respect to the U.S.'s role in liquids energy supply, in particular, right now, what is the tone like in your conversations with producer customers amid the emergent call on U.S. onshore production? And maybe bridging that to your near-term expectations as well, what is your view on the time you're likely to see a step-up in activity across your...

Yes. Great question. I think all of us, certainly within the energy scope are reacting to news that changes seemingly by the hour. I think it -- with respect to long-term changes, it's pretty early to tell exactly what's going to change. I think certainly, our conversations with -- our direct conversations with producers haven't suggested yet that there's going to be a massive change. I think producers generally are looking for -- and this is part and parcel with the substantial cash flow discipline that's been imparted on U.S. producers over the past 10 to 15 years are looking for really long-term price signals before making substantial changes.

In fact, I saw an interview with Mike Wirth yesterday saying Chevron wasn't really making any changes at this point. Now I did see -- I haven't digested all the news in the last couple of days, but I did see, I believe, Diamondback, who's a large Permian producer as part of their reporting yesterday suggested that they were going to increase production -- crude production in the Permian. So I think if you see sustained price signals, I think you will see incremental production by U.S. producers.

Now that's really with respect to overall price response. If you look at the overall structural underpinnings of world energy production, world energy supply, I think there are probably going to be a lot of thoughts and conversations on where people are sourcing molecules of gas and barrels of oil vis-a-vis sovereign risk. And if people are looking at places and deciding that a particular place with the Strait of Hormuz being front and center, has a lot more risk than it maybe did 3 or 4 months ago than -- and they're looking for places that have less perceived sovereign risk. I think the United States is probably one of the first places they look.

And I think -- I mean my personal view is over the long term, this is going to be a substantial catalyst for incremental development, both with respect to production and associated infrastructure in the United States. And the first place, you're probably from an oil perspective is the Permian Basin. I mean Permian produces roughly -- it's the most prolific U.S. basin of about -- U.S. produces somewhere around 13 million, 13.5 million barrels a day of oil. I want to say about 6.5 million of that comes from the Permian Basin. It also is a substantial provider of gas, roughly 23 Bcf a day of gas coming out of the Permian. And that really is all driven by oil production.

It's -- we call them associated gas because oil is what drives the production decision, but gas comes out. And a couple of things. First of all, you can't flare it, you can't burn it, and it also has value. So that's led to a pretty substantial build-out of gas egress out of the Permian over the past, call it, 10 to 15 years. And so that's probably the first place you look from a crude perspective. With respect to gas, the -- I think of the world gas -- the world LNG ecosystem as being roughly 60 billion cubic feet a day, something like that. I think nameplate is greater than that, but if you factor in utilization rates, it's probably somewhere in 60 Bcf, maybe 65 Bcf. Right now, it looks like the best numbers, at least, I think that we have are that roughly a couple -- 2 to 3 Bcf a day of liquefaction capacity in the Middle East coming from Ras Laffan/North Field is out and going to be out for roughly 3 to 5 years. Now that could change. I mean the amount that's out could change tomorrow, but that seems to be what the number is right now.

U.S. liquefaction capacity is expanding. It's about 21 Bcf a day right now, up from a blending of about 15 Bcf a day in 2025, but it's effectively maxed out right now. There's incremental capacity coming online. And if you look at the basins that could provide that, the Permian is certainly one of those. The Marcellus, which is the biggest in the U.S. at about 36 Bcf, but it's reasonably constrained with egress capacity. And then you've got the Haynesville, which is right next to LNG corridor at about 15 Bcf or 16 Bcf. So that looks -- that's the landscape as we see it right now.

Super helpful, lay of the land as far as the key drivers and where everything is coming from. And Dax, I want to double-click on the commentary related to the call on U.S. LNG, supporting incrementally positive long-term growth outlook for feed gas operators like Kinder Morgan.

So we're still somewhat early days in the next wave of announcements and proliferation beyond what's been already under development. But what are you hearing from your liquefaction customers at the end of your pipelines in terms of additional expansions from here as a result of this call in the war? Do you anticipate further upward revisions to your already bullish outlook for feed gas demand growth as a result of all of these developments?

Yes. I think so. I think it goes -- it's part and parcel with, first of all, the capacity that's actually been taken off right now. And I think as well as kind of the thing I touched on with respect to the people's perception of sovereign risk. So I think that -- we think that right now, the U.S. gas market is about 115 Bcf a day, roughly 115 Bcf, 116 Bcf. We think that's going to grow or rather the latest WoodMac numbers suggest that's going to grow by roughly, I want to say, 19 Bcf over the next 4 or 5 years. Our numbers are actually a little bit more bullish. LNG growth is about 13 Bcf of that. So a pretty substantial piece of it. And we think that is -- that's going to continue. And you take one specific, and I don't have any information from this group, but you take Golden Pass LNG, which is one of the largest facilities coming on here pretty soon. That's 30% owned by Exxon and 70% owned by the government of Qatar.

The government of Qatar clearly owns and runs Ras Laffan and is the developer of the North Field, the largest -- presumably the largest field in the world. I think that it's probably reasonable to assume that their calculus over the last 3 to 4 months about what's the most practical to further develop has probably changed a little bit. So we feel good about that. And we've got -- one of the ways we're playing it, and we think that our angle in this as an infrastructure company is to build the infrastructure around the assets like LNG that are going to be key assets.

We have the largest natural gas network in the United States. We transport about 40% of all the gas around the United States, about 40% of the liquefaction capacity or gas going into liquefaction. And we've got -- right now, we've got a backlog of projects, and these are projects that are Board approved that are -- that have signed binding agreements with creditworthy counter-parties that we are deploying capital, actively deploying capital against. And that capital is -- about 60% of that backlog is actually related to power in the United States, but about 20% of it is related to LNG.

And one key pipeline we have on the LNG front is -- we call it the Trident pipeline is a pipeline that originates in Katy, Texas and goes north of Houston goes to the Texas-Louisiana border, ties into our network and some other pipes in the Texas-Louisiana corridor. It will transport about 2 billion cubic feet a day of gas. And this is gas that's coming out of the Permian. I talked about it earlier, that's moving into the Houston area. But there's only so much that Houston can absorb. It needs to move east into the markets East. And so we're building this pipe. It will be -- it will start to come online towards the end of next year, and it will be -- it's under active construction right now.

And it will come in over the next year, sort of following that, get to a full run rate after that. And so it will really take -- it will be a connector for Permian egress gas and moving it into the LNG and even to a lesser extent, power consumption corridors. And on that pipe, we've got -- we will have the ability to expand that pipe by an additional Bcf a day with just compression should the need -- should the basin continue to expand and the need arise...

And on that brownfield expansion, would that be rather quick in terms of turnaround and commercialization in your opinion?

Yes. We haven't fully scoped out what it would be. But generally speaking, compression expansions, as you noted, a brownfield compression expansion can be done a lot more quickly than a greenfield expansion where you're putting new pipe in the ground. So it definitely will be -- would be a lot -- we would be able to get it done a lot more quickly than the time line for this pipe, which is all greenfield new pipe in the ground.

Understood. So in addition to your sanctioned backlog, of which consists Trident and other things, I'd like to touch on your $10 billion of shadow backlog of natural gas projects and other projects. Can you share more details on these proposed opportunities, which are closer to reaching FID even from a value chain perspective without naming individual ones? How much more of this shadow backlog could you realistically sanction in the year ahead?

Yes. So just again, a little bit of a recap on -- because these are measures we use to communicate with investors on sort of what the future looks like and what we think we can develop. So again, starting with what we call our project backlog, which to reiterate what I mentioned a minute ago, those are projects that have been sanctioned that have binding proceeding agreements, long-term agreements that we are actually actively developing, spending money on. That stands right now at $10.1 billion. We just updated it recently.

That consists of projects that I said earlier, about 60% related to power. And again -- yes, sure. yes, yes, about 60% of our projects are power related. And within that, I mean, data centers get a lot of conversation in airtime, but the power demand that -- first of all, these contracts are generally with utilities. They're not directly with data center providers. They're with utilities that have generally solid investment-grade ratings, generally sort of an A- kind of level.

And they're for power related to everything from demographic changes, migration into the U.S. Southeast, coal to gas switching and power, reshoring of industrial demand in the United States as well as data centers as well. But I think the point is, is that there are a lot of drivers that we're seeing in our markets for incremental power that are beyond data centers. So -- and then about roughly 20% is LNG and the balance is other stuff, industrial, miscellaneous other things. So that's our backlog. Our shadow backlog that Theresa mentioned is another measure.

I mean investors have constantly asked us, well, what's next behind that? And so we've developed what we call our shadow backlog, which are projects that are under active development by our business development teams. What they are not are an idea that's a hope and a prayer that somebody just kind of came up with over lunch and sketched out on a napkin. What they are opportunities that we are in active conversations with customers on. We know that there is a demand. We know that there's a possibility of a project, but they haven't been approved by the Board.

They haven't been -- we don't actually have signed agreements yet. It may be a situation where we've got competition, and there's a lot of competition out there. We have competition with other potential providers or a customer may just decide to go in a different direction. So -- but these are projects that we believe have a really good chance of being developed. And generally, what will happen is over kind of a year's period of time, the projects on that list will work themselves out. And we will either get -- some of them we will get -- a lot of them we will get, some of them we won't. There will be new ones added. Some of them will go away. As we sit here right now, our shadow backlog looks a lot like our existing backlog. There's a lot of potential power demand out there.

Largest area of demand is probably the United States, as I mentioned, Southeast, which is where we have our Southern Natural Gas pipeline, which is a joint venture with Southern Company, the big Southeastern utility, which has a lot of power demand. There's also the Desert Southwest, where we have our EPNG pipeline out West. Again, there's a lot of competition out there with the Transwestern Pipeline. And in the Midcontinent as well, where we have our NGPL, Natural Gas Pipeline Company of America that we own 37.5% of. So those are really the drivers behind kind of what we're seeing in our shadow backlog. But there's a lot of opportunity in the U.S. infrastructure market.

Got it. So between shadow and sanction, $20 billion of potential opportunities out there, $10 billion and change of which has been officially sanctioned.

Yes, that's right.

Looking at data center side specifically, can you talk about Kinder Morgan's role in the SoftBank consortium, organized to develop a 9.2 gigawatt data center project in Ohio. Will KMI need to expand your existing footprint in the region? What will you need to do to serve this project?

Yes. Great question. And what she's talking about is there was an MoU that was released by the [indiscernible] it was actually released by SoftBank or U.S. federal government. But it effectively is a consortium of people led by SoftBank and led by a big source of capital from the government of Japan as well as a host of other people looking to invest a substantial amount of capital in the United States for data center development in different places.

We were named in that as part of that consortium. We are thrilled to be part of it. We're thrilled to be working with SoftBank and the other members of the consortium. There hasn't been -- and the potential opportunity associated with that is not part of any backlog anywhere. We don't have any signed binding definitive agreements. But we do continue to work with the consortium, and we hope that's going to lead to something at some point because the development is real, and we think there's a good opportunity. But we haven't announced anything. We haven't put any direct releases out ourselves. And again, just to reiterate, there's nothing associated with that in any one of our backlogs.

Understood. It is interesting that you're the only midstream company named within that consortium period.

Yes, that's right. And we were very happy to be the only one named in there. So...

So we talked a lot about your organic growth opportunity stacks. I'd like to touch on the inorganic side. Looking at your recently announced acquisition of Momentum (sic) [ Monument ] Pipeline, can you shed more light on the strategic benefit that this asset will bring to your system and as well as the rationale behind purchasing an asset that is comparatively more expensive than what you typically build on your own?

Yes. Great question. And just to be clear, it's the Monument pipeline that we -- no, it's all good. There's a lot of Ms out there. We -- yes, so the Monument pipeline which we announced with our earnings a couple of weeks ago, and we actually just closed on that last week. The -- it's an acquisition just north of $500 million. This is a short-haul piece of pipe just outside of Houston that ties really nicely into our existing network. It's got a set of customers, a small set of customers with the largest customer being a customer that is one of our largest existing customers on the same asset.

And so we look at a lot of M&A -- potential M&A transactions. Anything that's close to what we do, we look at. We're always looking at something. Most things we're not going to get. Most things, we're just -- there's some buyer that's probably willing to take more risk or underwrite more -- less concrete assumptions than we are. But if you look back over the last 5 years, I would say about every -- somewhere between, call it, every year, but call it, 6 months to 18 months, something will come along that is just an absolute fat pitch right down the middle of the plate. And this was one of those. It's a pipe that, again, ties right into our existing network.

There's an existing storage contract associated with this that the asset is that the seller had been using to supply storage service to the existing customers. We've got our own storage assets over time, we will transfer the storage, the providing of the storage service from the third party to our existing assets, and we've got some incremental capacity there that we're not using. So it's a really nice tuck-in acquisition. And exactly to your point, we are -- we're, I think -- as you noted, when we build new pipe, we generally are able to construct it at a multiple -- at a very attractive multiple. Our existing backlog, as we talked about, is about 5.6x build multiple. And our history suggests that we can do that or better with new projects.

Now even in the M&A market, even when we find an asset that we think is a really good fit, there's a lot of competition out there. And so generally, the price and the valuation for M&A assets is not as attractive as we would see on new build multiples, but still very attractive. So as we said, in the medium term, this will be sort of an 8x asset, and it's something we're very excited about, and I think it will be a really good tuck-in over time.

Great.

It will be a really good tuck-in day 1, but it will be really good over time.

Understood. And we talked a lot about your Gulf Coast assets as it relates to natural gas. In terms of the Permian needing additional residue gas egress, you clearly have a strong footprint there as well. Can we talk about your ability to execute on incremental expansions of GCX or any other flavor of Permian egress as you see fit as this demand grows over time?

Yes. Yes. Great, great macro question as it relates to us. So the interesting thing about Permian, we talked about the Permian at the beginning of the conversation, but the interesting dynamic about Permian gas is -- Permian gas egress is that it has -- egress was needed. There was almost no egress, call it, 10 years ago. And gas production started to grow and egress was needed and egress -- a decent bit of egress was built. And there was a lot of speculation and worry that the egress was getting overbuilt.

And guess what, gas production just continued to grow as the Permian grew and egress grew as well. And so we've kind of had this sort of one step, one foot in front of the other, incremental egress, incremental production growing. As we sit here today, the Permian is short gas egress. And really, what you do is you look at the difference between the Waha price and the Houston Ship Channel price and Waha is pretty consistently negative and which is, again, is the price in West Texas. We've got an expansion of our GCX pipeline we own, our 2 -- we've got several, 2 main and then a couple of ancillary pockets for egress out of the Permian heading eastward. We also have our El Paso Natural Gas pipe, which moves gas westward out of the Permian. But we've got a 570 Mmcf a day expansion of our GCX pipeline, which is coming online sort of like -- it's in the process of coming online right now. It will be in later this quarter.

With that, our pipes moving eastward are generally at capacity based on the amount of steel in the ground. There's also an additional 11 Bcf. I want to say it's about 11 Bcf of capacity -- egress capacity coming online with some other pipes, Hugh Brinson with Energy Transfer is building Eiger, a couple of other pipes. So as those come online, it feels like you're going to be -- you're going to have enough egress capacity out of the Permian.

Now again, if you go back to what we started talking about at the very beginning, if there is a call on additional Permian crude capacity or Permian crude production and Permian gas grows, you could be short again. And I think if there is a new greenfield pipe that needs to be built out of the Permian, I think we certainly would be there and be ready to participate in that. You could potentially even see another pipe, not compression, but looping of one of our systems coming out of there.

But again, just to reiterate, I think we are very well positioned to be able to take the gas. As it comes out of the Permian and moves eastward, it moves right into our network, into our Texas Intrastate system, potentially our Trident pipeline that we talked about. So we're very well positioned to move it even -- move it further eastward.

I think, Dax empirically speaking, the supply and demand balance for Permian egress has only surprised one side.

Yes.

We'll see.

Well said.

So turning to the liquids side of your portfolio. I want to give some attention to this, too, because you have some major development and projects here. So maybe first on what's recently been in effect. Your conversion of your Bakken system from crude oil to NGLs. Looking at that recent pipeline conversion, how do you think about the incrementally positive macro backdrop, the potential uptick in production at large for the U.S., what that means for the Bakken and how that alters expectations for subsequent phases of your NGL system as it stands?

Yes. So just to put a little finer point on what Theresa is talking about, we've historically had a crude pipe -- a crude egress pipe out of the Bakken that originates in the Bakken and goes down to Guernsey, Wyoming. We announced a couple of years ago the intention to convert that into a natural gas liquids line to bring natural gas liquids out of the basin. And that's in the process of coming online right now.

We've talked about potential future phases of that. And we don't have anything that we've announced on that. And I think as we've said before, given how competitive it is up there, that's not something that we've elaborated on a lot. although I would say we do put -- we are putting a lot of energy in sussing out the next opportunities there. With respect to the overall macro, we don't see the Bakken as having a tremendous amount of growth associated with it.

But that's okay from a gas. And we also have a crude oil as well as gas gathering operation in the Bakken. But we don't necessarily see that as absolutely necessary to potentially drive growth. I think the wells up there are getting a little bit gassier. So we are seeing incremental gas, and we are seeing incremental NGLs. So we think that there's opportunity to further develop our Phase 1, and we continue to work on that, but we haven't announced anything beyond that.

Fair enough. Elsewhere on the liquids side, touching on your refined products project. So on Western Gateway, following the conclusion of a successful second open season, can you provide color on the early learnings from both open seasons and whether your expectations for the project have changed at all relative to initial expectations?

Yes. Great question. I would say, first of all, expectations right now are reasonably consistent with what we thought about from the beginning. The interesting thing is the Desert -- the plumbing for refined products in the Desert Southwest in California has been in a relative state of equilibrium for the past 70 years. And what we're attempting to do with our partner, P66 is completely change that plumbing via this Western Gateway project that we're talking about. And the real change, the dramatic change that's happened over the past handful of years is you're seeing refineries in California shutting down. You've seen several -- you've seen a couple of convert to renewable diesel. You've seen a couple of shutdown.

And so refining capacity in California that has traditionally provided refined products to California and even moved products eastward into Nevada and Arizona is changing pretty dramatically. The other thing that you're seeing is the relative economics of PADD 2 refiners and even PADD 3 refiners has increased. And so what this project will do is reverse the flow of one of our pipes that's moving refined products from Southern California into Arizona to take products that will be brought from PADD 2 and Texas Gulf Coast eastward -- I'm sorry, Westward into the Phoenix area and take product from Phoenix to supply California. And what this does, what it would do is provide really the next phase of refined product security for consumers in the Desert Southwest, in Arizona, in California.

And so it's a big undertaking, but it's something we're excited about. The open season, as we said, was successful. The next phase, as we said, as I said on the earnings call a couple of weeks ago, is to negotiate a successful joint venture with our partner, P66, which we're working on. And we're optimistic that we'll get there and that we'll get it done. I mean there's enough -- big enough size of the pie to make this project work. But I mean, again, I think it's likely that we do. But if we weren't able to work something out, then we would go back to -- I mean, these are great assets that we have, and we would go back to the state of equilibrium that existed for the past 70 years. But we think this is a project that the market needs, and we're excited about it.

Well, on behalf of all California residents, we greatly welcome incremental refined products flowing into our state, I certainly hope this project passes FID. But to your point about the state of SFPP at this point, there is a lot of debate on the value of SFPP as it stands, either as contribution to this project or on a stand-alone basis. Can you talk about the EBITDA and earnings outlook for SFPP if this project was not to come to fruition? How do you see that evolving over time?

Yes. Well, first of all, these are really good solid assets. They're good cash flowing assets. They are assets in markets that are -- that have existed for a very long time with solid demand. There are certain places that they serve that have really favorable demographics. I mean, Maricopa County, both our East Line and West Line serve Maricopa County, which is where Phoenix is, which is a very fast-growing metropolitan area. We, in part, also serve the Calnev pipeline, which is serving Clark County, Nevada, which is growing as well.

So these are really good, solid growing assets. They've got really good traditional fixed cost economics associated with them. Those of you that know the way refined products and oil pipes work in the United States, every 5 years, the FERC sets an index adder or subtractor that you apply to the producer price index that sets effectively how much you can raise your tariffs each year. And so it's an inflation plus or minus. The past 5 years, it's been PPI plus 0.78%. FERC just reset it for the next 5 years at minus -- roughly minus 0.5% but again, that's off PPI, which is a substantially positive number.

So what that does is it provides an inflation escalation component to your tariff that allows you to raise -- basically grow revenue each year. So these are really strategically important assets. They cannot be replicated. You're not going to build a new gasoline pipeline in California anytime soon. And they are absolutely critical to meeting the demand that exists today. So these assets are -- these assets are going to be worth a decent valuation whether this -- whether they go into part of this JV or continue to operate as they have for the last 70 years.

Fair enough. And we spent the bulk of our time talking a lot about your fee-based assets, the fee-based contracts and the long-duration nature of those cash flows. But you do have a modest amount of torque within your system as it relates to this macro backdrop that I don't think we can ignore given the current environment. I'd like for you to talk about this potential uptick if either producer activity materializes or the elevated and volatile commodity price environment persists. Can you elaborate on the specific sources of earnings upside across your diversified footprint.

Yes. Well, the first thing I would say, even one of the most important aspects of our entire network, and this goes for the entire United States natural gas grid, but the utilization of our network back in 2016, 10 years ago was about 74%. And today, that number is at or north of 90%. So what that says is the competition for the incremental molecules -- space molecule in our pipelines just continues to increase.

And so we are able to benefit from that when situations -- when the right situation presents itself in extreme events like extreme weather events. So you've got that. That's probably the most fundamental thing associated with our business. But to your point about specific items related to torque, we do have our CO2 business, which is a tertiary oil production business. That business is a small part of our overall company. It generates about $300 million a year of free cash flow. We generally hedge about 90% of our budgeted barrels going into a particular year.

But we've got 10% that are generally floating throughout the year, to the extent that we outperform, we have the ability to capture that. We are outperforming in our crude production this year. We have a Transmix business where we are buying downgraded product and then upgrading it back to what it was before it was downgraded, so we get to capture that spread. We've got some Blending businesses. And then we've also got businesses that are -- those are kind of specific. We don't -- we do not have a lot of commodity exposure as an overall company, but that just highlights some of the areas where we have a little bit of commodity exposure.

With respect to volumetric exposure, I think to the extent you're seeing a lot of incremental volumes, if you're talking about torque, if you have high prices and then you have volumes that are driven by that, we've got gathering and processing. We've got a couple of Gathering and Processing businesses, I mentioned Crude business in the Bakken. We've also got a Gas business there. We've got a Gas Gathering and Processing business in the Haynesville. And then we've also got probably the largest number of export docks that accommodate refined products exports in the United States, and those are running about as full as they can possibly run right now. And we've also got crude pipes that have some exposure to the crude export market. So those are all things that are, again, the fundamental piece of our business is we are a Fee-based energy infrastructure business. That's our core business. But to your point about where do we have some torque, we do have a little bit of torque around the edges that we're able to capitalize on.

Wonderful. Well, we are about at time. Thank you all for participating and coming. Thank you very much, Dax, for this lovely discussion.

Thank you. Thoroughly enjoyed it.

Good afternoon, and thank you for standing by, and welcome to the First Quarter 2026 Earnings Results 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 call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. As usual, before we begin, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

Now I'm preparing for this investor call, I look back at the text of the introductory remarks I've made over the past several years. Most of what I've said concern the future of natural gas demand and the positive impact it has on midstream energy players like Kinder Morgan. In almost every case, the projections I may turn out to be understated. In other words, the demand for natural gas, driven primarily by growth in LNG feed gas demand and by increased utilization of natural gas for electric generation has simply grown faster than we expected.

Now I think events since the last call have made the outlook for growth even more positive. Regarding LNG demand, the recent events in the Middle East will clearly have substantial impact. While the ultimate outcome is certainly not clear at this point, the damage to Qatar liquefaction facilities and continued uncertainty regarding ship traffic through the Strait of Hormuz will lead to more preference for U.S.-sourced LNG and the predictions for growth in gas-fired electric generation have also increased.

In a piece that surfaced just this week, S&P Global Market Intelligence reports that utilities plan to add a staggering number of 153 gigawatts of gas fire generation capacity in the next several years primarily to serve data centers with the bulk of this coming online by 2030. Now this is twice the estimate by the same group of 1 year ago and reflects plans to build about 210 additional natural gas-fired facilities.

Our Kinder Morgan forecast for overall U.S. gas demand now extends through 2031, and estimates demand in that year of 150 Bcf a day and growth of about 27% from this year. In short, the natural gas story has legs and Kinder Morgan's strong start to 2026 that Kim and the team will explain supports that view.

While the old saying that rising tide lifts all boats has some applicability to this situation, there will clearly be some players who will benefit more than others from this positive story. I believe that the midstream sector as a whole will be one beneficiary, and it offers a low-risk way to invest in the growth story of natural gas, given the prevalence of long-term throughput agreements with investment-grade credits underpinning the bulk of midstream assets.

The Inga Foundation in a study released in March estimates that North America needs 70 Bcf a day of new gas pipeline capacity by the 2050 time frame. And I believe Kinder Morgan will fare very well in this environment. Let me tell you why. We have a superb set of assets located in the areas where gas demand is growing dramatically. Our strategy is to concentrate on expanding and extending those assets in an aggressive but disciplined manner.

This means we will continue to identify and pursue the myriad of growth opportunities we are currently seeing and once undertaken to complete the resulting projects on time and on budget. Because our cash flow is very strong, we will be able to finance these projects primarily with internally generated cash flow, and I can promise you an intense and unrelenting focus on these unparalleled opportunities.

This strategy will enable us to grow our EBITDA and EPS substantially over the coming years as these projects come online, while still maintaining a strong balance sheet and growing our dividend. To me, that's a pretty good recipe for success.

And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. We had a remarkable first quarter. The best I can remember with adjusted EPS up 41% and EBITDA growing by 18%. Importantly, every segment delivered growth versus the first quarter of '25 and every segment outperformed our budget. Natural gas drove the most significant share of the outperformance, benefiting from winter storm burn and the extended cold in the Northeast.

These results reflect the value of our critical infrastructure and the essential role it plays in serving our customers, especially in periods of high demand. During the quarter, we entered into an agreement to acquire the Monument pipeline system in Texas for approximately $500 million. These assets are a natural fit with our existing network, supported by long-term contracts and acquired at an attractive multiple. We received early termination of HSR yesterday and expect to close by the end of the month.

On full year guidance, we now expect to exceed our EBITDA budget by more than 3%, excluding any contributions from the Monument acquisition. Most but not all of that outperformance is attributable to the first quarter. Given that we are still early in the year, we've taken a somewhat conservative approach to our expectations for the year. However, continued outperformance in our gas group and/or higher oil prices, which benefit our 10% unhedged oil in the CO2 segment could provide upside for the balance of the year.

The growth in the overall natural gas market of over 36 Bcf since 2016 has driven utilization on our five largest gas pipelines to over 90%. That utilization, combined with the projected growth in the market to approximately 150 Bcf a day in 2031, highlight both the need and the opportunity for expansion. Our expansion project backlog increased to $10.1 billion this quarter, up $145 million from the last quarter. We put approximately $230 million of projects in service and added $375 million in new projects, including three data center deals.

The backlog multiple remains below 6x with an average in-service date of Q1 2028. With respect to our three largest projects, which make up over 50% of the project backlog, we continue to be on time and on budget. Beyond our reported backlog, we're actively advancing a number of identified opportunities. Much of this activity is being driven by power growth, and we expect a meaningful amount of these opportunities to convert into approved projects during 2026.

Our performance this quarter demonstrates the strategic positioning of our 78,000 miles of pipeline and 136 terminals and the tightness of energy infrastructure. As we look ahead, we're confident in our ability to complete our $10.1 billion backlog of projects, add to that backlog and deliver tremendous value to our investors.

And with that, I'll turn it over to Dax.

Thanks, Kim. Starting with the natural gas business unit. Transport volumes were up 8% in the quarter versus the first quarter of 2025, primarily due to increased LNG feed gas deliveries on the Tennessee Gas Pipeline. Natural gas gathering volumes were up 15% in the quarter from the first quarter of 2025 and increased across most of our gathering and processing assets with the largest impact coming from our Haynesville system.

Winter Storm firm and the extended cold weather in the Northeast contributed to higher volumes as well. Looking forward, we continue to see incremental project opportunities across our natural gas pipeline network. For example, we're in various stages of development on projects to serve more than 10 Bcf a day of natural gas demand in the power generation sector and opened 3 Bcf a day in the LNG sector.

In our Products Pipeline segment, refined product volumes were down 2% in the quarter compared to the first quarter of 2025 and crude and condensate volumes were down 12% in the quarter compared to the first quarter of 2025, with more than all of the decline in crude volumes explained by the removal of the Double H pipeline in service for NGL conversion in the third quarter of 2025. Excluding Double H volumes in both periods, crude condensate volumes were up 2% in the quarter compared to the first quarter of 2025.

With respect to Western Gateway, as noted in the joint release earlier in the week, KMI and Phillips 66 recently concluded a successful open season on the proposed Western Gateway Pipeline system. The next step is to finalize definitive transportation service agreements with the shippers and hopefully, acceptable joint venture agreements between KMI and P66. Assuming we can reach resolution on the noted definitive agreements, we would expect to FID the project sometime in the next few months.

In our Terminals Business segment, our liquids lease capacity remains high at almost 94%, market conditions continue to remain supportive of strong rates and the utilization of our tanks available for use is approximately 99% in our key hubs on the Houston Ship Channel and at Carteret. Our Jones Act tanker fleet remains exceptionally well contracted. Assuming likely options are exercised, our fleet is 100% leased through 2026, 97% leased through 2027 and 80% leased through 2028.

We have opportunistically chartered a significant percentage of the fleet at higher market rates and have an average length of firm contract commitments of 3 years and over 3 years when considering options that are likely exercised. The CO2 segment experienced 2% higher oil -- net oil production volumes compared to Q1 2025, led by a 5% increase in production at SACROC.

NGL volumes were 5% higher and CO2 volumes were 1% higher. Notably, RNG volumes increased 63% due to greater uptime at our facilities and greater hydrocarbon recovery as the team running that business has made great progress in improving the overall operations of those assets.

With that, I'll turn it over to David.

Thank you, Dax. So for the quarter, we're declaring a dividend of $0.2975 per share, which is $1.19 annualized and an increase of 2% over 2025. As you've heard, we had an outstanding first quarter, generating net income attributable to KMI of $976 million, an EPS of $0.44.

These are 36% and 38% above the first quarter of 2025, respectively. These very impressive results reflect strong demand fundamentals across the country, combined with strategically positioned assets and skilled execution by our colleagues to capture the associated opportunities, and we saw growth across the business segments. The natural gas segment grew the most with colder normal weather, driving additional demand across already highly utilized natural gas midstream systems, but the segment also grew from factors other than the cold weather with contributions from growth projects, greater capacity sales, gathering volumes and utilization across numerous assets.

In products, we benefited from improved commodity pricing as well as the recovery of retroactive rate increases we booked following a favorable court decision. And in the Terminal segment, we had increased volumes and rates in our liquids business as well as the benefit of storage contract buyouts, and we also saw increased volumes in our bulk business. For the full year 2026, while it's still early in the year, we expect to be more than 3% favorable to our budgeted adjusted EBITDA. That's over $250 million of additional EBITDA contribution. We clearly outperformed in the first quarter, and we expect additional outperformance for the rest of the year, driven by continued strong demand for our natural gas midstream services and the contributions from our Monument acquisition will be additive as well.

Moving on to the balance sheet. As we continue to grow our cash flow and remain committed to a disciplined approach to capital allocation, our balance sheet continues to strengthen. Our net debt to adjusted EBITDA ratio ended the quarter rounding down to 3.6x, which is down from the -- down from 3.8x from the beginning of the year. Leverage of 3.6x is the lowest for a Kinder Morgan entity since well before our 2014 consolidation transaction.

That being said, we expect leverage to increase slightly by year-end 2026. We expect increased capital spend during the rest of the year, and we will only get a partial year EBITDA contribution from the Monument acquisition. Our budget had us finishing 2026 at 3.8x, and now we expect to end the year 2026 at 3.7x due to our expected EBITDA outperformance, and that keeps us comfortably below our midpoint of our leverage target range.

During the quarter, net debt increased $82 million, and here's a high-level walk-through of that. We generated $1.49 billion of cash flow from operations. We spent $650 million on dividends, $800 million on total capital, capital expenditures, and we had about $120 million of other uses of cash, which gets close to the $82 million increase in net debt.

The rating agencies have now fully recognized our strengthened financial profile with Moody's upgrading us to Baa1, which means we are now the equivalent of BBB+ at each of the 3 rating agencies. Additionally, the treasury issued guidance in March that will allow us to more fully take advantage of bonus depreciation across all of our assets, and that creates nice near-term cash flow benefits, which will generate additional investment capacity.

With that, I'll turn it back to Kim.

Michelle, if you'll come on, and we will take questions.

[Operator Instructions] Our first caller is Julien Dumoulin-Smith with Jefferies.

Luke on for Julien. Nicely done on the quarter. Just wondering if you could help frame the expected Western Gateway scoping in more detail around like maybe initial capacity diameter, maybe even total project costs and how capital contributions are likely to be allocated between the partners just given the contribution of those assets you have?

I'll say a couple of things, and then Mike Garthwaite, if you want to add anything. I mean, I think as Dax noted in his comments, we've still got to negotiate the JV terms, and that will obviously impact what our capital contributions are going to be. We expect that we will be making, one, an asset contribution, and two, we will be making cash contributions. But exactly how that's going to lay out and the total cost of this project and some of those details I think we'll just leave that for once we get the project FID to get through these discussions, assuming that we get through these discussions with our partner.

Yes. And then I would say on the capacity side, I don't want to go into full detail as we work through and towards executing the final transportation service agreements. But you'll see the maps that we've consistently had out there, our line from El Paso to Phoenix is a 20-inch line that we focused on, and that gets the commitments that we've seen served plus some growth that comes along with that.

Awesome. And separately, you guys touched on this in your remarks, but maybe just looking to the Northeast and potential for maybe any expansion out there. There's this growing recognition that we may need to see more gas degressed into New England. Just curious for your thoughts on whether Tennessee could be a potential solution for that. And if you would need at the state and regional level to take another look at growth opportunities in that part of the state.

The need is clearly there. But I mean, I think we've said this a number of times, we would have to have certainty, certainty on state permits, and we would have to get the commercial support we need to underwrite a project. And last time, the commercial support was a problem. because the IPPs don't really have a way to get reimbursed when they take on long-term capacity agreements.

So you either need the utilities or there's not a lot of commercial support out there. So I think we have to have the commercial support and the permit. Somebody is going to have to roll out the red carpet. And then I think we would love to take advantage of the opportunity. But we've gone down that road once. We wrote off a fair amount of capital. And I think that's not something that we are interested in doing again.

Our next caller is Theresa Chen with Barclays.

Can you talk more about the rationale behind the Monument pipeline acquisition? What kind of synergies or growth opportunities does it provide for your broader system that you would not have otherwise been able to achieve with your existing assets in the area alone? And when thinking about the valuation, can you define more precisely what medium term means in terms of achieving that less than 8.0x multiple? And does it require incremental CapEx? And if 8.0 is indeed medium term, what would be the current or LTM multiple just to provide context as a marker for Texas intrastate gas assets in general?

And that's quite specific. Okay. So let me just say a couple of things about that. $500 million, as we mentioned, we've got long-term contracts that are underpinning this weighted average contract life on this is about 9 years. It's over 90% utilities and industrials with good credit ratings. It integrates well into our existing assets. It does allow us to access some storage on our system that we previously couldn't access.

There is some ongoing expansion activity that will require some incremental capital after we close, and that expansion opportunity will come in over time. I think it comes in and it starts later this year. And so I think that's what will help bring what is high single-digit multiple down is coming from that, primarily from that expansion. There are some synergies with this associated with our storage and I'll let people talk about some of that.

So just taking a step back, a couple of things. One, the system really integrates well on a last mile basis, it goes through Houston all the way down into the corp's corridor. So we see the demand profile there is very strong. It does bring an element of incremental no nitrogen supply in addition to what we are already working on, which over time, we'll see the value of that low nitrogen. And then as Kim alluded to, we -- these assets touch our storage -- our existing storage in ways that we can unlock certain value that an independent by itself cannot. So those are the 3 primary drivers. And once again, it just -- it makes good map is like what I'd like to say, and it fits real well.

In terms of the early termination of the terminal service agreement at Pasadena in exchange for a series of some payments. Did you recognize a lump sum in the first quarter? And if so, how much? And what is the expected lost EBITDA?

So let me say a couple of things on that. Yes, the lump sum gets recognized in the first quarter. And I think this is just a great job by our terminals team so we have the termination, they have gone out and they have backfilled all these tanks. And all these tanks are backfilled on a long-term basis. Some people are taking them currently and then their rate steps up over time as we improve connectivity.

And then one of the other customers is taking it in a year or so, 18 months. But in the interim, we are able to lease that capacity on a short-term basis. So we've been able to backfill all of this, the rates will step up over time and largely offset the lost earnings and with respect to that contract that was bought out, I think there is a little over a year remaining on that contract.

Through first quarter of '28.

Our next caller is Brandon Bingham with Scotiabank.

Just wanted to maybe talk a little more thematically about some of the dynamics you're seeing in the refined products market, thinking specifically around California and Western Gateway. How is demand evolving in light of the products pricing being seen on the screen and just the tightness in global markets? And just could that possibly create any expansion opportunity for the project?

I wouldn't say that it drives expansion for the project because I don't think the overall demand necessarily is changing California significantly. What this -- what I think the global situation does here is it highlights the fact that California has to import some of its supply and that makes it subject to the variability in growth markets.

And so what this does is instead of bringing in a fair amount of product over the water, they'll now be bringing in supply from Texas and from the Eastern United States. The other thing it does is it serves the Phoenix market, which is also right now reliant on the California refining capacity. And as you know, that refining capacity has decreased as a number of refineries have shut. So I think it's a great solution, I think, for California and for Arizona to be able to access domestic supply as opposed to having to be reliant on the international market.

Okay. Great. That's helpful. And then maybe just turning to -- you mentioned continued expectations for outperformance over the balance of the year. Is any of that tied to the dynamics created by the Iranian conflict? And how do those change, if at all, when this conflict comes to, I'll say, a firmer end or hopeful end?

Yes. I'd say the Middle East conflict has limited impact on us. Obviously, in our CO2 segment on the unhedged barrels, which is about 10% of our barrels, we're getting a higher crude price. On products, where you might anticipate it impacting us is just higher product prices impacting demand, but we have not seen that to date.

In our Terminal segment, I think our docs have been really busy. Our export docs have been very busy. And so record volumes across that. And so we do get a small amount of ancillary revenue resulting from those movements. But our tanks are sold on long term, what we can monthly warehousing charges, which are takeway contracts. And then on natural gas, not much in the short term. Obviously, we're moving a lot to LNG export facilities, but those are under long-term take-or-pay agreements. But as Rich said in his opening comments, longer term, it should drive incremental demand for U.S. LNG.

Thank you. Our next caller is Manav Gupta with UBS.

I wanted to ask you a little bit about the GCS expansion and at the same time, the Trident pipe. And what I'm trying to understand is there's a lot of gas moving towards East Texas, including your GCS expansion. And then egress from there to Port Arthur and Henry Hub might take a little more time, including your pipe Trident.

And I'm trying to understand if that might lead to some dislocation in pricing as we understand between Houston Ship Channel, Katy or Agua Duscher, how are you thinking about these localized gas markets as more gas from the Permian starts to pour in over there and the egress might take a little more time.

Okay, Manav. That was a -- I think, a two-part question. So first, both projects are on track. They're moving forward. I think in terms of basis dislocation, et cetera, I generally try and stay away from commenting on forward-looking pricing. But I can tell you, just at a fundamental level, there are always going to be dislocations, right, as you look forward, when you have demand coming on separately, then the supply getting across, and it goes in both directions. So what I would say there is -- is that a possibility?

Yes. I guess the reality is there's also a lot of demand from the power side that we're seeing coming up in Texas. We're talking about the power growth within Texas. So speed to market is very important there, and maybe there's a home for that supply. I'll leave you with that, and then you can kind of draw your own conclusions from that commentary.

And then the other thing I'd say just about our assets is we benefit a little bit on the margin from pricing dislocations in the short term. I mean, obviously, in the long term, those drive expansion projects. But most of our capacity on our pipes is sold under long-term take-or-pay contracts.

So perfect. That power comment is very helpful. My quick follow-up here is KMI is somewhat unique. You have nat gas storage opportunities, which some of your competitors don't have. Can you talk a little bit about -- I think in December, FERC approved a 10 Bcf expansion at NGPL's existing storage. And then I think at Bear Creek storage also, you had an open season. So can you talk a little bit about the nat gas storage opportunities in your portfolio?

Yes. Look, a very good question. And as we see this demand coming on and the scale of this demand, one of the big differentiators, and Rich alluded to, there's midstream opportunities, but there's some differentiator. Storage is going to be a key differentiator for us. We have those expansions on site that we're working on, especially the Bear Creek, not yet commercialized, but it's something we're working on.

And we're looking at that across -- looking at storage across our footprint, not only to be able to leverage these short-term dislocations, but long term, as you think about operational balancing needs that these large demand centers are going to have, the ability to put in gas into storage and also pull out storage on a pretty quick basis is going to be critical for their operations.

And that's somewhere where we think we differentiate ourselves quite nicely, having over 700 Bcf of storage in play and looking at much more to try and expand from an operating footprint standpoint.

Our next caller is Michael Blum with Wells Fargo.

I was going to ask all my questions at once, if that's okay. So first question really is on capital allocation, and it really encompasses both Momentum, this deal and Western Gateway. And the crux of it is you have significant gas pipeline investment opportunities at 6x investment multiples or better.

So I think you addressed the strategic synergies at Momentum. But on Western Gateway, is it fair to assume that the return on this project will need to compete with your gas pipeline investments? And then the second question is on Western Gateway specifically, can you clarify that if you lose any EBITDA from taking an existing pipe out of service for this project, it will be captured in the overall project economics.

Okay. Sure. So I think your first question is, do we look at Western Gateway the same as we look at natural gas projects. And I would say no change in our capital allocation strategy. We continue to target risk-adjusted returns in the same range that we always have. And so yes, this competes with natural gas. And so no change there in our approach. You asked about if we -- let me just say this, we're going to invest additional capital and we're going to get incremental EBITDA, and it will be at a nice return in order to do this project.

Mike, just to clarify one thing. We're buying the monument pipeline, not momentum.

Our next caller is Jean Ann Salisbury with Bank of America.

I had a similar question to Manav's about the Trident staggered start dates. As you mentioned, there's some concern that gas pipelines out of the Permian are going to come on well before gas pipelines to take them further east like Trident. So I guess my question is that if there's pull for more than the 30% of that gas on Trident in 2027, can you deliver that? Or is it really like that's the pace that you're bringing on Trident, if that makes sense?

Yes. I mean Trident is going to come on first phase, first quarter of '27. That's the schedule. And so there's no advanced gas that can get across until we get that pipe up and running.

Sorry, I meant like over the course of 2027, if there's more demand than just the 30% that you referenced in the news release. demand for 100% of it, for example, is that something that you could deliver or it's more of a downstream constraint?

Today, there is some incremental capacity versus what we would move in '27.

Okay. That makes sense. And then I guess my other question was about the NGPL 550 MMcfe expansion in the Panhandle. That seems like quite a lot of gas. And I was wondering if that's basically all demand pull for utility demand in that area or if it's partially people supply pushing out of the Permian and getting on to other pipelines after NGPL?

You're referring to the Amarillo expansion. Yes. Yes. So that is market pull driven by power.

Our next call is Keith Stanley with Wolfe Research.

I wanted to follow up on Western Gateway and just, I guess, how you're thinking about the project. So first, just confirm you'd be contributing the whole SFPP pipeline to the JV. I think that's $350 million of EBITDA or so. And then on the returns, just how you're thinking about it, do you look at it as just a return on the cash contribution you would make to the JV? Or do you also factor in that you're effectively upgrading the value of the asset with new long-term contracts and a more competitive supply source?

Okay. So it's not the whole SFPP system. It is what we call the East line, which goes from Amarillo to Phoenix and it's the West -- and the West line, which now moves product from California to Phoenix -- I mean, sorry, El Paso, I said Amarillo, El Paso to Phoenix on the East Line. And so those are the lines that are getting contributed to the JV. There are additional SFPP assets in California that will not be contributed. And then with respect to your second question, say that again about the EBITDA?

Just the returns, like do you think of it just as cash-on-cash return on your contributions to the JV or you factor in the upgrading of the project?

Well, I mean the way we think about it is what cash are we contributing and what cash are we getting back versus anything we might be giving up. And so we look at it on an incremental return on our capital. And it's based on an IRR. So it's not just what is the year 1 cash on cash, and we look at a full project IRR.

Got it. Second question on the strong quarter. Any color you can give on the impact that Permian gas spreads are having on the business? Is it single-digit millions, tens of millions, hundred million? And then any impact on winter storm fern specifically that you would call out?

I mean, I'll say a couple of things. The Waha-Houston Ship Channel, it does have some modest benefit for us. But our preference and practice for that matter, has been to sell transportation capacity to our customers on a long-term basis. And so what I'd say generally about winter storms is what happens is you just have a peak in demand and therefore, the services that we provide for our customers increase in value.

And whether that's storage services or that's transportation services, when you've got increases in bands, you've got high volatility and you have a system that's running at the high utilizations that we talked about, that just creates opportunity for us. And so I think that's what you're seeing in the first quarter results.

Our next caller is Olivia Foster with Goldman Sachs.

I wanted to start on the gas transmission opportunity set going forward. When we think about the various projects under commercial discussion and the shadow backlog, I understand a bulk of the opportunities are related to growing power demand. Is there any way to frame up other details about the general size or scopes of these projects and potentially as well the geographies from which you're seeing the most demand? We saw several projects move forward today, but what are...

I can describe it generically. I don't think it's really going to answer your question for me to describe this generically. And -- the reason that we don't give more detail around that is because most of these are competitive situations. And so we want to make sure that as we communicate before we -- before these projects are tied down that we don't say something that causes us competitive harm. But in general, I mean, what's in the project opportunity set beyond the backlog, there's a lot of power and there's also a little bit of LNG. There's some industrial, and it goes across the entire Southern United States. So there's opportunities going from Arizona all the way to Florida.

I would add, it's critical to understand, as I'm sure you do, that our pipeline network relates very well geographically to where the big demand drivers are in this country. So I think we are enormously advantaged by the share size and location of our pipelines.

That's very helpful color. I appreciate the details. Maybe for my second question, I'd like to ask about the macro for a moment. Are you seeing any signs of volume changes on your system in response to higher commodity prices, either from a G&P or potentially refined product perspective?

Refined products in the quarter are down a little bit, but we don't think it is a function of higher prices. As I said earlier, we don't think that the higher prices are yet having a noticeable impact on the consumer, but that's something we'll continue to watch. And then with respect to G&P volumes, most of our stuff is gas on the G&P side. Those volumes were up nicely in the quarter. They were up 15% in the quarter. And our KinderHawk volumes in the Haynesville were up 34%. So nice there. Our crude gathering position is primarily in the Bakken, and it's doing okay. Continental dropped rigs earlier this year, but prices are better. And so hopefully, at some point, some of our producers may increase rigs, but we have not seen that to date.

Our next caller is Jeremy Tonet with JPMorgan.

Just wanted to come back, I guess, to the tracking more than 3% above budget. And just wanted to refine that and see how much of that is kind of like onetime in nature versus recurring? Like if we're thinking about for '27 go forward, should we think about how much of that 3% would kind of come back next year on a regular basis versus maybe being onetime in nature?

Well, I think with respect to the buyout on terminals, obviously, that's somewhat onetime in nature. And then with respect to the balance of it, I think that's just going to be a function of, to some extent, commodity prices because on the margin, we do get some benefit from commodity prices. and whether you have winters in the future.

So to the extent that you're getting some good winter weather, system is going to remain tight for a while, we will -- our asset -- the value that our assets provide our customers will continue to be strong in those situations.

Got it. So it's fair to think of that bucket kind of the contract onetime weather, how it shook out and commodity prices are kind of the main drivers there?

Yes. I mean, I think volumes in CO2, production volumes are up. That's nice. And RNG did better. I think we already went through that. So products-based business is very stable and doing well. So I think the base business is performing very well. And then you have this increased demand and increased volatility and increased commodity prices that around the margin are just driving tremendous outperformance.

Got it. And actually, I just wanted to take a step back. We have not heard much conversation on carbon capture in some time now. And just wanted to see in the marketplace, do you see any demand for that? Or is that kind of completely gone away at this point?

I would say it's mostly gone away at this point. We're looking at a few things, but I'd say it's mostly gone away at this point. But I'd say we have the expertise here. And if the opportunity ever presents itself again, and we can do it on an economic basis, then it's something that we'll look at.

Our next caller is Elvira Scotto with RBC Capital Markets.

Given where commodity prices are now, can you maybe review your oil hedging strategy and just how you're planning to hedge out over the next year or so?

Yes. I mean we're 90% hedged for the balance of this year. And I think our $1 move in prices is a little less than $4 million. I think it's like $3.5 million. And then next year, we're like 70%, 75% hedged for 76% hedged for 2027. So -- and I think that's roughly at $65-ish $60 a barrel. And so our hedging strategy is -- remains the same in terms of, I'd say, the near term, we try to hedge a large majority, I'd say, 80-plus percent of the current year.

And we usually, by the time we get into the year, 90% hedged. And then with respect to year 2, we hedge that -- more of that as we move closer to it. And so I think at this point in time, being 70% -- 76% hedged on 2027 is consistent with how we've done it historically.

Years 3 and out, we typically are waiting to lay on some more hedges because some of your cost structure is driven by commodity price. And so we want to make sure that we match those 2 things up. So very stable cash flow in the near term, not huge amounts of commodity -- not large amounts of commodity exposure, some exposure on the margin, I think, is where we want to be.

And of course, to the extent that we outperform our plan, those percentages are based on planned volumes. And to the extent, as we said earlier, we are driving -- having a very nice year as far as volumes, and we'll sell those into the open market, obviously.

Our next call is Jason Gabelman with TD Cowen.

I wanted to first go back to Western Gateway. And I guess 2 clarifying questions there. One, is it in your project backlog? I know it hasn't been to this point, but I want to confirm, it's still not in there. And two, as you think about the steps that you need to complete to FID the project, would you say those are less difficult than completing the open season? Or do you still see a decent amount of risk of getting this project over the finish line?

Okay. With respect to the first question, no, it is not in our $10.1 billion backlog. We don't generally put any projects in there until they are approved/FID-ed, however you guys want to think about it. But -- and then I'll let Mike address whether -- what he thinks is the hardest.

Yes. I think entering into these -- as you go out with an open season, there's just a lot to understand in the market. And I think that was probably the harder piece. As we look forward to executing and getting to FID, there's, of course, the regulatory aspects that we've got to look at. But we've got experience through all the states that we're operating in. We have experience with those regulators and have confidence in moving that forward.

Got it. Great. And my follow-up is just on the commentary around future growth and kind of the more constructive outlook for gas demand in this country and you're talking about seeing kind of aggressive in your growth in your pursuit of additional growth.

Thinking back to the Permian pipeline going west that you didn't win, were there any lessons learned in that process that you're going to apply in competing for future growth opportunities in this country, particularly as you think about the competitive position of your asset base?

I think we approach that project the way we do all of our others. And so I don't think there was any specific lessons learned there.

Our next question is from Zach Van Everen with TPH.

Maybe when thinking through natural gas demand in the Gulf Coast. So I'm curious how much open capacity you guys have on NGPL Southbound if you guys were able to source more gas to that pipe?

So look, I mean, we are -- once again, you heard we're operating at very high load factors. I mean I think all the low-hanging fruit is pretty much off the table. We're looking at some expandability. You see some reservations that go out there. Clearly, we're working on an opportunity set that's pretty robust in both directions.

As you think about the demand side, you think about power, you think about supply aggregation and you think about movement to get supply to kind of end-use markets, I think the opportunity set there is pretty strong. But as far as specific capacity, I mean, we've got -- there's so many pockets of capacity out there on the EBB. It's out there, if there is any, but I would be surprised if there's any significant capacity in the key areas that you need it.

Got you. That makes sense. And then -- on KinderHawk, it seems like volumes continue to perform well there. Have you brought on a portion of that expansion project and maybe the cadence for the rest of the year, how you plan to bring that capacity on?

Yes. Look, so one, we're operating pretty much at our capabilities at capacity, and we're -- the volumes are there. We're still -- we still haven't brought on the expansion, but we plan on bringing it on as we layer it on through the balance of the year to add an incremental Bcf of processing capacity, and we're on track to do so.

And at the time, I am showing no further questions.

Okay. Thank you all very much.

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.

Okay. Good morning, everybody. My name is JR Weston, one of the midstream analysts here at Raymond James. I'm excited to have David Michels from Kinder Morgan here today.

Really interesting story, a lot of unique kind of growth opportunities here with the asset base that they have, especially on the natural gas side of things, in an interesting cycle here from a natural gas demand perspective with both the U.S. Gulf Coast LNG growth and also a lot of power opportunities and natural gas demand opportunities out there. And so Kinder Morgan is very well positioned to take advantage of some of these trends and translate that into nice growth for their business, one of the large cap kind of diversified blue-chip names in our midstream space. So just really happy to have them here to present with us today.

So I'll turn it over to David now.

All right. Thank you, and thank you all for participating. I'm going to start off with a legal disclaimer before we get going. So this is our forward-looking statement slide. Review this in our SEC filings for risks that could materially affect our expected results. Additionally, I'll be discussing certain non-GAAP measures during the presentation. For a list of non-GAAP measures and reconciliations, see our investor presentation and our website.

Okay. So as was just mentioned, Kinder Morgan is a leading energy infrastructure company. We are one of the largest energy infrastructure companies in the world, and we are the largest in the S&P 500. We move about 40% of all of the natural gas molecules that are produced in the U.S. on a daily basis, including the feed gas that gets liquefied and exported globally. So we are focused on U.S.-owned infrastructure, but we're becoming more and more connected with the global markets given our position in supplying feed gas to these liquefied natural gas facilities that then export to the rest of the world. We own close to 80,000 miles of pipeline, nearly most of that is natural gas. 80,000 miles of pipeline is enough to circle the globe 3x. So it's a lot of gas pipeline, a lot of other product pipeline, and it's a big responsibility that we take very seriously. It also gives us a great competitive advantage when going after new projects, and we'll get into that in a minute. And you can see on the left-hand side of the slide here, 67% of our cash flows come from our natural gas transportation and storage business. So that's what we're going to be spending most of the time today talking about is the natural gas market and some of the really interesting and exciting growth opportunities coming from that market.

Our overall strategy as a company hasn't changed much since Bill Morgan and Rich Kinder founded the company 29 years ago. We focus on assets that are key to the portion of the industry that they are located in. We focus on fee-based, stable cash flowing assets. Even though we're in the energy industry, we're focused on maintaining low exposure to commodity prices directly. So we -- you'll see our cash flow mix in a minute, but it's mostly take-or-pay or fee-based. We have a little bit of commodity price exposure and a lot of that we hedge.

So very stable fee-based cash flows. We prioritize a strong balance sheet and ample liquidity. We use -- we focus on funding our growth capital and our other cash flow needs with organic cash flow generation. And then we have a bias to returning value to our shareholders, and that's primarily done in the form of a dividend, which is well covered and sustainable. Then of course, running our assets in a safe and compliant manner as efficiently as we can is another key part of our overall strategy.

So as I mentioned, the cash flow stability and visibility is very high. This is a very high-quality form of cash flow that we generate. 65% are take-or-pay cash flows, which means we get paid for giving shippers the right to use the capacity in our assets. Whether or not they actually use it, we get paid for that subscription to our assets. So it's kind of like rent. It doesn't matter if you actually stay at that house, you pay the rent.

We have another 5% that's hedged. So for 2026 -- and that 5% hedged is pretty consistent year in, year out. And so for any given year, about 70% of our overall cash flows are fixed. Our revenue is known and it's going to be paid to us. So very high-quality form of cash flow, very stable and visible. Another 26% of our cash flows are from fee-based businesses. And so this is like a toll road. If a car rolls down the toll road, we get paid a fixed fee. Similarly, for us, 26% of our business is fee-based. So highly confident, stable business model.

Now moving back a little bit and looking at the overall industry and some of the trends that are unfolding. The current global natural gas demand is about 410 billion cubic feet a day as of 2024. And this is a Wood EIA forecast, and this forecast shows it going to 541 billion cubic feet a day by 2050. And to put that in context, the U.S. is the largest producer of natural gas today, and we produce about 115 billion cubic feet a day. So between 2024 and 2050, this growth would imply that we need to replace more than all of the United States natural gas production in the next couple of decades, which is a massive amount. And I think that speaks to some of the excitement around the opportunity set that we're going to talk about how this translates into U.S. opportunities. But on a global basis, this is a tremendous amount of additional natural gas demand that is forecast to come to the market.

And how does that translate into the U.S.? This is going back to that liquefied natural gas. We are the exporter of choice for many countries across the world because many of the countries that are driving that natural gas demand that we just talked about don't have adequate or natural resources at all to supply their internal demands. And so they're looking for other countries to supply liquefied natural gas, which is the -- really the only efficient way to transport natural gas internationally. To liquefy it and then put it on ships and then re-gas it when it goes to its host country.

The U.S. is particularly well suited because we have a very robust set of infrastructure, pipelines, storage. Well-known basins, excellent producers. EOG was just in here earlier. They're one of them, excellent producers who have been very efficient and capable at unlocking new sources of reservoir, new sources of molecules to produce. And we also -- and I think in the Iran conflict that's happening right now, I think this is underscored we have a relatively low geopolitical risk in America. So a great partner for many of these countries who are looking for not just the next 5 years of supply, but the next 20 or 30 years of supply, signing up for those types of contracts takes great confidence that you're not going to get interrupted because of geopolitical concerns.

So that's the international part of our business and how it's growing and why it's growing. Domestically, we're also seeing an increase in natural gas demand. So we're not just seeing international natural gas growth driving LNG demand, but we're also seeing domestic demand for natural gas increase. Industrial businesses, a lot of them can't be electrified. And so natural gas is one of their choice feedstocks to supply the catalyst for high heat content type industrial processes.

We're seeing incremental growth from residential and commercial businesses, but we're really primarily seeing a lot of growth from power generation. This was something that we started seeing unfold over the last 3 to 5 years. Population migration, so population moving from parts of the country to other parts of the country, increasing the overall power generation demand for those parts of the country that are attracting new population to them.

Coal to gas conversions, we still have a lot of coal power generation out there, and that is more slowly today under the current regime, but still transitioning from coal to the other dispatchable form of electricity production, which is natural gas because it's -- you've got three dispatchable forms of electric power generation: Nuclear, coal and natural gas.

Nuclear is still a difficult one. still haven't figured that one out completely. I think the small modular reactors might be something on the horizon, but still many, many years away. Coal, as we talked about, is being environmentally and economically phased out. So it leaves us with natural gas. So as these coal facilities are switching over and converting coming to their end of their lives or just being environmentally phased out, they're being most often being replaced with natural gas power generation.

And then, of course, we can't leave this slide without talking a lot about data centers and how much additional power generation is coming from the whole revolution of artificial intelligence and the associated data centers that are required to power them. We're -- I think the total amount of additional demand from that category is still to be seen, but it is definitely incremental to what we had been seeing prior to 2024.

In 2026, some of the recent estimates, and I'm sure everyone has read something about the scale of this investment and the stimulus that it's providing. But in 2026, the five largest hyperscalers are expected to spend over $700 billion in AI investments, which is just incredible. And for us, we're seeing great demand for additional power generation and a lot of that is directly attributable to the power that is being used to fuel these data centers.

We have over 5 Bcf a day of new hookup requests, which gives you a sense for how much new power gen is being requested. Where is that data center capacity being built? Here's a sense for the announced data center capacity by state. And then the red bars are the bars where we have significant infrastructure presence. The gray bars are where we don't.

So the vast majority of these, about 70% of all of this announced data center capacity are in states where we have significant infrastructure capacity to serve that additional load. This represents about 210 gigawatts of power demand. And if they were all gas, that would be 32 billion cubic feet a day of additional natural gas demanded. And again, about 70% of that is in our backyard. So it gives you a sense for the scale and the competitive advantage that our assets have going after some of these data center capacity builds.

Speaking of our competitive advantage, this slide shows you on the right-hand side. So this is bringing it back together. The left-hand side is total natural gas demand for U.S. supplies. Today, as I said, our market is about 115 billion cubic feet a day. And the red line is Kinder Morgan's forecast growing by 26 billion cubic feet a day through 2030. The darker line is Wood Mackenzie's forecast growing a little bit slower, but still growing quite substantially. Both are 20% or low 20% growth over this time frame, which is less than 5 years away now.

And you can see on the right-hand side, the key factor to any peer in this midstream industry to securing additional infrastructure growth projects is, do you have assets nearby that can integrate with or that you can expand off of in order to accommodate this additional load growth? And so the existing miles of pipeline that you have in the ground is very important with regard to securing these additional projects. And you can see here, we have over 58, 000 miles of major interstate pipeline in the U.S.

And so it's much more than our nearest competitor and more than double all but two of our competitors. So we're pretty well positioned to take advantage of this underlying growth trend that we're seeing. Additionally, the existing capacity that we have -- so that was more focused on growth and securing additional projects to meet that additional growth. But the existing capacity that we have is also increasing in value because that capacity is getting full. We'll talk about that in a minute. And you're seeing not just incremental natural gas power -- natural gas demand across the year, but you're seeing it incrementally getting more peaky -- so this is -- these are two lines. One is 2015 average daily demand for natural gas in the U.S. The other one is 2025 average daily demand for natural gas in the U.S.

You could see down in the average temperature range of moderate temperatures, 50 to 70 degrees, the difference between these two bars is, call it, 10, 15 Bcf per day. But as you go to the extreme temperature areas, you could see the differences become closer to 40 billion cubic feet a day. So it's showing you that in cold temperatures and in warm temperatures, the peakiness of the delivery and the capacity needed is higher than kind of the average incremental load over these two periods of time.

So these -- the peak day demand is becoming greater, which means additional storage and pipeline capacity is growing even faster than you would suggest from this page. That 26 Bcf a day doesn't speak to how peak day demand is growing even faster. So that gives us additional growth opportunities, but it also speaks to the value of the existing assets and how important they are.

Okay. And this speaks to, again, kind of the concept that I talked about earlier, the existing capacity becoming more and more valuable. Between 2016 and 2025, the natural gas market in the U.S. grew 44% from 79 Bcf a day to 115 Bcf a day. A lot of that growth was accommodated through existing pipes that had spare capacity on them. And so you didn't see as many growth projects being built as you do in today's market because back then, we had a little bit of spare capacity and today, it's more or less gone on all of the major facilities.

So on the top right part of the page, you can see our 2016 5 pipe average, our 5 largest pipelines that stretch across America, we had a utilization of about 74%. And in 2025, that utilization grew to 90%. That's pretty much full because in the summer and the winter are when we have peak demand and in the shoulder months is when we have a little bit less demand. And so 90% is basically full. You don't really have any spare capacity. And that's playing out. We're seeing it in the values that we're getting for our service, but we're also seeing it in the tenor that our counterparties are willing to sign up for.

You can see in 2016 on those 3 pipelines that we have listed here, the average length of contract was 5 to 6 years. And in 2025, that grew to 7 to 8 years in term. So people are recognizing the value of that capacity and are signing up for longer terms at higher rates, which is all good for infrastructure operators like us.

Okay. So where are we -- that's the backdrop in the industry and where does that leave us today? That leaves us with a very nice robust project backlog. So this is our 5-year committed project backlog, $10 billion in total projects. These are projects that have been sanctioned, approved by our Board. Many of them are under construction. So a high degree of confidence that we are going to be building these and we'll be putting those into service.

Mostly focused on our natural gas area, not a surprise. Strong build multiple here, 5.6x CapEx to EBITDA, very good returns. And again, these are projects, and we'll talk about where some of these are built, but a lot of these are built right in areas that we're very familiar with. So we have a high degree of confidence that we'll be able to construct as well, which is important.

Yes. So this speaks to -- so this slide speaks to the projects and the experience that we have in building large natural gas projects in the U.S. and how successful we've been able to build those and bring them into service. So we spent $5.4 billion on projects from 2021 through 2025, 273 individual projects, and we put them into service pretty much right on line with our expectations.

A little bit of variance on both cost and schedule, but well within a reasonable band of tolerance. So we know how to build these projects. We have a great track record in putting them into service recently. And so we're not expanding our business by entering a new business line or extending ourselves outside of our core competency. We are doing what we do best, which is build natural gas pipelines in the United States.

And here's a list of some of the largest projects that we have signed up right now in that $10 billion of project backlog spend. Just -- I'll just touch on the top 3. South System 4 expansion number one and number three, Mississippi Crossing. You can see on the right-hand side of the page there, they're both taking gas kind of out of the tea corridor there just to the east of Texas over into the Southeast states. That's been a part of the country that's been short on natural gas supply for many years now, and we've gotten to the point now where they've reached critical mass where they needed some real significant incremental capacity to those markets.

And so -- so we're building those two pipelines, which Mississippi Crossing provides liquidity to the South System for expansion to get it all the way over into the Carolina markets, bringing 1.3 billion cubic feet a day of capacity into those markets and our customers are excited about that. They recognize the need for it, and we're actually even starting to talk to them about the next expansion. So a great area to construct pipeline excellent committed commercial contracts with customers that we know very well, they're utility customers, Southern Dominion, Duke, Ogalthorpe,who's a very high creditworthy counterparties as well.

And then the other one is #2, which is it's a smaller pipeline, but it's a substantial build. It's moving from the Katy hub to which is west of Houston over into the Port Arthur market, which is where a lot of the LNG demand is. Katy is where some of the pipelines from the Permian are being delivered into and so that we needed to debottleneck that area between Katy, go up and around over Houston, down into the Port Arthur market in order to get that liquid molecule over into where the end market really begins.

Exciting build. We're already under construction on that one, great counterparty contracts, very good return. 2 billion cubic feet a day of capacity and everything is on track with all three of those major projects. So what's next? Beyond that $10 billion of projects that we've already sanctioned, we're working on the next -- our business development teams aren't working on those anymore. Now they're focused on the next set of projects to backfill those and then to potentially grow even more beyond those.

We have over $10 billion worth of identified specific projects that our business development teams are working on right now, incremental to the ones that we just listed. And the growth drivers behind those incremental new greater than $10 billion of opportunities are similar to the ones that we just talked about. I said, we're already working on potentially adding additional supply projects to the Southeast markets. We're working on debottlenecking within the Texas and Louisiana markets, which is becoming increasingly more important as these LNG facilities continue to come online. You saw how large that LNG market was growing. It's almost doubling between 2024 and 2030. So we're going to see additional debottlenecking efforts required to accommodate that flow.

And then throughout the country, we've got the power generation demand, industrial growth. We've talked about coal conversion all very, very exciting things. Exports to Mexico is another one. Mexico's production is declining. And so delivering additional gas down to Mexico is also another factor of growth that we're focused on. Meanwhile, our financial profile has improved nicely. So we're meeting this time when we have this very robust opportunity set with a balance sheet that's in really good shape. We've been generating some good growth as it is, we've had a cadence in our dividend that's allowed us to have a dividend that is well covered and sustainable. So over the past decade, we've been growing our EPS by about 8% annually while decreasing our leverage by 26% over that same time.

Our leverage target range is between 3.5x and 4.5x. We're at 3.8x right now. So we're a little bit on the low end of that. We're below the midpoint of our leverage target range. So we have a little bit of balance sheet capacity. We're generating cash flow from operations of $6 billion, which means we have about $3 billion annually to spend on these growth investments. So we have a great amount of cash flow internally to support these investments that we're making. We don't have to rely on the external capital markets to any large degree.

And then our dividends, you can see here, we've got this good cadence here where we've been growing. And growing at a little bit of a slower pace relative to our cash flow growth, and that's added to the sustainability of that dividend over this time. You can see we've taken advantage of some of our lower stock prices those light gray bars are share repurchases.

All right. So yes, that kind of brings us to the end. And just to kind of wrap up here, we're very excited about the growth projects that we have. We're very pleased with our recent performance. We're very pleased with the fact that we've got our financial profile in the shape that it's in, in order to meet this current opportunity set driven by the opportunities, driven by the dynamics that we've talked about through this presentation, and we're very optimistic about our future.

So that's it. I think we have a couple of minutes left for questions.

I appreciate that, David. Thank you. Any questions here from the audience?

Maybe one for me here, David. Just, you had there on the slide about the $10 billion of kind of additional growth projects out there. Can you just maybe speak to -- some investors probably understand some of the kind of the secular growth themes that are out there. But just translating that to growth opportunities for the company. How much easier or harder is it getting to kind of convert those project opportunities into real projects that move into your backlog?

Yes. They're always hard. Otherwise, everybody would be doing it. So -- but in some degree, there's greater recognition that existing capacity is full. We talked a little bit about that. And so there's a little bit more urgency to get some of these projects built because they recognize, I think our customers recognize how long it takes to build these things. There's just a standard amount of time to permit and build and get these things constructed. It's not like a digital transformation. There's a lot of physical work has to be done. You cannot bypass.

And so I would say in some regard, it's gotten a little bit more efficient to sign up commercial contracts in current environment relative to where we were 5 years ago, but it's still really tough. And then I would say the other thing that I think I failed to say before is with the $10 billion of committed project backlog that we have today, plus all the projects we're planning to sanction in order to backfill those. If you convert that at the -- at the EBITDA multiple that we talked about earlier, it's a $500-plus million a year of additional EBITDA.

So good single-digit growth on our EBITDA basis, which translates into a high EPS -- high single-digit EPS or low double-digit EPS growth rate, combined with the dividend yield that gets you to a total stock return that's pretty compelling.

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Yes, that's a great question. That's a really good question. We're focused -- that's one of the big risks, I would say, to our -- to the overall story here because the projects are there, will the equipment and the labor be available for us and for others to build especially with the backdrop of all these data centers that are being developed? There are some components of labor that are going to be competing for those same projects.

Over the past year, we've bid out three of our major projects, and we've talked to our -- the qualified contractors and what kind of capacity they have in the next 2 to 3 years when we'll be building these. So far, there is adequate capacity from major qualified labor contractors. The equipment is getting a little bit longer lead time. compressor units are 2 to 3 years backlog.

And so we're working on some alternatives for us to look at there. But I think that just puts more pressure on us to make sure that our scheduling is appropriate. We're signing up and we're getting committed contracts with our labor contractors and we're signing up for all the long lead time materials well in advance of when we need to put them into service. So far, that's working pretty well, but it is something that we're watching really closely.

And just real quick, David, are you able to -- in some of these situations where you have some cost inflation still pass through some of that and kind of protect that?

That's great. That's a great point. So what we try to do is we try to anticipate the cost escalations associated with the tightness in the market and pass those along in the form of the rate that we're willing to sign up for with our customers. In most cases, we're able to do that pretty well. And a handful of cases we're actually able to put it into the contractual arrangement with our shippers, cost escalations, unforeseen at the time that we sign up the contract with them to sanction the project.

Again, I think that is something that -- that's pretty rare. In the past, we didn't see that as something that the shippers are willing to sign up for. But today, I think because of the fact that capacity is tight and the urgency to get this supply to market is so great, we are seeing more willingness to share and cost overloads.

That's perfect. We're out of time here.

Good afternoon and thank you for standing by, and welcome to the Fourth Quarter 2025 Earnings Results 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 call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

I have only 2 comments before turning the call over to our CEO, Kim Dang and the team. First, we believe our bullish outlook on natural gas demand remains grounded in reality, and we expect to see very strong growth over the rest of this decade and beyond. Now while there are several important drivers of that growth, the largest and most certain driver remains the need for additional LNG feed gas to service both expansions of existing export facilities and new greenfield projects coming online. We now estimate feed gas demand will average 19.8 Bcf per day in 2026, which is an all-time record an increase of 19% from the daily average of 16.6 Bcf per day in 2025. And we see that demand increasing to over 34 Bcf per day by 2030. This astounding growth is enormously beneficial to the midstream sector and especially to companies like Kinder Morgan that have extensive pipeline networks along the Texas, Louisiana Gulf Coast, which is the location of most of the export terminals present and future.

Our throughput agreements for delivery of the feed gas are essentially take-or-pay in nature which gives us great confidence in the resulting cash flow. My second comment is specific to Kinder Morgan. You will hear from Kim and the team that we finished 2025 very strong compared to 2024 and to our budget for 2025. And as you know from our earlier release of the budget for 2026, we expect more good performance this year. Once again, the chief driver of our success in both years is the extraordinary strength of our natural gas assets.

And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. As Rich said, we had a fantastic fourth quarter, producing record results for the quarter and the year, much stronger than we anticipated when we announced our Q3 results.

For the quarter, adjusted EBITDA was up 10% compared to the fourth quarter of last year and adjusted EPS grew 22%. Those are big numbers for a stable midstream business like ours. The biggest driver of the outperformance was natural gas. It had an outstanding quarter and year. Our project backlog has increased by approximately $650 million to $10 billion. We added a little over $900 million in new projects which was offset by $265 million of projects placed in service. The most 2 significant additions are Florida Gas Transmission projects, both supported by long term for contracts. Our backlog multiple remains below 6x, which will drive very nice growth over the next few years. In addition, we're working on greater than $10 billion in project opportunities beyond the backlog. While we won't be successful on all of those, it gives you a sense of the tremendous market opportunity. We believe we will continue to find attractive opportunities for years to come. Wood Mac currently projects the U.S. natural gas market will continue to grow over the longer term, with an incremental 20 Bcf a day of demand growth between 2030 and 2035.

Now a quick update on our 3 largest projects, MSX, South System 4 and Trident. We started construction on Trident last week. And for MSX and South System 4, we received our FERC scheduling order. The FERC anticipates issuing our final certificate by July 31, which is a schedule we requested but ahead of our original expectation. There's still a lot of work ahead, but all 3 projects are on budget and on or ahead of schedule. Another positive last week, S&P upgraded KMI to BBB+. That shows our balance sheet is in great shape.

On the management front, I want to take a moment to recognize Tom Martin, who will retire at the end of this month for his wise counsel and the value he has helped delivered to our shareholders over his 23 years with the company. As we have previously announced, Tom will continue to serve as an adviser to the OTC and the Board, so we'll continue to benefit from his perspective. We're excited to have Dax, who many of you know from his long tenure at the company step into the President's role. I'm looking forward to working with them closely as we continue to execute on our strategy. To sum it up, we had a great quarter and year. We also strengthened our balance sheet and advanced key projects with a $10 billion backlog and tremendous potential beyond that were set up for a very exciting future.

And with that, I'll turn it over to David -- Tom.

Thanks, Kim. I appreciate the kind words. Starting with the natural gas business unit, transport volumes were up 9% in the quarter versus the fourth quarter of 2024, primarily due to increased LNG feed guest deliveries on Tennessee Gas Pipeline. But the full year transport volumes were up 5% over 2024. Natural gas gathering volumes were up 19% in the quarter from the fourth quarter 2024 across all of our G&P assets with the largest impact being from our Haynesville system. Sequentially, total gathering volumes were up 9% and the full year 2025 gathering volumes were up 4% versus 2024.

We experienced a significant ramp-up from our producer customers during the quarter to meet the growing LNG demand. Our Haynesville gathering system, for example, set a daily throughput record of 1.97 Bcf a day on December 24. Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network. For example, we are in various stages of development to potentially serve more than 10 Bcf a day of natural gas demand in the power generation sector.

In our products pipeline segment, refined products volumes were down 2% in the quarter compared to the fourth quarter 2024. For the full year 2025 refined products lines are about equal to '24. Crude and condensate volumes were down 8% in the quarter compared to the fourth quarter of 2024. More than all of that decline is driven by taking double age out of service for the NGL conversion project early in the third quarter of 2025. Excluding HH volumes in both periods, crude and condensate volumes were up 6% in the quarter compared to the fourth quarter of '24. On January 16, 2026, KMI and Phillips 66 announced the start of the second open season on their proposed Western Gateway Pipeline system. Western Gateway Pipeline will connect Midwest and other refinery supply to Phoenix into California with connectivity to Las Vegas, Nevada via KMI's CALNEV Pipeline. The second open season, which concludes on March 31, 2026 is for the remaining pipeline capacity and adds new access to the Los Angeles market via a joint era supported by the planned reversal of one of KMI's existing SFPP lines between Watson and Colton, California.

In addition to expanding the offer destinations, the second open season adds additional origin points to enable supply diversification and optionality for our customers. We believe this project provides an attractive supply alternative for markets in Arizona and California. In our Terminals business segment, our liquids lease capacity remained high at 93%. Market conditions remain supportive of strong rates and the utilization of tanks available for use is 99% at our key hubs on the Houston Ship Channel and at Carteret, New Jersey. Our Jones Act tanker fleet remains exceptionally well contracted, assuming likely options are exercised. Our fleet is 100% leased through 2026, 97% leased through 2027 and 80% leased through 2028. We have opportunistically chartered a significant percentage of our fleet at higher market rates and have an average length of firm contract commitments of more than 3 years. The CO2 segment experienced 1% lower oil production volumes lower NGL volumes and 2% lower CO2 volumes in the quarter versus the fourth quarter of 2024. For the full year 2025 all volumes are about 2% below '24 but finished strong in the quarter to be slightly above our plan for the year.

With that, I'll turn it over to David.

Thank you, Tom. This quarter, we're declaring a quarterly dividend of $0.2925 per share, which is $1.17 per share annualized, up 2% from 2024. For the fourth quarter, we generated net income attributable to KMI of $996 million and EPS of $0.45, 49% and 50% above the fourth quarter of 2024. This quarter's results included a gain on an asset sale which we treat as a certain item. Excluding certain items, our adjusted net income and adjusted EPS still grew very nicely, both 22% above the fourth quarter of 2024.

Our growth was driven by newly placed in service natural gas expansion projects, contributions from our Out River acquisition and continued strong demand for natural gas transport, storage and related services. For the full year 2025, we beat our budget by more than the contributions from our Outrigger acquisition. Outperformance came from our natural gas business, driven by greater value on transport capacity and ancillary services. Our Terminals segment also generated better-than-budgeted contributions. We budgeted to grow adjusted EBITDA by 4% and adjusted EPS by 10% from 2024. We actually grew adjusted EBITDA by 6% and adjusted EPS by 13%. Our 2025 EBITDA and net income were all-time record levels of Kinder Morgan.

Moving on to the balance sheet. As we continue to grow our cash flows and take a disciplined approach to capital allocation, our balance sheet continues to strengthen. Our net debt to adjusted EBITDA ratio improved to 3.8x, down from 3.9x last quarter and down from 4.1x at the end of the first quarter, which was immediately following the acquisition of Outrigger. Since the end of 2024, our net debt has decreased $9 million despite nearly $3 billion of total investments in growth products and the acquisition. So we'll go through a high-level reconciliation. We generated cash flow from operations of $5.92 billion. We've spent -- we've spent $2.6 billion in dividends. We invested $3.15 billion in total CapEx, including growth sustaining and our contributions to joint ventures. We spent approximately $650 million on the Outrigger acquisition. We've received $380 million on divestitures, primarily the EagleHawk sale. And then we had all other items a source of cash of about $100 million. That gets you close to the $9 million decrease in net debt for the year.

The rating agencies have recognized our strengthened financial profile. Last week, S&P upgraded us to BBB positive. Fitch upgraded us to BBB+ during the summer of 2025, and we're on positive outlook by Moody's. So as has already been mentioned, but I'll mention again, 2025 was an exceptionally strong year, a record same year, in fact. We beat our budget and delivered double-digit earnings growth. We grew our backlog from $8.1 billion to $10.0 billion despite placing $1.8 billion of projects into service meaning we added $3.7 billion of projects to the backlog during the year. We improved our balance sheet. We achieved credit rating upgrades and expect meaningful cash flow benefits from tax reform which will generate additional investment capacity. We have very positive momentum heading into 2026.

And with that, I'll turn it back to Kim.

Michelle, if you'll come back on, and we'll take questions.

[Operator Instructions] Our first caller is Julien Dumoulin-Smith with Jefferies.

Look, if I can kick it off more on the data center front. You guys talk about the 70% number with respect to where you have exposure and aligned with data center opportunities. Can you talk a little bit about what you're seeing actively on that front? Obviously, we saw the announcement here, perhaps that seeks out a little bit. But how do you think about that regionally in terms of further data points we should be seeing through the course of the year? And I've got a quick follow-up.

Okay. I'm not exactly sure about the 70%. But if you look at our $10 billion backlog, about 60% of our backlog is associated with power projects. That's not just data center, that's anything associated with power. And if you think about the opportunities on the power side, I think a great example is if you look in the state of Georgia, where Georgia Power, recently, I think the end of November filed a revised IRP. And they're projecting 53 gigawatts of power demand between now and the early 2030s.

And so from a gas perspective, if that was 100% gas, that would be like 10 Bcf a day, roughly, depending on the conversion metrics you use. And we expect that a significant portion of that will be gas, and that's just one utility in one state. And so what we're seeing across our network, whether that's in Georgia or South Carolina or Louisiana or Arkansas or Texas or New Mexico, Colorado, mean we are seeing similar stories just across our network. And the other thing is you look at power demand, we've got a higher power demand growth between 2025 and 2030. Wood Mac has and their most recent estimates increased theirs. And if you look at Wood Mac between 2030 and 2035, they think the power growth, at least in their projections, is greater between 2030 and 2035, than it is in their projections between '25 and '30. So this is something that is driving significant amount of projects. It's also a significant driver of the potential opportunities that we have, and we think will last for a decade.

Excellent. If I can just firm up a little bit more on the SSC 5 setup in timing. What are you looking to move forward on that? How are you thinking about timing? And then even more specifically, if you could speak to, are you thinking about this as being a compression first or looping kind of project initially? And what level of signed utility load would unlock a more formal filing?

Yes, Julien, this is Staples. So look, in terms of timing, we -- we see strong interest in the Southeast, and we continue to work with the customer base in terms of what the final scope looks like, that all depends on final subscription. I do see it more than just compression. I think there could be some more brownfield looping. But once again, it's early. We're working through the demand dynamics with our customer base. We do see opportunity there, and it is competitive. So we will continue to report as we go along. But ultimately, the sign deals, what drives the announcement.

Our next caller is Jackie Caleres with Goldman Sachs.

First, I just wanted to start on the next steps on the Western Gateway following the second open season launch last week. How do you think about allocating capital towards this project versus natural gas opportunity set? And how do those returns compare?

Yes. I mean on every project, we look at based on risk and return. And so I think we have a middle-of-the-road return that we expect and then we vary off that based on the stability, the duration and the creditworthiness of the cash flows. And so it's you've got stronger creditworthy parties and longer cash flows and take-or-pay, then you come off that return down from that return a little bit. And if you have those things are less and you go above that return. All these returns are significantly above our cost of capital. And so I think if we proceed on Western Gateway, we will have long-term shipper contracts there. And I expect those shipper contracts will be largely from creditworthy counterparties. And if not, we would have some credit support. So we don't, at this point, have limited capital. I think we can easily fund this project and do all the natural gas projects that we're talking about. Another point I'd point out on Western Gateway, which is we are contributing assets to that. And so our cash contribution will be less than we're going to -- we're setting up a 50-50 joint venture with P66. It would be less than half of the cost of the overall project because we're contributing value for contributing assets or part of our contribution.

Got it. That's helpful. And then just as a follow-up, leverage ended around 3.8x in the quarter. How do you think about maintaining leverage levels towards the midpoint of your long-term guide of 3.5x to 4.5x range versus leveraging up towards that high end if there are multiple CapEx opportunities?

Well, I'd say right now, what we've said is we're going to spend about $3 billion per year in CapEx. Now that won't be a perfect ground, $3 billion because you just have timing of spend, but roughly $3 billion a year. And we have the ability to flip on that 100% out of cash flow. The other thing I'd point out is that as our $10 billion backlog of projects come online at our debt-to-EBITDA actually declines over time. And so that creates more balance sheet capacity. So for every 0.1x of leverage, that $850 million of capacity. So I think we've got a ton of capacity even without leveraging up closer to the 4.5x. And I don't think we have intention of getting close to that level. So I think we've got plenty of capacities to accommodate the opportunities that we see out there.

Our next caller is Theresa Chen with Barclays.

Kim, I hear you loud and clear on the less than 50% of capital contribution on Western Gateway because you're contributing SSPP. When we think about the net EBITDA impact to Kinder, I'm assuming this project moves forward, how should we quantify the displacement of existing SSPP EBITDA? How much is that contributing currently?

Well, I think 2 things. One, Theresa, I think we're really early. And so we've got to get through the open season, we've got negotiations to do with our partner on the specifics. So I think -- and so I think we've got to finalize costs, et cetera. So I think it's too early to go through that at this point.

Understood. Maybe turning to a different portion of your liquids business. Could you provide an update on the progress of the HH conversion and in light of recent upstream developments in the Bakken and the increasingly challenged near-term outlook for the basin, how are you thinking about the expected NGL throughput and EBITDA contribution from this project?

Sure. I mean the project is going to come on probably late first quarter, early second quarter. and that's Phase 1. And then with respect to the future phases, that's something we continue to work on.

Yes. Theresa, Broadly, though, I mean, we still given the recent pullback, it's just a matter of time. I think our initial phase is well contracted. We see the volumes behind it. These are coming from our plants, and so we have visibility there. So I don't think as far as Phase 1 is concerned, and that is probably on the earlier side of the time frame that Kim gave you in terms of where we come in I think as we look to look to the next phase, we continue to have discussions, positive discussions with our customers. We'll monitor the overall macro situation, and we'll make the investment decision accordingly. That being said, we still have that in front of us.

And I think the other thing is GORs are growing in the Bakken.

Our next caller is Michael Blum with Wells Fargo.

Yes, maybe if I could just ask maybe a different way at the same question to some degree, with Continental Resources effectively I think they're going to stop drilling in the Bakken. I'm wondering if you can talk about, at least for now, can you talk about how meaningful a customer they are, either your current business? Or were they were contemplated to be for HH and if that has an impact on the further expansion?

So yes, if you look at the EBITDA that we get from Bakken or EBDA, it's about 3% of Kinder Morgan or all. Obviously, Continental makes up a piece of that. We don't think that there's going to be any material impact from the Continental news. We think that the impact is very manageable, that's one because it's 3% of our EBITDA. But it's also because volumes came into the year a little stronger than we were expecting. And it's also because they're going to continue to complete wells through August and because they are just one of a number of customers we have out there.

Okay. Great. That makes sense. And then I just wanted to ask, in light of the asset sale that you did here in late 2025. Are there more noncore assets that you're actively looking to sell? And strategically, are there segments or areas of the business that you're more inclined to reduce your exposure to?

Okay. Yes. Let me talk about the EagleHawk sale first. First of all, on that, that's not an asset that we were looking or planning to sell. Our partner approached us because they were selling at least a portion of their interest and based on the price that we could achieve it made sense to sell. It's an 8.5x multiple on a nonoperated minority interest in the GMT asset. And when we looked at the reinvestment opportunity, meaning if we we're buying at the price that we propose to sell and we look at the cash flows, those were going to be below our cost of capital. So and that included taking in into account any tax impact from the sale. So we thought it made sense. It was a good economic decision to sell that asset and recycle that capital. And so that's generally the way that we have been approaching sales of assets, which has been more opportunistic. As we say, our assets are for sale every day at the right price. And so we want to make good economic decisions about that. We like the portfolio of assets that we have today, 60 -- it's 2/3 natural gas and 26% is product pipelines and terminals, very similar pipeline and storage business. So the 7% is CO2, which is a little bit different, but we get great returns on that business, and we have an expertise that a lot of people don't have. So I think we're very comfortable with the suite of assets that we have, and this was just an opportunistic sale that made sense.

Our next caller is Jeremy Tonet with JPMorgan.

I was just curious for your thoughts, I guess, industry at large and what opportunities it could present to you down the road just if we think about Waha egress. One, we have some pretty cold weather coming up in during Yuri, that presented opportunities for Kinder last fall round. So just wondering if you could share any thoughts there.

Well, look, we as always here, when we look at the footprint, given our footprint, we're able to leverage basis dislocations that occurred. First and foremost, we want to serve our customers. And then to the extent that these opportunities present themselves, we've been taking a little more of a proprietary view on certain things in certain areas, strategically, small amounts. And so to the extent that, that presents itself, we'll be able to leverage that.

Yes. But I don't think this storm is not a yeary.

It's not a yeary.

I mean it's much shorter in duration and it's not going to be as significant. So...

Understood. It seems like there might be another one on a heals. So we'll see what happens this winter again.

Generally, what I would say is that the gas transportation market is very tight. And so whenever you see dislocations in supplier demand in and around our assets, that is going to present opportunities for us. And that's part of what you saw in the fourth quarter of this year.

Yes. And the key component of that is storage for us, and we have a significant storage portfolio that will allow us to leverage some of that to the extent that it presents itself.

Got it. And then just wanted to dial in on NGPL a little bit here, hearing more data center-driven opportunities in the Midwest, coal to gas switching as well, some of the other nat gas pipeline operators are seeing a lot of activity there. I'm just wondering if you could talk about what that could mean for Kinder for NGPL?

Yes. So look, we've -- we're quite a bit of -- there's significant discussions. You've been seeing some of the EBV postings we've been making out there. we've got interest along the pipeline in terms of not only just from power customers but also from organic markets that are trying to grow -- still early on some of these projects. We've got some binding commitments that we're looking to convert into full flood FID projects as these develop, we'll bring them. But I mean, when you think about the corridor itself, when we see a concentration up in the market area. We have some in the producing regions where folks are looking to site themselves. And so I think the opportunity set is there. It's just, once again, we're in this mode where folks are looking -- there's -- it's a competitive landscape, and so we want to make sure we secure the returns that we need to progress the projects to FID.

Our next caller is Jean Ann Salisbury with Bank of America.

You said in the prepared comments that MSX could be in service a couple of quarters early. I think is there any read across to a faster permitting process across the board? Or was that project specific?

No. I mean I think a couple of things on these projects. One is 871 is gone, and that happened, I don't know, 6 or 9 months ago. and basically required us to wait 5 months between when we got our FERC certificates on when we could start construction. So that's gone. And then the FERC has acted within -- is going to act within roughly 1 year on our filing. And so previously, we've been seeing that take a little bit longer than that on big projects. And so the fact that the FERC process only took 12 months and we don't have 71 is speeding up our in-service on MSX from called the fourth quarter of '28 to the second quarter of '28.

Great. That's a clear. And then one of your peers took an equity stake in a LNG terminal a few months ago. Is that something that KMI is actively looking at or would have interest in, especially, I guess, if you could back to back it with another counterparty to make it take or pay equivalent?

You make it. Well, I'll say a couple of things on that. Generally, what we've seen on the LNG front is the returns haven't been where we needed them to be to make those investments. And it's not something that we are accustomed to building. We do a small one, obviously, at Elba, but that was a relatively small facility. And so I think in general, what you should expect from us is that we are kind of sticking to our knitting, we're staying in our lane. We are serving those that LNG demand through our pipelines. And right now, we serve 40% of that demand, as Rich said, that demand is expected to grow significantly, and we expect to get our fair share of that future demand, and that's driving very nice project opportunities for us. So I'm not saying we would never step out. It's just there hasn't been the opportunity where we thought the risk return profile was appropriate. And we haven't wanted to build these on our own.

I think another thing we like on a risk-return basis is the fact that both on the LNG terminal side for feed gas and on the service to -- for electric generation purposes, we have, in general, take-or-pay contracts with utility grade investment-grade utilities. And that, we think, is a very good way to look at the risk that we are taking. And we think that minimizes any risk that we have as opposed to contracting directly with AI developers, for example.

Our next call is Keith Stanley with Wolfe Research.

You updated the messaging on CapEx to at least $3 billion a year of growth CapEx for the next few years, up from $2.5 billion wanted to clarify, is that solely based on the sanctioned project backlog today? So if you keep FID-ing new projects and the backlog grows, CapEx could be above $3 billion a year for the next few years? Or is that already reflecting your best estimate over the next few years?

I'd say it's largely based on the $10 billion approved project backlog, but there is some view there is a small portion that is based on getting some of the $10 billion in the -- in the opportunity set. So -- and look, I think that we updated it from $2.5 billion to $3 billion given the $10 billion given we continue to add to the backlog even after putting projects in service. So this year, when we were putting all those projects in service at the beginning of the year, we thought it might come down. It's continued to increase natural gas demand, we continue to see it grow between '25 and '30, but also beyond that. And so there may be the opportunity to extend that further, but we're not ready to do that or make it higher, but we're not ready to do that at this point in time.

Got it. Second question, just wanted to follow up on the earlier one on Mississippi Crossing. So if you're 6 months early on that project and on potentially on some of the other bigger ones given the regulatory environment. Would your contracts kick in and you'd have pretty close to a full financial contribution right away at that earlier date? Or is that not the case?

It's a project-by-project analysis. In this case, the answer is no, the customers don't have to take it at that point in time. Can, I mean, they can elect to take it, but they don't have to. And I would say that being early on the regulatory front does not directly translate into day for day on the in-service. It's going to depend on the projects because once you move back that regulatory, once you get sooner approval from a regulatory perspective, you have to think about when you're getting pipe and when you're getting compression. And so for example, we haven't seen that translate into much of an earlier date on South system at this point in time. So it's project by project. But if our customers don't want that capacity, it will be available for us to use during that time.

And given the macro environment, Keith, I mean, you just think about the demand profiles that are coming our way, it's just -- you look at that as an opportunity to sell in the secondary markets.

Our next call is Manav Gupta with UBS.

Firstly, congrats on all the upgrades from rating agencies reflects the strong quality of the management and execution. I wanted to ask you about the Florida gas transmission projects, both the projects. How did this come about? Can you give us more details? And then the last one year, what you have seen is you announced the project and then end up upsizing it. So if you could talk about the possibility of some upsizing here for these projects?

So Manav, this is Staples. So just in terms of the project itself, as you know, we're not the operator. energy transfer as the operator. So let them talk about how it came about on the call. We've been working with them closely. Thematically, it's the same things we've been talking about in the Southeast. We see that as a growth area, just broadly. And this is just another example of us getting incremental infrastructure to an area where there is significant growth. There's also a resiliency component there with the 2 projects. We think it makes sense in terms of whether or not the project gets upsized, but we're in the process of having an open season right now. The open season closes here, I think Fed fit if I'm not mistaken. And based on the interest there, is it possible to upsize Yes, if there's a demand for it.

Yes. I'd say both those projects are backed by long-term contracts with creditworthy counterparties. And so I mean, they are right down... .

Perfect. And my quick follow-up here is, at the start of the call, you mentioned that the 4Q turned out to be stronger than what you thought when you announced your 3Q results. So help us understand some of those tailwinds which help you drive the beat in 4Q? And are those still persistent out there? So should 1Q also turn out pretty strong, if you could talk about that.

Sure. So I mean, it was across the gas network. So it was our trust. It was our interstate pipes and our gathering assets. And so both as we said before, when you [Technical Difficulty].

This is the operator, please standby. And speakers, please go ahead. The next question comes from Jason Gabel.

It's Jason Gabelman from TD Cowen. Hopefully, the storm hasn't have you too hard down there. Maybe to start and to help everyone out, maybe we could just replay Manav's question because I was interested in the answer to it. I didn't quite hear. So just wondering what drove the earnings upside on the natural gas segment in 4Q. It sounded like some of it was driven by pull from LNG plants. So did some of these plants start up earlier than you had expected in the plan? Or were there other factors at play?

I mean, it was -- look, it was across the entire gas business. So it was a lot in our Texas and trust at market. It was in the Eagle Ford and the Haynesville on our gathering assets. And then it was also on the interstate markets more so in the Northeast than other areas. And so it's a function of having a very tight pipeline and storage network and that's going to create opportunities when you have supply or demand dislocations that could be leather, that could be LNG coming on or off to be a variety of factors, but that leads to volatility and upside for us. And there is the potential for that to happen again in 2026.

Great. And my follow-up maybe staying on the topic of LNG. It seems like the market is facing this upcoming global supply glut and maybe you get a bit of a slowdown in the pace of new liquefaction project sanctions here in the U.S. Gulf Coast. So just wondering how much of that project backlog if any, is tied to servicing incremental projects? And I guess it's not the project backlog. It is the shadow project backlog and projects -- LNG projects that are associated with that shadow backlog?

Yes. So a couple of things. I'd reiterate the point Rich made a minute ago, which is -- the -- we have long-term take-or-pay contracts with these LNG facilities. And so those typically are 20- to 25-year contracts, and they pay whether they use that capacity or not. In our current backlog, about 12% of the $10 billion actual crude project backlog -- 12% of the shadow backlog is associated with LNG. So it's not a huge percentage. I think a lot of the shadow backlog, again, is going to be more on the power front. But the other thing I'd say is that when you look at these LNG projects, it's not always about adding a new facility. A lot of times, it's about an existing facility has some capacity and they want to reach further back to get more competitive supply. So to have incremental project, you don't have to have a new facility come online. It could be a need from an existing facility to try to get more competitive supply.

And at this time, we are showing no further questions.

Okay. Thank you, everybody.

Thank you. Have a good day.

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.

All right. This is the session for Kinder Morgan. To my left, I've got Kim Dang, CEO; and Dax Sanders to her left, yes. So thank you all for being here. Appreciate it.

Yes, good to be here, Michael.

First of all, if you don't mind, could you just close the door in the back. Thank you. So put out the guidance last night. So I figured maybe just start with that, just talk through it, and then maybe I'll have a question or two on that.

Sure. So we put out a guidance, which shows a 4% growth in EBITDA from 2025 to 2026. It shows 8% growth in earnings. It shows us ending the year -- next year at 30.8x debt to EBITDA on the balance sheet well -- or at the lower end of our 3.5 to 4.5x range. And it shows $3.4 billion of expansion CapEx. The other thing we did was we raised our expansion CapEx guide. We used to talk about approximately $2.5 billion per year, and now we're talking about over $3 billion per year for the next few years, and that's just a function of the project opportunities that we've continued to add to the backlog as well as the timing of that spend. And so we think a fantastic opportunity in the midstream space right now, getting nice growth in EBITDA and earnings and lots of opportunities for economic investment.

Great. And I should have set up front, if anyone has questions, just raise your hand, we'll run a mic to you, and just -- at any time, just raise your hand and ask a question, just feel free to interrupt me. Yes. So I guess at a high level, like you said, it's a pretty exciting time in the industry and certainly for the company. It seems like you're in the right place at the right time. So you've had a really significant increase in the backlog for the last few years, almost all of that gas pipeline investments. I guess my first question is, and maybe you kind of answered it already is, what inning do you think we're in here? Like like how long do you see the runway for growth and projects and investment opportunities? And do you see any risk to that long term?

Sure. So I'll start with the existing backlog of projects. So these are projects that we have contracted and our Board approved. So that's $9.3 billion is our current backlog of approved expansion projects. That's up from, as you mentioned, substantially from two years ago. Two years ago, that number was $3 billion. So that $9.3 billion is going to generate nice growth in EBITDA for us. As you said, 90% of that is associated with natural gas, and it's coming at less than a 6x EBITDA multiple. All those projects, again, Board approved and contracted with customers. So that will lead to nice growth. But beyond that, we have a huge set of opportunities that we're working on. And when we go back and we look at that set of opportunities that we're working on that's sort of beyond the backlog, we went back, and we looked at it when the backlog was $3 billion. And then obviously, we know what it is now, and that opportunity set hasn't changed. It hasn't gotten any smaller from when the backlog was $3 billion. So we feel like we've got really nice continued opportunity in the natural gas space, that's being driven by the 20% plus growth in natural gas -- in the natural gas demand that we expect between the end of 2024 and 2030. And it's going to be between 22 and 28 Bcf a day, and 22 is WoodMac's number, which is a third party, 28 is Kinder Morgan's internal number. And that's primarily being driven by export LNG and power as well as a little bit of Rails Com and exports to Mexico. So just a fantastic time to be in this space, seeing lots of opportunities to expand our existing asset base and serve the market.

So maybe just to follow up on that. On the last call, you made a few interesting comments to frame that. You talked about evaluating more than 10 Bcf of natural gas projects tied to the power gen sector. And then you also talked about $10 billion of potential projects, I think, mostly tied to natural gas. So can you bucket those, or is there a way to think about what those -- a little more color on what those are?

So yes, the opportunities beyond the $9.3 billion backlog is the over $10 billion of potential projects. Now say this, some of those projects won't happen, and we won't win every one, but it's a huge set of opportunities to be working on. I'd say that the $10 billion looks kind of like the $9.3 billion backlog. It's more of the same in terms of -- it is focused on natural gas. So it is almost all natural gas. It is driven by the same demand drivers and supply drivers that we see in the $9.3 billion. So it is power demand, it's export LNG. It is driven -- we have a gathering position in the Haynesville, it's a potential expansion of our Haynesville position. So it's all the same drivers. And I would say in terms of size and scope of projects within that, it looks pretty similar. You have a couple, a few that are big projects, and then you have a lot of singles and doubles in there. And so -- and I'd say, is largely across the Southern United States as you go from Arizona to Florida. But we do have some pipes go in the Northeast. So we have some potential developments there and then some on NGPL that goes into Chicago, a little bit in Colorado, but it is substantially across the Southern United States. So I'm confident we'll get -- we will be able to take some of these projects and ultimately be able to add them to the backlog over time. Now timing is a little bit harder to predict, but the need is there, and we've got a great position to work from with our existing asset base to deliver value to our customers.

So maybe if I push that a little bit. I guess a multipart question here, but some of your potential customers have put some stuff out there. So Southern -- SNG, they sort of intimated that they could spend another $1 billion on another SNG expansion. You've already done one as we know. So curious if you can talk about that at all. And then -- and there's also been Dominion has listed you as a gas supplier for our proposed 2.2 gigawatt plant that I think would be in service in like 2032. So either speak to those projects specifically if you can. But if not, maybe if you could talk about like the process, how this happens, what's the conversation with the customers? How does the project get from development to FID?

Sure. Sure. So the first expansion of our Southern Natural Gas asset, which is a gas pipeline that moves gas into primarily Alabama and Georgia. It's a $3 billion [indiscernible] project. Our partner is Southern. We have some expansion on existing systems as well. And so our share of that project is, I think, approximately $1.8 billion. So a big project for us. I think things are going pretty well, expect a FERC certificate probably next summer, and then we'll start construction. So fully contracted pipe and comes in service mainly in 2029. So -- but I think Southern's continue to see incremental demand in the Southeast. Georgia Power, which is one of Southern's subsidiaries, they filed an amended IRP at the end of November, and they were showing 53,500 megawatts of power demand between now and the 2030s. And so if you look at that, and this is just a rough -- when you convert that to gas demand, just rough math, because there's a whole bunch of assumptions that go in here. That's going to be probably over 10 Bcf a day of gas demand. Now not all of that will be gas, right? And some of that -- a small portion of that is being served by the SS4 expansion. But even if you adjust for those two factors, that's still a huge amount of incremental demand in that market. And that's one utility in one state. You're seeing similar things. You mentioned South Carolina and Dominion and Santee Cooper that power plant that you mentioned there is being served by our Bridge project, which is about a $425 million project that is in our $9.3 billion project backlog, and it comes online in 2030. That's about 325 dekatherms a day, but that pipeline is easily expandable. And so like what we see with Georgia Power and Alabama in Georgia, we expect that those South Carolina utilities will probably add additional demand -- power demand over time and our pipeline -- our bridge pipeline is easily expandable to meet that demand. So what we're seeing in Georgia and South Carolina, that's just a microcosm of what we're seeing across the entire Southern United States and in pockets elsewhere that we -- where we have existing capacity.

So maybe just a follow up on the Georgia example. So 10 Bcf, let's cut that in half, let's just say, make it easy 5 Bcf. I guess a couple of questions. One, how many competing pipelines are you, who are you competing with there for that business, and what are the limitations of what LNG can do in terms of ability to expand further, like is that another factor?

So SNG has got a great position in Georgia and Alabama. And it's got two legs to that pipeline that goes through those states. So it's got a great position to compete from. In the northern part of the state, Transco does go through the northern part of the state. And so there is some competing pipeline infrastructure. And so I'm not saying that we will get 100% of, in your example, the 5 Bcf. I mean it's going to depend on exactly where the power plants are sited, et cetera. And so there's probably going to be that some of the competition gets. But in my mind, in those kind of numbers, there's plenty of gravy to go around, plenty of food to go around. So I think it will -- there's a nice opportunity for a South System 5 Expansion.

Great. I appreciate that. What about -- maybe we turn to Arizona for a minute. So obviously, you had a product that you're developing. It didn't happen fine, but you've said that you still see opportunities to invest in Arizona. So I wonder if you can just elaborate on what that means?

Yes. So two, there's opportunities on the natural gas side and then there's opportunities on the product side actually in Arizona. And so -- let me talk about natural gas real quick, and then I'm going to let Dax talk about the products opportunities. For those of you that don't know Dax, Dax has been with Kinder Morgan for as long as I have. He most recently ran our Products Pipeline business unit and is now the incoming President for Kinder Morgan. So Tom Martin will retire in January, and Dax will take that position. So on the natural gas side, yes, there are more opportunities, just like I said, in the Southeast where Transco will have probably opportunities on some of the power plants depending on exactly where those power plants are, we've got an existing system and that goes out to -- that goes through New Mexico and out to Arizona. And so there's going to be opportunities on power plants in Mexico and other places in Arizona that may not be Phoenix, which is where the new pipeline that competitors scheduled to build is going. There's other places, and there's coal conversions and other places that will need power in Phoenix and Arizona. So I think we're well positioned to compete for some of those opportunities. And so we do see additional opportunities in those states on the natural gas side. And then on the product side, I'll let Dax speaks to that opportunity.

Yes. We got an open season going out there right now in the desert Southwest that actually has brought a lot of interest to a market that's been incredibly boring for probably the last 50 years. But the project, we partnered with P 66, and we're looking at expanding our East line system from El Paso into Phoenix. And also as part of the JV, we would build a line from Borger into El Paso that would bring 2 barrels from Borger as well as Wood River. So the project also would reverse the gold line, which connects Wood River to Borger, would reverse that line, bringing barrels again from PADD 2, Wood River into Borger barrels down to El Paso all the way across the desert into Phoenix. And then our existing system brings barrels from El Paso into Phoenix as well as West Coast PADD 5 barrels from California into Phoenix. That market's about 250,000 barrels a day. Our project would also reverse our West line, so it would clear barrels that are coming into Phoenix -- out of Phoenix and move them into the Southern California basin. So we've got an open season out right now with P 66, that closes in the next 1.5 weeks, couple of weeks. We haven't put a lot of details out because there is a competing project out there, and it's a very, very competitive market. So -- but it's something we're excited about. And hopefully, that will come together. We're pretty enthusiastic about it.

And the dynamic driving that is just the shutdown of refineries in the California market. And so the California refineries right now serve the Phoenix market, Tucson market to some extent and also the Nevada market, specifically Las Vegas and Reno. And so that's what's basically producing that opportunity.

Just one follow-up on that, on the refined products pipeline project. What's the timing? Just can you just lay out the timing of that?

Yes. So the open season closes in the next kind of call it, 1.5 weeks to 2 weeks. I think we'll see what the open season produces, and then we'll get together with our partner. Our expectation is if we have a project that we would probably look to FID sometime in the first quarter.

So I think I know the answer to this question, but I'd like to ask it every now and then. Just on the behind-the-meter power market, which Williams has obviously very -- been very front-footed in. None of the other pipeline companies seem to have really done that. So I'm pretty sure that you're not interested in that. I think I know that. But you had talked about potentially creating some kind of partner structure with other players and then having like a package effectively to deliver to a potential developer or hyperscaler. Can you just talk about where that stands today, if I describe that correctly?

Yes, sure. So you're right on behind-the-meter in terms of building power plants, that's not our cup of tea. That's not our business. And so we've done some new businesses in the past. And it's hard first time that you're doing something and doesn't always go as smoothly as you would like. And so that's why we've passed on that opportunity. But we're seeing huge power demand and opportunities to serve power demand. That includes data centers. Sometimes -- a lot of times, what we've seen early on is it's been the regulated utilities, that are building the power plant. So -- and then the data center demand is contract -- or the data centers, et cetera, hyperscalers are contracting with the regulated utilities. And so we're serving the regulated utilities, which is a great model. We did have a sort of consortium that we put together, bring a power plant developer and a data center developer and us. We haven't found that, that's really necessary to get the gas supply to the power plant or to the data center. We haven't found that, that's been necessary to compete. And so we just -- that's still something that we could do. But in general, we found that we are getting opportunities without having to complicate the task.

Got it. Maybe just last question I think I have on gas is gas storage. So maybe you can -- maybe just start by describing your current footprint? And then; a, do you see just natural uplift in EBITDA as contracts roll, like where is your contracts versus rates today? And then do you see expansion opportunities around your gas storage assets as it relates to everything else we've been talking about.

Sure. So our storage footprint is 700 Bcf, so pretty substantial storage portfolio. And about 75% of that is regulated, meaning the rates that we charge are set by the FERC in conjunction with our shippers generally. And about 25% of it is unregulated. So on the unregulated market, it's just basically market-based rates. You're competing with other people have storage to set those rates. Those rates have increased substantially over the last couple of years. And so typically, it depends, but those storage contracts are 3-ish years. And so you're marking that portfolio to market every three years. And they don't roll -- it doesn't roll ratably. And so -- but you can think about 1/3 of that rolling every year, give or take. So -- but yes, I mean, storage has been great. We've done a couple of expansions. We completed one last year, which was a 6 Bcf expansion on storage facility in Texas. We are doing another store, 10 Bcf expansion of a facility. We actually just got the FERC permit on within the last week on NGPL, which is in East Texas. And then we recently just had an open season for a storage facility that we own in the Southeast and got very good demand on that open season. And right now, in the process of working to put together a project. Brownfield, as you can see from the projects we've done, brownfield development, which just expanding existing storage facilities' works. You can get the rates you need and the contract duration that you need. I'd say in terms of greenfield, that's a little more difficult because generally, to do a greenfield project, to get the rates to where you need them to be, you've got to have five or six or seven customers sometimes because of the size, the scale and scope of that facility. And so getting that number of shippers to sign 10-plus year, 10- or 10-plus year contracts is not there yet. The rates are there, but -- and so -- but I think we're getting close -- a lot closer on the greenfield side.

Okay. I lied, I had another gas question. Sorry. So there's been a lot of -- in the market, like the stock market, there's been a lot of angst about the AI bubble, that's kind of vacillating here and there. I'm wondering if in your discussions with potential customers for incremental gas supply into these power projects, are you seeing any of that hesitation, or is any of that kind of angst around this AI bubble manifesting in your conversations?

Well, I think by the time they're getting to the gas supply piece of it, a lot of time -- I mean, yes, we're having conversations early on, but I think that -- we try to push away the projects that we don't think are going to happen so we can focus on the projects that we think are more likely. And then as we focus on the projects that we think are more likely then we're thinking about, okay, what's the credit here. And that's why you heard me say earlier, doing it with regulated utilities is a nice place to be to have that credit on the other end of the gas supply contract. To the extent that you don't have a regulated utility on the other end, there could be -- we're going to look to determine whether we think collateral is necessary and a lot of times, we do. And so we'll get some form of collateral to help us mitigate cost to make sure we're not going to be out of pot depending on what that credit is. I mean we might require as much as the entire project cost to be backed by an LC or something. That would be someone who doesn't have very good credit, someone that's got better credit than you'd have, but not utility-like credit, then you'd have -- you'd be somewhere in between the two. So that's generally how we think about it, make sure that we have the right credit. So that if you do have a bubble in this market that we've tried to pick the winners, and that where we have a little bit more -- took a little bit more risk. We get higher returns and have a collateral.

Okay. Maybe just a related question on the regulatory and the permitting environment. So I guess the question would be this administration came in sort of touting that they're going to have a better more industry-friendly environment. So I'm curious if you're actually seeing that, or how the -- how do you think they've done so far in terms of making it easier for you to do business to -- yes, permitting as well, which obviously...

So I think they've done a good job so far. I think there's more to do. That's what I'd say. So let me tell you about where I think they've done a good job. So the core of engineers has been very quick on response and permitting, et cetera. And that is a change from what we've seen in the past, their engagement and their responsiveness, and they're issuing a permit is just much faster. On the FERC side, which any time we build an interstate natural gas pipeline of any significant size, we have to have a FERC permit. And we've seen some improvement on the FERC side. The most substantial improvement was they basically retracted what was called 871, which basically was a 5-month period from when they permitted your project to when they would let you start building to give landowners time to appeal and them to resolve those, so they -- which is something that they had only put into effect 2 or 3 years before, and it is just elongated time lines. So they have rescinded that. So that gives us immediate five months benefit. On our big projects, they have said that they're going to issue our permit in 12 months. They've committed to that. That's the schedule that they put out there. And so on some large projects, prior to that, it was taking longer than 12 months. And so them committing to 12 months, I think, is a win. Where we would like to see more is we would like to see that 12 month, and this is on big projects, right? If you're doing a smaller project, it doesn't take 12 months to get a project -- to get a permit. But we'd like to see them compress that 12-month time line more. That being said, we want to make sure that the permits they're issuing are durable. So we don't want them to issue just -- take this to the extreme in one day because then they wouldn't have done the work necessary for that permit to be durable if it was challenged in court. So -- but we think that there is a reasonable basis to have durable permits and be less than 12 months to get there. So we'd like to see some incremental improvements there. And we're actually -- we're working with the FERC to propose some of those changes. So they -- the other thing they did was they took up some of the limits where you don't have to file a permit, or where you can file a very modified permit in terms of the cost of the project. So they -- in one case, it's 1.5x now. So they increase those limits. And so that was -- that's a win as well. So I think we've seen some good progress so far, but would like to see more. And I think at some point that regulatory ends up not being the gating item, you're going to get into the supply chain being the gating item. And in some cases, depending on the project, we're getting close to that. But in other cases, I think there's still room on the regulatory side.

Could you expand on last comment about the supply chain? Where are you seeing the potential...

So on the supply chain, I think the biggest issue is going to be on compression, really. And on our big projects that are in our backlog, we've secured our compression and no concerns. And I think at this point, I feel like we're going to hit our dates there in terms of projected in-service dates. I think it's on new projects, where it can take a longer time. On the interstate projects, again, with the current regulatory environment, generally not a concern, but if you're doing an unregulated project, that can elongate those times. We're seeing some capacity added in the market -- well, not added yet, but going to be added in the future, but it will take time to get that capacity on, get it running smoothly. So I don't think we're going to get help there for maybe another year or so.

Okay. Just one more follow-up on that. I mean there's -- obviously, you and many of your competitors are all pursuing a lot of expansion projects. Do you foresee at some point that labor becomes a constraint, or do you feel like that?

We haven't seen it to date. That doesn't mean we won't see it. I mean we're going to -- we're constantly on the lookout for that. But we've been engaging with a lot of contractors on the big three projects, MSX and South System 4 and Trident, which are $5.3 billion of the $9.3 billion backlog. And to date, we haven't -- those things seem to be about on budget. Now we're not fully done there in terms of getting those contracts, but the preliminary -- we'll try that or essentially done. But on South System 4, for example, on the preliminary numbers we've seen there, it's been within budget.

Maybe if I just turn to capital return for a second. So obviously, you just announced your dividend and your guidance for '26. So that is what it is. But I'm wondering just holistically, your rate of EBITDA and cash flow growth is accelerating. You're going to -- at least on our math, you're going to be growing EBITDA in the next bunch of years faster than the roughly 2% increase in the dividend. So I guess the question is, do you see -- would you consider, or would you think about accelerating cash return as your cash growth improves and what form would that come in? Is that -- could it be a faster dividend growth rate? Is there buybacks? Is there -- or maybe you want to keep that capital, so just curious how you're thinking about?

Sure. Sure. So we've been, again, growing our dividend at about $0.02 the last few years. And that's really just a function of the opportunity set that we have out there on the capital side. And as we said to the beginning of this session, we just raised our expected CapEx guidance for the next couple of years from $2.5 billion -- around $2.5 billion per year to over $3 billion. And so the reason that we've been conservative, I would say, in our dividend growth rate is to preserve that capital and preserve flexibility for all the opportunities that we're seeing out there. And so I think on the other side of some of the CapEx, the over $3 billion. I think it's a -- and then you'll start seeing projects come in service, then it probably makes sense to look at a faster growth than the dividend rate. But I think right now and for the next few years, I think the strategy that we have is the right one.

Okay. And I'll squeeze one more in here...

And then the other thing I'd say in terms of buybacks, that's just going to be opportunistic. And our balance sheet, as I talked about a few minutes ago, 3.8x debt to EBITDA, the high end of our range is 4.5x. Every 0.1x is $850 million. I don't foresee us taking our balance sheet up to 4.5x that we like having that flexibility. But if there were -- if we saw opportunities for share repurchase, we have some capacity there to do that.

So maybe just to round it out in the last -- well, we are over a bit, but it's fine. Just M&A, obviously, there's a lot in your plate organically. So it just feels like maybe you don't need to do anything, but just curious what the landscape looks like? Is it even on the table, or do you just feel like, you've so much internally that it has to be pretty special.

Okay. So I'll say a couple of things, and then I'll let Dax add to it because Dax ran corporate development for a number of years at Kinder Morgan. So look, I think that's part of the reason to keep your -- to keep the capacity on your balance sheet so that when we see opportunities, we can take advantage of them. M&A is opportunistic. You can't schedule it the way you look at an expansion project and, you've got a year down 1 or 2 years down the road, you're going to bring these things in service. I mean those things arise and got to have the flexibility to be able to take advantage of that. We think our balance sheet gives us that. And if you look what we've done in the last couple of years, we did a tuck-in acquisition the beginning of this year in the Highland, we did a tuck-in acquisition in Texas at the beginning of '24. And then I think in '22, I think it was, we did stagecoach versus storage acquisition in the Northeast. So we've been finding opportunities and that $850 million per point 1 turn, that's just straight adding debt. If you're doing an acquisition, and you're adding EBITDA as well, then you've got more capacity or less use of the balance sheet, however you want to think about it. So I think we're in a position where when we see opportunities, we can take advantage of them.

Yes. No, I totally agree. I mean we like M&A. Our company was built on M&A over a 30-year period of time, but you got to be incredibly opportunistic about it. It's very difficult to predict when the opportunities come about. You've got to align economics, social issues, people's willingness to part with stuff at a reasonable price. You don't -- it's generally not a good idea to lock in on something you want and chase it at all costs. That's how you end up with bad deals. So we tend to -- any process that happens in our space, we're generally included in. We generally see what's going on. And so we generally sit back and wait to see what happens and participate when it makes sense. And with respect to selling stuff, people ask about that pretty frequently. We're we're a willing seller at everything we own every day at the right price, and that's a true statement. That's not just a line. But you generally have to have somebody who has a different thesis on an asset, then you do and a lot of people, a lot of people -- there are a lot of introductory conversations about a potential transaction that as time passes, and it gets closer to time to actually kind of check those don't necessarily come to fruition. So we are working on both ends of that all the time. And we're only going to do things when they make sense.

Great. Well, thank you very much for the time this morning. Appreciate it.

Thank you.

Good afternoon, and thank you for standing by. Welcome to the Third Quarter 2025 Earnings Results 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 call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. As usual, before we begin, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 and as well as certain non-GAAP financial measures. Before making any investment decision, we strongly encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. I think we all recognize the positives and negatives of publicly traded companies One of the biggest pitfalls is the undue concentration on quarter-to-quarter or even day-to-day issues, many of which are relatively inconsequential in terms of the long-term success of the enterprise. With that in mind, I thought I'd take this opportunity to stress 2 important substantive factors that will impact the future of Kinder market. The natural gas story and the long-term strategy of our company. Obviously, the 2 are intimately related.

On the natural gas demand front, there are 2 huge drivers. The first is the continued rapid growth in LNG feed gas demand driven by the enormous expansion of export facilities, primarily along the Gulf Coast. While industry experts differ somewhat, there's a pretty broad consensus that demand will at least double between 2024 and 2030. In fact, S&P's commodity insights recently estimated that increased at 130%, which implies a demand of 31 to 32 Bcf a day in 2030.

As an example of this growing demand, 6 LNG projects have reached FID so far in 2025. Feed gas demand for those facilities alone when completed will be 9 Bcf per day. Now there's more variance in assessing the impact of the second driver, which is the increasing demand for electricity, primarily to serve AI data centers. There will clearly be huge additional demand for electricity, but how much of that will be captured by natural gas.

Let's look at the alternatives. Certainly, renewables will play a major role, but can't handle the entire load given AI needs for uninterrupted power 24/7, not just when the sun is shining or the wind is blowing. But can't this be fixed by [indiscernible] wind or solar farms with massive batteries the store power and release it in the steady stream when needed. Well, that sounds intriguing, but there are serious drawbacks to this option because batteries are expensive and limited in the time they can cover and renewables of the size to serve AI centers require enormous space. A recent article in the New York Times of all places, estimated that to continuously produce just 1 gigawatt a solar farm would need 12.5 million solar panels and over 5,000 football fields and wind turbines would require even more space. Another source of power is nuclear, which generates steady power from relatively small footprint, but this is an industry that unfortunately has been basically dormant for over 40 years and new nuclear facilities are very expensive and would likely take 7 to 10 years to come online. This means that AI sponsor would not have the facilities when needed, and we'll be handling billions of dollars that the demand will still be there a decade or so from now.

That leaves natural gas, which is abundant and reasonably priced and the infrastructure to produce power from natural gas is relatively quick to build. Reasonably like I've just outlined is why we believe that AI data center needs will supplement in a very meaningful way the tremendous increases in LNG feed gas demand and in combination of the 2 drivers will ensure a huge and growing market for natural gas in the years and decades to come. Now let me conclude by again emphasizing the long-term strategy at Kinder Morgan. We are a prolific generator of cash and are fortunate to have the majority of our assets employed in a true growth segment of the energy business namely the transportation of natural gas. These 2 characteristics dovetail nicely. The tremendous growth in natural gas demand drives the opportunity for expanding and extending our pipeline and terminal networks and adding new facilities, as evidenced by the $9 billion plus of projects already approved by our Board, and we generate the cash internally to fund those projects while maintaining a healthy and modestly growing dividend. Now to be clear, we have to complete these projects on time and on budget, but our track record in that regard is good, and we're benefiting from a federal regulatory process that is more supportive of projects like ours.

While our base business is relatively flat, these capital projects will drive substantial growth in EBITDA and EPS for years to come. This is a simple but in my mind, very compelling strategy. And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. We're pleased to report another strong quarter with EBITDA up 6% and adjusted EPS growing 16% year-on-year. These results reflect the strength of our underlying business and the continued execution on our growth projects. We currently expect to exceed our full year budget due to the contributions from the Outrigger acquisition. This outperformance would be greater if not for lower-than-budgeted [indiscernible] prices and RNG volumes. Currently, the RNG volumes are much closer to budget, but RINs prices remain weak. The natural gas segment, which accounts for 2/3 of our business is outperforming its budget, even excluding Outrigger. Our expansion backlog remained flat at $9.3 billion, with the approximately $500 million of new projects offset by projects placed in service. The backlog multiple continues to be below 6x, consistent with our disciplined approach to capital deployment. The mix of new projects added to the backlog this quarter has split roughly 50% natural gas, primarily supporting power generation and 50% to refined products tankage.

Looking ahead, our opportunity set remains exceptionally compelling. We're actively pursuing over $10 billion in potential projects, primarily in natural gas underscoring the continued demand for our services and the strength of our platform. As I mentioned last quarter, the scale of opportunities we're evaluating today is comparable to when our backlog stood at just $3 billion highlighting the consistency and the resiliency of our growth pipeline. Our gas infrastructure more than 66,000 miles of pipeline connecting all major basins and demand centers. positions us as a critical player in energy infrastructure.

Today, we transport over 40% of the natural gas in the United States, including more than 40% of the volume headed to LNG export facilities the gas fueling U.S. natural gas power plants and 50% of the gas exported to Mexico. Looking forward, our internal projections estimate 28 Bcf a day increase in natural gas demand by 2030 driven primarily by growth in LNG exports as well as power and exports to Mexico. Wood Mackenzie forecast a similar trend, projecting 22 Bcf a day of growth in overall natural gas demand. With our strategically located assets, we are well positioned to capture a meaningful share of this expansion. Our current $9.3 billion backlog is a strong foundation for long-term high-quality growth. A very significant portion of this backlog is supported by take-or-pay contracts, providing both stability and visibility into future cash flows. And as we continue to advance our development pipeline, we expect to convert a portion of the $10 billion opportunity set into additional backlog, further reinforcing our growth trajectory. We remain confident in our strategy, our execution and our ability to deliver long-term value for our shareholders.

And with that, I'll turn it over to Tom Martin to walk through the business performance in more detail.

Thanks, Kim. Starting with the natural gas business unit. Transport volumes were up 6% in the quarter versus the third quarter of 2024, primarily due to LNG deliveries on Tennessee Gas Pipeline new contracts from expansion projects placed into service on the Texas Intrastate system and increased Permian deliveries to Waha and Mexico on our El Paso natural gas system. Natural gas gathering volumes were up 9% in the quarter from the third quarter of 2024, with growth across all our G&P assets, the largest impacts from our Haynesville and Eagle Ford systems.

Sequentially, total gas gathering volumes were up 11%. We experienced a significant ramp from our producer customers during the quarter to meet the growing LNG demand. The gathering volume growth trend continues in the early days of the fourth quarter, most notably on our Haynesville system as it is approaching new daily volume records in October. For the full year, we now expect the gathering volumes to average 5% above 2024. And looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation and storage capabilities in support of the growing natural gas market.

For example, we are exploring more than 10 Bcf a day of natural gas opportunities to serve the power generation sector. In our Products Pipeline segment, Refined product volumes were down 1% in the quarter compared to the third quarter of 2024. For the full year 2025 refined products volumes are forecasted to be about 1% higher than 2024 and in line with our budget. Crude and condensate volumes were down 3% in the quarter compared to the third quarter of 2024. More than all of that decline is driven by taking double age out of service earlier this quarter for the NGL conversion project. On Monday, Kinder Morgan and Phillips 66 launched a binding open season for transportation service on the Western Gateway Pipeline, a newly proposed refined products pipeline system that will facilitate the movement of products from origin points in Texas to key downstream markets in Arizona and California with connectivity to Las Vegas, Nevada. This open season is scheduled to run through December '19.

Following the successful open season, the Western Gateway pipeline and KMI's SFPP East line will be jointly owned by KMI and Phillips 66. We believe this project provides an attractive refined products alternative for markets in Arizona and California, given the decline in California refining market. In our Terminals business segment, our liquids lease capacity remains high at 95%. Market conditions continue to remain supportive of strong rates and high utilization at our key hubs in the Houston Ship Channel and New York Harbor. Our Jones Act tanker fleet is fully leased today through the remainder of 2025, assuming likely options are exercised, the fleet is 100% leased through 2026 and 97% leased through 2027. We have optimistically chartered a significant percentage of the fleet at higher market rates and extended the average length of firm contract commitments to nearly 4 years. The CO2 segment experienced 4% lower oil production volumes, 4% higher NGL volumes and 14% lower CO2 volumes in the quarter versus the third quarter of 2024. For the full year 2025 or volumes are forecasted to be 4% below 2024 and 1% below our budget. With that, I'll turn it over to David Michels.

Thank you, Tom. This quarter, we're declaring a quarterly dividend of $0.295 per share or $1.17 per share annualized, which represents a 2% increase over our 2024 dividend. For the third quarter, we generated net income attributable to KMI of $628 million and EPS of $0.28 per share both in line with the third quarter of 2024. Last year's results included favorable mark-to-market impacts on hedges and a onetime noncash tax benefit, both of which we treated certain items. Excluding those items, adjusted net income and adjusted EPS grew 16% year-over-year, delivering strong double-digit growth. This growth was driven by greater contributions from our natural gas expansion projects placed in service, the Outrigger acquisition and strong demand across our natural gas footprint for natural gas capacity and related services. Moving on to the balance sheet. As we've continued to take a disciplined approach to capital allocation, our balance sheet has strengthened. Our net debt to adjusted EBITDA ratio has improved to 3.9x at the end of the third quarter down from 4.1x at the end of the first quarter, which was immediately following the Outrigger acquisition. Year-to-date, our net debt has increased by $544 million, and here's a high-level reconciliation. We generated cash flow from operations of $4.225 billion. We've paid out dividends of $1.95 billion. We paid or spent $2.245 billion of total capital. the outride acquisition was $650 million, and all other items were a source of cash of approximately $75 million, which gets you close to that $544 million increase for the year. The rating agencies have recognized our strength in financial profile. And in August, Fitch upgraded our senior unsecured rating to BBB+. We were already on positive outlook by both S&P and Moody's and we look for a favorable resolution of those in the near term. As Kim mentioned, we expect to exceed our 2025 budget.

And as a reminder, we budgeted to grow adjusted EBITDA by 4% and adjusted EPS by 10% from 2024. So with the outperformance we expect to deliver even larger year-over-year growth. As we mentioned last quarter, the budget reconciliation bill delivers meaningful tax benefits for us, primarily from full expensing of investments. In addition, recent adjustments to the corporate alternative minimum tax are expected to provide additional substantial tax savings beginning in 2026. So we are poised for a very strong full year 2025. We're on track to beat our budgeted our budget and delivered double-digit earnings growth. We sanctioned additional high project high-return projects that will support future growth. We've improved our balance sheet resulting in enhanced credit ratings, and we expect meaningful cash flow benefits from tax reform, which will generate additional investment capacity. And with that, I'll turn it back to Kim for Q&A.

Michel, we'll come back on, and we'll take questions.

[Operator Instructions] Our first caller is [indiscernible] with Barclays.

Afternoon. I wanted to go back to your growth outlook and specifically the over $10 billion opportunity set in unsanctioned projects under development up, I think, from the previous $7 billion to $11 billion range. What has driven the seemingly improved outlook over the past few months -- how quickly do you think you can commercialize these growth opportunities? And where are you seeing the most interest for expansion projects amongst your customers.

So on the $10 billion, that's all the opportunities that the opportunities that we're pursuing right now. It's mostly natural gas. It supports the themes that we've mentioned here today, so export LNG, power, but there's also projects that exports to Mexico and industrial growth. And as I said, the opportunity set is very similar to when our backlog was at $3 billion. So we haven't seen any diminishment in the projects that we're looking at. These projects are mostly across the Southern U.S. So they go all the way from Arizona to potentially Florida. And most of them are in smaller in size, I'd say, less than $250 million, but there are a few that are $1 billion plus. So it's all of the board. It's power in Arizona, power in Texas power in New Mexico Power in Florida. -- if we need more egress from the -- from all the producing basins, the Haynesville, potentially the Marcellus Utica we need more gas moving to LNG. As Rich said, we've 9 Bcf of gas demand from the projects that have FID recently. So I mean it's across the board. And then today, we have potential project we're working on with respect to Western Gateway. So there's a lot of different opportunities out there.

And on that last point, Kim, following this week's announcement of your open season for Western Gateway, can you talk about your projects positioning relative to [indiscernible] competing Sunbelt project? And assuming that Western Gateway solicits sufficient commercial interest during the open season, can you talk about potential gating factors, regulatory or other rides that Kinder and [indiscernible] is many to address before the project can be sanctioned?

So relative to the competition, I think their pipeline just goes into the Phoenix market. Currently, the Phoenix market is by us from the left as well as from the East. The project -- the proposed project with P66 and us would reverse our West line build a new pipeline from Borger to Phoenix. And so we would be sending barrels from the East into the Phoenix market. and reverse our West line so that you could potentially barrels could move on into the California market and potentially into the Las Vegas market. So I think it's -- from our perspective, it's a very good project for Arizona. Arizona is a growing market. So it gives additional capacity to serve the Arizona market. Arizona is no longer dependent on California, where California has got some closing refineries. California gets potentially additional barrels coming to the California market. To the extent there are additional closures in California. And I think it's a great project because you're accessing multiple markets, you're not just going to 1 market. So in terms of the open season ends on December 19. And then from there, we'll need various regulatory approvals and we would target a 2029 in service date.

The next caller is Jeremy Tonet with JPMorgan.

Good afternoon. Just want to follow up on some of the comments you had said there with KMI seeing an opportunity step more robust at any time in the company's future. And just want to, I guess, see if we could expand upon that in any way? And just wondering how you think about the landscape given Kinder's competitive positioning, it seems like it's a competitive market out there. And any thoughts that you could provide around that? And I guess, what could be the cadence of how this capital could fall into plan at a high level over time?

So a couple of things. I think I walked through some of the background on the $10 billion in opportunities. But with respect to -- on competition, look, we're not going to win all these projects, but we're going to get our fair share. And what makes us very competitive is our existing footprint, which provides us with opportunities to build off of that footprint and we can provide our customer services that other competitors can't offer. And so -- including storage, and so that's really, at the end of the day, what differentiates us from our peers. We also have a good track record on bringing projects in on time and on budget, which I think is helpful when time is important to our customers. And that's especially true, I think, for some of the data center and power customers. So I think in terms of how this comes -- how this -- the products of bringing these to that is -- that's hard to project. And so I can't tell you exactly what that's going to look like, but I think will bring significant projects to FID in 2026 based on that $10 billion backlog.

Got it. That's very helpful. And then just a smaller question for me as it relates to the guide. It just seems like the language changed a little bit with how much going to exceed the guidance by out regular in the 2Q versus 3Q? And it seems like it's a little bit less at this point. Just wondering what other, I guess, changes in the backdrop you see versus the 2Q.

Yes. I mean there was a slight change on that, and it's really related to the [indiscernible] the RNG volumes and the REMS price weakness.

Our next caller is [indiscernible] with Jefferies.

Maybe just picking up where the other guys just left off here. Can you elaborate a little bit on how you're seeing the opportunities emerge as it pertains to the shadow backlog? I know you gave some of these examples smaller and larger, but maybe regionally and how they pertain. I mean, obviously, we've seen examples recently in the last week here with a private backed pipeline FID in the Gulf Coast. Could you elaborate a little bit on the power opportunities, both in as it pertains to Texas, and also maybe as it pertains to the backlog opportunity in the Southwest, I mean, obviously, we saw what your peer announced in the last few months, but how do you think about the future on the gas side in the El Paso system.

Yes. I mean I think there's continued power development. A lot of it is for data centers, but there's other things that are driving power development coal retirements that some of those have pushed out some, but some of them are still -- some of them are still happening. And so what we see and there you need more peakers to back up renewables, which is what we're seeing in Texas. And so on the data centers and the power conversions, I mean, we're seeing that in Mexico, we're seeing it potentially in Arizona, some places where maybe the pipeline that got it now recently doesn't go, wouldn't serve. We're seeing some in Colorado. We're seeing some potentially more in Arkansas in Florida, Again, I'll just repeat some of these and the CPL come in. We're seeing opportunities to build out of the Haynesville to get gas further to the market. get more volumes potentially coming out of the [indiscernible] Utica. So there's a lot of different opportunities. Storage is a huge factor right now. people need a lot of storage. And so we're looking at some opportunities to expand our storage and some new greenfield opportunities.

So one thing I'll add, especially out West, is we have strong connectivity to Mexico. So when you think about the power demands there, those are also rising. -- and not only from the base organic power, but Mexico also is evaluating their own data centers. And so our footprint, especially out West is very well connected along those lines. And then when you look out in the Southeast, you've seen the IRPs that have been put out by all the various states. Clearly, there's demand that's coming. And as you all know, we're well positioned in that market to try and capture some of that growth. when I go to the Gulf Coast, we continue to debottleneck and the plumbing to be able to get the molecules from the supply zones to the consuming markets. I think that's something you can kind of takeaway on things that we're working on. And then all of this gets put together with our -- when we evaluate storage and how to integrate storage and then supply access to these consuming markets. Those are kind of the big themes that we're seeing on the horizon.

Got it. And if I can pick a little bit -- I know you just alluded to the Southeast opportunities on does that line up with what we're seeing right now in the generation resource planning? I mean, obviously, we've upticked it pretty meaningfully here of late. Is that presently reflected? Or is there a little bit of a mark-to-market to happen on your side? And then also on the Western Gateway, if you could just clarify what the ultimate economics are on your side or at least the total dollars [indiscernible]

So I'll take the first question, and I'll turn it over to to Kim and Mike on the second one. So Southeast, look, in terms of what we're in that $10 billion that Kim was referring to, that is taking into account some of the IRPs that are out there, especially in the Southeast. I mean that's what we see as infrastructure that's needed. And so I think to answer the first question, that is a subset of that $10 billion. And then I'll turn it over to Kim and Mike for the second piece.

I mean, in terms of the cost to build that pipeline, we're not going to get into that because as you know, there's a competitive project out there. And so the -- we don't want to compromise that position at this point in time.

Our next caller is Michael Blum with Wells Fargo.

Wanted to ask about Highland Express, the NGL conversion project. Just in terms of where do you stand on committed initial volumes? And where do you think that can go? And then I noticed in the press release, you talked about potentially some takeaway out of the Powder River as well. So I wonder if you can expand on that.

Yes. So sticking to our previous discussions, it's on track. We're on track to be ready first quarter next year for our initial commitment. Obviously, you all know we're also at a very aggressive competition with the incumbent there, so I won't get too much into the details on what's next. That being said, we have some assets that we're effectively repurposing to be able to position ourselves to draw incremental barrels to the pipeline. And I will leave it at that until we actually have the next set of announcements to make, hopefully, very soon.

Okay. Fair enough. And then I wanted to ask you about the behind-the-meter opportunities. I know in the past, you've talked about maybe coming up with a solution with partners. So just want to see where that stands and if that can be a meaningful driver? And if that's part of that [indiscernible]

I think the answer is still -- that's not something that we're interested in doing. I think we've got plenty of opportunity, plenty to say grace over in our existing infrastructure business. That is what we are good at, of what we know how to do. And therefore, the growth that we're projecting is very high-quality growth, as I said, largely backed by take-or-pay contracts. I think maybe we're missing a little bit is I think in the past, what we said is if there was a data center or something that wanted us to invest for some reason, maybe we might make a very small investment there. But that would just only be to facilitate a project getting done. That is not where we want to invest our dollars. And so what I would say is it is unlikely that we invest behind the meter.

But what -- but to add on to what Tim just said, we are looking at working with our partners to supply gas in certain instances to be able to support a consortium of folks to be able to provide reliable power. I mean I think that's the way you would look at our participation in the opportunity. we would be looking to build the infrastructure to be able to support that.

We'll supply the gas.

Our next caller is John Mackay with Goldman Sachs.

I'm going to go to the shadow backlog, too, I guess, not to keep running through the same thing. But I guess I just want to ask one more way. When you're looking at the $10 billion, how much of this is look at the competitive environment, we'll see what we win, we have a lot to bring to the table versus really waiting for actually that demand to materialize the next LNG FID, some larger power built out across the Southeast, et cetera. Maybe just what are the kind of buckets between the 2 in terms of what you see in front of you?

I mean, these are projects where we are actively talking to customers about them. And so I think we're having conversations with people we are putting together estimates on what things would cost. We're looking at returns. These are all things that are active conversations internally.

That's fair. Maybe just follow-up second question. I appreciate the comments on the guide around the RNG side being softer. Can you talk about the rest of the business? I mean, gas was relatively strong. Any more kind of one-offs in there? Or is this a kind of healthier run rate?

I think gas is very strong. We didn't have much of a winter or much of a summer. And they're still -- even if you take out the Outrigger acquisition, they're still going to nicely beat their budget. Terminals is also doing very well this year and should exceed its budget products, I'd say, it's kind of right on its budget, slightly short, but it's pretty small. And then where the weakness is really in RNG and a little bit on CO2.

Our next caller is [indiscernible] with Citi.

I wanted to start with the 2026 outlook. I know we're going to be getting a formal update from you guys in a few weeks. But maybe just at a high level, if you just talk about some of the variables you could see impacting the various segments? And maybe any reason 2026 growth wouldn't at least sort of match up the 2025 growth rate?

Well, I think we're going through a process right now. And so I think it's too early to talk about what the growth rates might be. But in terms of if you want to go tailwinds, headwinds, something like that, tailwinds, we've got expansion projects. We've got a full year of the '25 that we'll get in '26. And then you've got partial year '26 growth projects. We've got contract escalators in our terminals business and our products business, interest rates are coming down. So that should be a tailwind for us not expecting a significant increase in taxes, given what we've seen on the big beautiful bill and the bonus depreciation. As always, we see a little bit of decline potentially in CO2 in oil volumes. And then what's unknown is I think commodity prices at this point in time will just have to see where those come out.

Yes. Fair enough. Second one, if you could believe it. I do have another follow-up on the opportunity set. And so just curious, how we should think about the time frame that either the $10 billion or the 10 Bcf a day captures I'm asking from 2 different perspective. To the extent these are all opportunities you're sort of chasing within the decade, is there an opportunity here to see investment per year CapEx go up above $3 billion. And then conversely, how should we think about your ability to maybe deliver more short-cycle cash flows. A lot of these projects have later dated great projects. But just curious if you could sort of fill the front end up more, too.

Yes. So I think if you think about -- these are going to be both on regulated projects and regulated projects. And so the regulated projects now have a shorter time cycle than they have in the past. And so that's very good. I think the FERC has gotten rid of a 71. So that 5 months has gone -- that 5-month waiting period is gone. And I think they're working really hard to get permits delivered more quickly. So that's going to shorten that should shorten up your capital cycle some. I think the gating item is probably going to be compression. And so that's going to -- that will limit how much you can probably shorten it up. But I think in general, the FERC projects are going to be 3 -- a little over 3 years probably from the time you sanctional to the time you're in service. And I think shorter capital will be on the gathering side and then on all the Texas intrastate projects, all the pipelines in Texas and then potentially other intrastate pipelines in other states. So generally, I think you're going to start filling up the out years but you may have some near-term capital, which increases '27, '28 CapEx somewhat. But I think we have plenty of free cash flow and balance sheet capacity to be able to handle any increases that we see above $2.5 billion or $3 billion if you think about it. I'm not giving any guidance here. I'm just going out a rough number. If we have $5.5 billion of DCF, and you've got $2.6 billion of dividends, you've got $2.9 billion of cash flow to support the expansion projects. Then our balance sheet right now is sitting at 3.9x every 0.1x as $800 million. I don't -- we're probably not going to run it up to 4.5%, but you've got a $3 billion-ish at least a room there. And then over time, that debt to EBITDA is going to come down more as we bring these projects online. And so that balance sheet capacity is going to increase over time. And then I think there is also very attractive third-party capital out there if we wanted to access it. So I think we've got I'm not worried about capacity to finance these expansions. I think they are good return projects and we will find ways to do them without compromising our balance sheet.

Our next caller is Keith Stanley with Wolfe Research.

Just wanted to follow up on Western Gateway and I know you don't want to say a total capital cost. But my questions are more on the structure. So if Philips is building the new pipe and I think your capital investment is just a line reversal and maybe some tankage. Is it fair to think your portion of the CapEx is a lot smaller in this project? And then the second question is the structure of the JV, so you're contributing SFPP, they build Western Gateway. And then is it roughly like a 50-50 JV from there?

Yes. I think it's going to be around a 50-50 JV. And so yes, because we're contributing assets, our capital expenditure for the new assets would be a little bit less than what [indiscernible] would have to contribute.

Okay. Great. And then second question, I think, Kim, you referred to potential TGP projects that would egress out of the Appalachia region. I think there's been a few capacity reservations for projects. Can you just talk about what you think is possible or doable to increase capacity out of Appalachia on [indiscernible]

Yes. So this is Steve, Keith. Yes, we've been working diligently on trying to find ways to get incremental egress out of the basin as these consuming markets develop with the demand that Rich Kim talked about earlier, it's incumbent on us to get incremental gas out of the basin. We're in terms of what that capacity amount is still being worked on. But needless to say, I would say just rough numbers, north of half of Bcf is what we're trying to get but still early, and I take that with the grant auto we're done with all the diligence.

Our next caller is [indiscernible] with TPH.

Maybe going over to the Haynesville, it sounds like volumes continue to grow there. I think on the last few calls, you guys have mentioned you're getting close to capacity. Maybe an update there? And then is this from your largest customer on that system? Or are you seeing private start to flow volumes as well?

Yes. So one, we are -- as Tom mentioned earlier, we are pretty much at capacity. We're just waiting for when we cross the record, hopefully, any day now. But I think it's not only our largest customer, but there are a few of the other privates that are also looking to increase their drilling in response to the demand that's coming our way. And so we do see meaningful ramp up next year in the Haynesville.

Yes. And I think quarter-over-quarter, in the Haynesville volumes are up 15%. So we're seeing our customers bring on these volumes and you might remember, we announced last quarter a $500 million investment in the Haynesville, which is -- it's a lot of treating capacity, but also some incremental pipe capacity to be able to accommodate our customer volumes.

Got it. That makes sense. And then maybe moving over [indiscernible]

We expect it to be one of the strongest -- probably the fastest-growing basin. Our internal projections are it's going to grow almost 11 Bcf a day between 2024 and 2030. So it's going to go up to probably 23 Bcf a day in terms of production. So I think we're seeing opportunities today, but I expect we'll continue to see opportunities over time both to invest in the Haynesville and to take molecules away from the Haynesville.

Got you. No, that all makes sense. I appreciate the color. And then maybe 1 on the Permian West expansion open season it looks like that gas is heading west bound. Just curious if that could be upsized if the demand is there. And then maybe some color on the customer mix. There's obviously some data centers where that expansion is heading. Is there demand also beyond Texas as well?

Yes. Look, I mean, I think -- I believe you're referring to the the smaller open season that we've got out there going west, that is to serve power. And obviously, as the open season closes, we'll evaluate the bids and look at what we can do to accommodate the capacity. Clearly, in and around that area. And then if you go to flip over 1 state over into New Mexico, there's a lot of activity on the power side. And so we're just going to have to evaluate how the bids come across.

Our next caller is Brandon Bingham with Scotiabank.

Just one quick one here for me. I would just be curious as to what you guys think the longer-term market dynamics are in California for the refining products market and whether or not there's upside potential for Western Gateway or any other future growth into that market? Just any high-level thoughts you have?

Yes, I'd say we wouldn't want to speculate on the California markets, what's happening there. But if you think about our reversal of the West line and that volume need now to be filled through the new gateway line into Phoenix, you've got this access into California. So depending on what that California refining market does. You've got the capacity across that West line to continue to grow with changes in that market. And then as we've talked before, you also have access beyond through [indiscernible] into Las Vegas, Nevada.

Our next caller is Jason Gabelman with TD Cowen.

I wanted to ask about the shadow backlog as well. And you mentioned both kind of large-scale and smaller projects. And I was hoping to get a bit more color on the larger projects. If I look at the backlog that you have right now in projects and execution, it's kind of large projects that are all serving Texas and Southeast. Should we assume the large projects in the backlog are kind of similar markets they serve or is it kind of a bit different? I noted, for example, you mentioned Mexico a couple of times and wondering if that's one of the larger projects in the backlog.

Well, so all these projects are competitive, almost everyone that we're working on. And so that's why we haven't given it -- we've tried to be very broad in how we describe but this drives the backlog. So what I would say about the larger projects in the backlog is generally, they are around the themes of supporting export LNG and supporting power.

Okay. Understood. And then my other question is just on M&A. Given there's starting to see once again a bit of a larger multiple dispersion between natural gas and liquids names? And given you do have a decent sized nonnatural gas business. I wonder if there's opportunities out there or hold in the portfolio that you'd be interested in filling especially if crude oil prices fall and some other companies become available?

Are you talking about buying?

Yes.

So look, I mean I think acquisitions, M&A is always opportunistic. And so we will look at opportunities for assets that set our strategy, which is owning energy assets, energy infrastructure assets. Fee-based and we can do it on returns that we think are appropriate on a risk-return basis and that we can do within keeping our balance sheet within the metrics to 4.5x debt to EBITDA. So I don't -- again, I think our view is there's unlimited capital for good returns, good risk return opportunities. And so we'll continue to look at those. We've done some in the recent past. We haven't done anything that is huge, but we did 1 at the end -- the beginning of this year in Outrigger. We did 1 last year as well. And so those things are hard to predict. But I think we either have the capital depending on the size or can find the capital to pursue those when they come about.

Our next caller is Dave Winans with Prudential.

You guys got a great opportunity set in natural gas, but just kind of switching gears a little bit here to the CO2 business at least one operator is talking about potentially using CO2 suites in some of these type plays out in the Midland and Delaware basins and such. Is that something you guys have looked at? Does that represent a business opportunity for Kinder Morgan? Or do you need to see more proof of concept around something like that?

Are you talking about participating in that Dave? Or are you talking about supply [indiscernible]

Either.

And I think with regards to supplying the CO2, we certainly would be interested in that. I think in terms of the other side of that, I think we would have to look at that a lot more closely and really seriously look at the risk/return opportunity there before we would consider investing.

And it depends on my understanding on a lot of these, Anthony, is it depends on how they frac that deal to begin with. So whether they would be successful CO2 candidates. I think any time you're doing something new, you need to get a much higher return on that to compensate for the risk of doing something that you haven't spent a lot of time doing before. Obviously, we know what we're doing in CO2, but we haven't done a lot of flooding from these previously for fracked fields.

Our next caller is Jean Ann Salisbury with Bank of America.

I just wanted to follow up on the comments that you've made about needing to build pipelines from kind of Tier 2 basins, not the Haynesville to the LNG that's coming online. One issue, I guess, that I had been thinking about is that it's a little bit unclear who would be willing to underwrite these contracts with the LNG builders kind of being linked to Henry Hub and the EMPs maybe not wanting to take long-term contracts. So I was just wondering if you could give any color on if you see that being kind of a constraint to these [indiscernible] and just if you think it will be a mix of end users, E&Ps and marketers on those trends of pipelines?

Yes. I mean second-tier basins, something like the Eagle Ford, I think, is very well positioned. And I think there's, one, that would be great for us because we've got a great position in the Eagle Ford -- and I think that is a basin that could grow more than what is in a lot of the current projections. In a place where infrastructure is relatively easy to build. And then I think the Haynesville has a lot of growth to come to support this. But [indiscernible]? .

Yes. When we look at this, I think as the markets start figuring out what -- where they can actually get a molecule that will drive. So I would -- the way I would answer the question right now is that would be driven primarily by the market pulling from the supply and then some of the producing base producers kind of complementing, it's going to take a little bit of both, especially in the second-tier basins. And I think that's going to evolve over time as the plumbing gets kind of discovered where we can get gas where you can source gas and how that moves through the networks to the grid -- the pipeline grids to be able to get to the consumer. That's the way I would think about that.

At this time, I am showing no further questions.

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

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.