Good afternoon, and thank you for standing by. Welcome to the Kinder Morgan third quarter 2026 earnings results conference call. Your lines are in a listen-only mode until the question and answer session of today's conference. At that time, you may press star followed by the number one to ask a question. Please unmute your phones and state your name when prompted. 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 one 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 two estimates just reinforce and strengthen what we believe is a bullish natural gas story. 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 one of the largest increases in any one quarter in our corporate history, and our backlog of U.S. natural gas projects now stands at an all-time record. 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 am 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 have 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 are in a unique position to capture a substantial portion of that need by developing projects supported by long-term take-or-pay agreements with credit-worthy entities. 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 is hard to think of a better strategy that combines consistent growth with minimal risk. Now let me tur n 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 one 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 $9.6 to 14.4 billion 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 two 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 one of the fastest-growing natural gas demand regions in the country.
Large load interconnection requests 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 if it was all served by gas-fired 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 Link captures a similar compelling opportunity by moving abundant, low-cost Permian natural gas north to meet growing power demands 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 2025. 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. 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. The 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 two very important projects today, looking forward and consistent with Kim'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 product 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 Double H from service for the NGL conversion early in the third quarter of 2025, with the remaining decrease resulting from fewer well connects at Hiland Crude.
As previously announced, we, along with our partners, were 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 remains high at almost 93%.
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 three 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. 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.
This 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 $0.24. 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 four business segments delivering higher adjusted earnings year-over-year. Natural gas saw greater contributions from EPNG, KinderHawk, TGP, and our Texas intrastate system. This performance was driven by greater volume and rates on capacity sales, park and 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. 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've 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, an 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 3.5 times, which is down from 3.8 times 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 3.6 times leverage. That's an improvement from the budget of 3.8 times, driven by the EBITDA outperformance. 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've 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. The Monument acquisition was approximately $500 million, and that gets you pretty close to the $513 million debt increase for the year. I'll turn it back to Kim for Q&A.
Okay, Michelle, if you'll come on, we'll take questions.
Thank you. At this time, if you would like to ask a question, you may press star followed by the number 1. To withdraw your question, you may press star two. Please unmute your phones and state your name when prompted. Our first caller is Theresa Chen with Barclays. Your line is open.
Good afternoon, and congratulations on these major commercial milestones. I want to ask first on TGP. Following a successful non-binding open season for the 219 South project, can you talk about the progress made on solidifying customership or commitments at this point?
How are you thinking about the ultimate size and scope for this project, given the elevated amount of interest beyond the half a B 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 SNG?
Theresa, this is Sital. How are you doing? Well, one, I am going to break this question up into a few parts. The open season that we had, the non-binding open season, in terms of interest, over 2 Bcf of interest in that open season. Where we are right now with our customers, clearly, we have been intimating to the market, and you guys that there is a demand equation here, and ultimately, will need to be solved with incremental molecules.
We do feel 219, in some form, is going to help contribute to that molecule shortfall. When we think about what the project ultimately looks like, that is going to depend on who signs at the bottom line. One of the things that we are seeing right now is timing. There are some customers that are further along than others. We are managing through that to try and see how we can stage these projects.
It may come in multiple forms. If I had to gauge where I see the CapEx landing there, roughly around $1.5 billion. Depending on ultimate interest, we could adjust from there. So strong interest. We do see the need. I think when you think about the downstream Southeast Connector, Tennessee is well positioned to serve that. Not only that, it is 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 to Tennessee, that is a growing demand center. 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 a little too early. We are 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 are still in the process of working through the precedent agreements, the interest on the commercial side, as well as very important credit, making sure we have the credit behind. We are working through those details. But needless to say, we can scale this up to 3.5, 3.5 Bcf is plausible.
Thank you, Sital.
Teresa, just for context. We have enough signed commitments today to support going forward in FID-ing the project. There are other customers that came in during the open season that are interested, that we're working with on PAs, and they may come in later, and that would cause us to scale the project.
Ultimately, it depends on who signs, right? I mean, that's always the driver.
Understood. Thank you.
Thank you. Our next caller is Julien Dumoulin-Smith with Jefferies. Your line is open, sir.
Hey, good afternoon, team. Nicely done. 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 were bringing up on the middle system here on the power corridor, how do you think about the size and scope of that opportunity, the timeliness here? You allude to having some open seasons pending here, but just what is the scope of contemplated there? You talk 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?
If you're focused on Southeast Connector, we've got that open season. It'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, and this is particularly on our 219 South project. Really the timing there is what we're talking about. There are some that are further along than others.
What we're going to have to do is really position ourselves to sanction parts of the project to be able to accommodate the immediate demand. The team is still creatively thinking on how we can accommodate the broader interest in terms of incremental scope. That's going to take a few quarters to kind of button up in some form or fashion. Ultimately, as usual, we'll sanction when we get customers that sign to the bottom line.
Awesome. Excellent. A little bit bigger picture, after adding $5 billion this quarter, how is the greater than $10 billion commentary or opportunity set change? Should investors view the Southeast Connector and Permian Link as conversion from the shadow backlog into a more formal backlog? Or as you just alluded to a second ago, as continued customer activity 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.
The shadow backlog today, there is substantial remaining shadow backlog. I would say that, as we talked about in our comments, adding these big projects leads to further opportunities. We think that, and we have 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.
I think the industry fundamentals in natural gas, as we talked about also in our opening comments, remain very strong. We are confident that there will be meaningful additions, conversions, if you will, into the backlog over time.
All right. Fair enough. I will 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?
I think. Yeah. Go for it.
The bill that is in Congress?
Indeed.
Huh?
He said yes.
Okay. The bill that is in Congress obviously has not passed yet. 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 System 4 both permits from the FERC within a year, which is the fastest in recent time on permits of this size. I think that the current permitting regime, we will be able to get those projects done.
No concerns there. I think the permit bill that is in Congress is a good one. I think it does some things that could help on where we have seen certain projects, not ours, run into problems. For one, it eliminates the state's ability to what I will call game the 401 water permit. It eliminates the vacatur as a remedy of the court, and it strengthens the Nationwide Permit 12 program.
I think it would be great if it got passed. We think it would be very helpful, and we are very supportive of it, but we are very comfortable completing these projects under the current permit in the current permitting environment.
Excellent. I appreciate it. Thank you, guys. Nicely done.
Thank you. Our next caller is Jeremy Tonet with JPMorgan.
Hi, good afternoon.
Good afternoon, Jeremy.
I just wanted to follow up on the capital opportunity set as you have been describing here. You announced some pretty sizable projects here. 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 the two big ones that you had seen? How do you think about run rate CapEx at this point?
Okay. Let me say, it is hard to project exactly what is going to be coming in, but Sital just talked about another $1.5 billion project. We have talked about other projects that we think will come about as a result of Southeast Connector. 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.
We were providing this number to try to help you understand the opportunity set. I think, at this point, with a $14.4 billion backlog, I hope we have established some credibility about being able to bring these things to fruition. With respect to run rate, I think it is probably going to be around $4 billion-ish for the next few years in terms of the CapEx that we would expect to spend.
Got it. That is very helpful there. Thanks. Dave, wanted to pick up, I think, on some of the comments you laid out when looking forward to 2027, some one-time upside optimization that I would imagine is not baked into the guide for next year. It seems as far as major projects coming online, it is more Trident, but that is very late 2027, more 2028 weighted. I know it is premature to ask, but just any other thoughts as we think about 2027 when we are modeling it, the EBITDA?
Yeah. We are going to avoid giving any previewing the 2027 guide for right now. Yeah, I think it is important to note that some of those items that we experienced this year, it is unlikely that we are going to see those again next year. Winter weather is always hard to predict, but we are not going to budget a colder or more severe winter weather than we normally do. 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 will give you the sensitivities that we will have in the budget.
Let me just address growth for the longer term other than 2027. As David said, we are in the middle of our budget process. We will 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 have $14.4 billion in projects that will bring in quite a bit of cash flow.
But it is true that because those projects do not come on evenly over all the years, the growth is not going to be even every single year. An example of that is Trident, only 30% of the contracted EBITDA comes on in 2027. 2026, because it has some of these items, is going to be a difficult year to replicate, but the underlying business here, all of our underlying businesses here remain very strong. The projects are going to deliver enormous benefits as they come online.
Got it. Thank you. I will leave it there.
Thank you. Our next caller is Praneeth Satish with Wells Fargo. Your line is open, sir.
Thanks. Good afternoon, and congrats on an incredible quarter here with project FIDs. Maybe just going back to 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. Does that $1.5 billion get you all the way to a 2 Bcf per day project, or is that based on the 500 MMcf per day open season that you went out with? I guess, where does this project transition from brownfield to greenfield?
Well, look, it ultimately depends on the shipper receipt deliveries, right? I can tell you, if we scale to a 2 Bcf to 3 Bcf number, it would be higher than the $1.5 billion. We're really focused on, at this point, just the brownfield component, and then ultimately we'll adjust accordingly with incremental volume adds. That's the way I would think about that.
Okay, that makes sense. 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 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?
Here's how I think about those pipes. Our intrastate system, I talked about this on the last call, Permian Highway and GCX, they're in the heart of the demand centers that are coming in and further developing. Our focus has shifted to really focus on these demand pulls. What we see there, especially across our PHP pipeline system, is we see a power demand center corridor forming.
To the extent that there's any push pull back by any of the producers that are underpinning the project, we see demand pull. The same thing is out there in our Gulf Coast systems. Both of these pipes were some of the first pipes built, so from a cost perspective, relatively low on the cost spectrum. What we see there is GCX. There's so much incremental LNG demand that is yet to come. I think we feel pretty good about that. Overall, our focus has been on market pull. We see those underpinned by long-term contracts. From a portfolio perspective, we feel pretty good.
Yeah. Sital's point, we've got like 6,000 miles of intrastate pipe and 145 Bcf of storage, and those pipes tie into that, are part of that system, and tie into a lot of demand. We feel good from a demand pull standpoint that those pipes will continue to have opportunities.
Understood. Thank you.
Thank you. Our next caller is Manav Gupta with UBS.
Good afternoon. Just for the record, we always viewed your claims of $10 billion shadow backlog very credibly, and you did say that the two projects add further credibility. Even if they would not have been announced, we would have been very confident that your backlog would end well over $10 billion before year-end. Just wanted to put that out there.
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. Can you give us an update on what the phase 1 and phase 2 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 should be delivered in February of next year. Sital, you want to talk about the market?
Yeah. Look, we've talked about this when we sanctioned 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. Beyond that, we ultimately pulled. You get down to the LNG corridor, and we saw the need to go from there further west to the Gulf Coast corridor, and we see incremental demand.
That coupled with our Texas header, our KMLP header, and the KMLP 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. As Rich alluded to earlier, when you get these stems inside and you get ancillary, secondary, and tertiary expansions off of those stems. We feel pretty good about that, and we think we can help on the demand side as this demand develops.
Perfect. My quick follow was a little bit just focused on the Florida gas market. It is 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. Thank you.
Well, I will talk broadly. As you know, we are not the operator of FGT. We will let Energy Transfer talk about the details. But I will tell you this. We have been talking about this thematically in the Southeast. We see strong demand in Florida, we do. FGT sanctioned a few projects already. We are obviously in discussions with other customers on future potential expansions.
We see the demand profile as being strong. I will just leave it at that. As you know, we are not the operator there. We work with the operator, but we feel pretty good about the asset as well. It is not just SGT, but we have SNG, who also can help serve some of that growing market.
Thank you so much.
Thank you. Our next caller is Jean Ann Salisbury with Bank of America.
Hi. 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. 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.
I think one of the benefits that Permian Link brings to the power market as we've talked about before is the link to storage and the flexibility and reliability that helps these hyperscalers achieve their seven nines of reliability. I think that's a real differentiator here. As the next phase, we look at all of our storage facilities to see where we could kind of enhance service and flexibility, and that's what I think differentiates this.
That makes sense. Thanks. Then building on Theresa's earlier question, do you anticipate all the gas that's feeding Southeast Connector to, like, will it substantially all originate from Appalachia? If that's the case, would you potentially require even more expansion than just TGP can provide?
Well, so look, one of the beauties of kind of the locations we've picked is we've got access to multiple pipeline corridors, right? Tennessee. Selfishly, we want to grow Tennessee, but we have interconnects with Columbia Gas. We've got interconnects with TETCO. We've got interconnects planned with several other major interstates there. Ultimately, those pipes also have forward haul, back haul capabilities.
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. So you basically could get a molecule from the Gulf Coast to that point via all of these major trunk pipes including Tennessee, and then also from the Appalachia, Marcellus, Southwest Utica, down to that point. So it's multiple basins that can kind of serve that takeoff point. That's the beauty of it.
That's helpful. Thank you.
Thank you. Our next caller is Brandon Bingham with Scotiabank. Your line is open, sir.
Hey, thanks for taking the questions. I 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. Just with the rate of change in Permian gas here and maybe not the most favorable price signals for broader Haynesville development, just how do you see those two basins playing out in the fight for U.S. Gulf Coast capacity, and who could be the primary driver there?
Well, we've said all along that we believe it's going to be all of the above. 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. We think there's plenty of resource. The key is going to be building that infrastructure in the middle, which we're really focused on. Then ultimately, the price will take care of itself.
Yeah. If you look at Wood Mac numbers, and 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 three big producing basins that are helping to get that 46 Bcf of growth that we referenced between now and 2035. We need them all.
Okay, great.
Yes.
No, it's, yeah, absolutely fair. 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. Looking at the SNG, the comments that you've made and just the projects you have going on in the South.
We move about 40%.
Okay.
There's no science behind this other than we move about 40% of the gas in the U.S. market. We move about 50% of the gas to Mexico, 40% going to LNG, and 45% of the power demand across the South. I think that's as good a number as any.
Great. Thank you.
Thank you. Our next caller is Keith Stanley with Wolfe Research. Your line is open, sir.
Hi. Good afternoon. First, wanted to clarify the SEC project you are sanctioning today, does that include the SEC extension line up to the Nashville area? If you could comment at all on the phasing for both SEC and Permian Link. They start up in the fourth quarter of 2030. When would you get to the targeted build multiple by?
Okay. Yes, SEC does include the Greenfield line. On Permian Link, it comes online in 2030, and on SEC, it comes on 2030, 2031, and 2032. It comes on over 3 years.
Got it. Thank you for that. Second one on Western Gateway. You are 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 during construction? Would you have to fund your share of that, or is there a separate mechanism given how you are contributing to the JV?
Let me say a couple of things on that. One is, I think we are being very prudent about how we are approaching this project in terms of spending capital until we get more comfort around the ability and make sure we are very confident that we can get built through the states that this has to go through. Secondly, what I will say, and I am not going to go into a lot of detail about it, but we do have certain cost protections against cost overruns on that project.
That's helpful. Thank you.
Thank you. Our next caller is John Mackay with Goldman Sachs. Your line is open, sir.
Hey, team, thanks for the time. 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, has the tone with customers changed all that much over the last couple of months compared to, let's say, earlier this year?
No. John, we haven't seen a change. I think our customers continue to engage, and we continue to look for our 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 continue. It's been good.
No, that is great. When we look at the implied returns on these new projects being sub 6 times, or if you look at something like the billions CapEx per Bcf of capacity numbers going up over time, could you just touch a little bit about customer willingness to take some of these higher implied rates, and what that means maybe from looking at a producer side versus the demand side customer? Thank you.
Okay. A couple of things. One, I think what you are referencing is the cost per pipeline mile or whatever has gone up, and that is going to be a function of a couple of things. One, steel prices, slash pipe prices have increased, compression costs have increased. That is what you are seeing in the cost numbers. We have not seen customer pushback.
We did not change our return thresholds, right? We are still targeting the same return thresholds. We have not increased those or decreased 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 have seen.
Just any comments on customer mix in terms of producer willingness to engage versus the demand side? Thanks.
Well, generally, all the projects we are 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. Now, some of them have been there for a long time, but the demand pull, it is there for decades. We feel very good about the customers on these projects.
Appreciate the time. Thank you.
Thank you. Our next caller is Spiro Dounis with Citi. Your line is open, sir.
Thanks, operator. Afternoon, team. I want to start first with project timing. You talked about adding cash flow after that 2032 timeframe, but it sounds like you're still filling in some growth for 2029 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'd.
I wanted to understand how you're thinking about, I guess, what's needed to fill out more growth in 2029 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 to 2030 plus timeframe.
Well, 2029 and 2030, South System 4 is coming online Q4 of 2028 and Q4 of 2029. That'll drive growth in 2029 and 2030. Then I think MSX, the second phase is mid-year 2028, so that'll drive additional growth in 2029. Then these projects, you'll get fourth quarter, probably, roughly you'll get the Permian link in.
As I said, it's not going to be exactly the same growth rate every year. It'll vary year in and year out. With this backlog and a 5.7 times 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-worthy entities or that have significant collateral posted.
Got it. Second question, talk about Trident, but 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 one point. Just curious about maybe the prospects you see to make another move into Arizona.
Well, look, on the western side, we do see opportunities. We have both of our legs, pipeline both to Arizona and Mexico. I would characterize it as we do see significant power demand there. We also see traditional conversion, coal plant conversion as opportunities on the western side. But it's too early to comment on where and how those get to compete. We do have discussions ongoing out west as well.
Great. I'll leave it there. Thanks, everyone.
Thank you. Our next caller is Gabe Moreen with Mizuho. Your line is open, sir.
Hey, good afternoon, everyone. I am not sure if it is allowed, but I would like to ask some questions on your non-natural gas businesses.
Yes.
Right.
Our analysts are here.
Right.
They love to answer your questions.
Okay. Thank you, Kim. One I was going to ask, just with the forward curve on crude oil has moved up nicely here in 2027 and beyond, whether that puts some CO2 expansions back into play, potentially. Also, I think there may be some inorganic opportunities out there on RNG. I am just curious your thoughts on potentially expanding that business as well.
Yeah. Gabe, thank you for tossing me a bone.
No problem.
Yeah, no. As you know, EOR projects take some time to develop, right? The forward curve has come up, but it is still pretty backwardated. I would say yes, we are looking at all of the projects that we can do, and our ability to accelerate, but it is really no different in terms of how we view investment in that business over time.
It is going to be looking at that curve, and we will be sensitizing that curve as well for lower oil prices in case those arise as well. Obviously, the oil prices, there is a lot of geopolitical risk associated with that. There is some concern to extent the war ends, where crude prices end up. But as I said, we are pretty careful in terms of how we look at our EOR investments.
We demand higher returns than we do on fee-based businesses, to take account of that risk. On RNG, I do not think we can really talk about ongoing third-party processes. We are aware of those out there, and we will continue to look at whether it makes sense to grow that businesses. We have had some operational issues in that business. I think we will be careful to extent that we want to step in into a bigger share there, and it will have to come with a higher return as well.
Yeah. The other thing I'd say on the RNG business, we did have some struggles, but we do have a team that has learned and who knows how to operate these at this point. I think we've developed some expertise there. We also have a lot of lessons learned that we would take into account if anything we'd look at. Then, to Anthony's point on the CO2 stuff, when we look at those are long-term projects. We tend to run some kind of fixed oil price to make sure that we get to our return. We don't just jump into projects because the current year goes to $85.
Thanks, Anthony. Thanks, Kim. If I could just squeeze one more on the back end, I'm just curious, on a Double H end, how Hiland update, it seems like there's some shifts going on there in the G&P landscape in the back end, just wondering if that makes you more or less inclined to invest more capital up there.
Look, we've invested significant capital up there. I think we're pretty well positioned for what we see coming. 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.
Great. Thanks, everyone.
Thank you. Our next caller is Zack Van Everen with TPH Research. Your line is open, sir.
Hi all. Thanks for taking my question. 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 agreements 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 look, we explain the macro environment. They have to make their own judgments on this. 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. Once again, it's a function of
Supply and demand, and there's other basins 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. That's how I would leave it. I think it's broad enough. I think folks understand that they need to secure a molecule. I think we make sure that's clear, and the rest is up to them.
Got it. That makes sense. Maybe a quick clarifying note. When you mention the 200 gigawatts in the Southeast equating to about 8 Bcf a day, is that a risk number? Because that feels a little lower than the general 150 MMCF a day per gigawatt that most people use.
Yeah. To keep my mind simple.
We just divide by 5.
I say inefficient plants. How's that? Inefficient plants.
Right. Inefficient plants, yeah. Look,
Okay
that probably likely will all happen, right? That is all the connection requests, assuming they all go, and that is all natural gas. It will be some combination. The point is, there is a huge amount of demand growth in the Southeast, and that is part of what Southeast Connector is addressing.
Got it. Appreciate the time. Thanks all.
Thank you. Our next caller is Jason Gabelman with TD Cowen. Your line is open, sir.
Yeah. Hey, thanks for taking my question. I wanted to ask about Permian Link and your targeted IRRs. You talk about, I think, mid-teen after-tax IRRs. I wonder, given this project with only one anchor shipper has some perception of higher risk, did that require you to construct the project for a higher IRR, or 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. What I'll say is this, which is we can move up and down on the risk-return threshold or 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's not willing to share in cost overrun, we need a higher return.
We have some flexibility in how we approach that. 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 that's one rate, and we put them one rate. If they're willing 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. We can add more shippers to this over time. That will lead to even higher returns.
Yeah, it's important. When we talk about the scope of this project, we have capabilities to serve incremental. We're talking to incremental customers to basically fill the rest of the basket, if you will.
Got it. Thanks for that. My other question is a bit separate. As you pursue connectivity to move more gas from the Marcellus, I'm wondering if there's anything to be gained to move further upstream into Marcellus G&P. 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?
Look, we have some pretty good customers of our own that are very sophisticated in doing that. 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. I think we would collaborate with our customers to do that, and I think that's probably the best course for us.
Yeah. I think there's very established mature players in that.
Yeah.
Typically they're going to have an incumbent advantage.
Great. Thanks for the time.
Thank you. Our next caller is Harry Mateer with Barclays. Your line is open, sir.
Hi. Thanks. Good afternoon. 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 at both those JVs during the construction phase.
Yeah. I think it's going to be a combination of the JV funding a portion of it and us contributing in capital. I think those JVs have nice cash flows that can go to fund 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 a way to maintain the existing ratings at those JV pipes.
There will be some capital required above that, in which case we will make equity contributions from owners. 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.
Got it. All right. Thank you.
Thank you. Mr. Kinder, at this time, we are showing no further questions, sir.
Okay. Well, let me just conclude with two remarks. 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. 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 was some, let me call it skepticism about whether we could really bring these projects along. 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 corral now with the saddles on, but we've got more horses just outside the corral, and I think you're going to see them.
They want to come in.
They want to come in. That will be the message for the future. Thank you all for your good questions. We appreciate it. It has 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.