Title

Presentation

Kinder Morgan, Inc. beats earnings expectations. Reported EPS is $0.48, expectations were $0.3959.

Operator: 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.

Richard Kinder: 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.

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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.

Kimberly Dang: 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.

Dax Sanders: 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.

David Michels: 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.

Kimberly Dang: Michelle, if you’ll come on, and we will take questions.

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

Unknown Analyst: 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?

Kimberly Dang: 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.

Michael Garthwaite: 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.

Unknown Analyst: 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.

Kimberly Dang: 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.

Operator: Our next caller is Theresa Chen with Barclays.

Theresa Chen: 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?

Kimberly Dang: 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.

David Michels: 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.

Theresa Chen: 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?

Kimberly Dang: 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.

Michael Garthwaite: Through first quarter of ’28.

Operator: Our next caller is Brandon Bingham with Scotiabank.

Brandon Bingham: 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?

Kimberly Dang: 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.

Brandon Bingham: 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?

Kimberly Dang: 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.

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

Manav Gupta: 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.

David Michels: 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.

Kimberly Dang: 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.

Manav Gupta: 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?

David Michels: 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.

Operator: Our next caller is Michael Blum with Wells Fargo.

Michael Blum: 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.

Kimberly Dang: 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.

David Michels: Mike, just to clarify one thing. We’re buying the monument pipeline, not momentum.

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

Jean Ann Salisbury: 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?

David Michels: 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.

Jean Ann Salisbury: 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?

Kimberly Dang: Today, there is some incremental capacity versus what we would move in ’27.

Jean Ann Salisbury: 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?

David Michels: You’re referring to the Amarillo expansion. Yes. Yes. So that is market pull driven by power.

Operator: Our next call is Keith Stanley with Wolfe Research.

Keith Stanley: 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?

Kimberly Dang: 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?

Keith Stanley: 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?

Kimberly Dang: 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.

Keith Stanley: 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?

Kimberly Dang: 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.

Operator: Our next caller is Olivia Foster with Goldman Sachs.

Unknown Analyst: 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…

Kimberly Dang: 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.

Richard Kinder: 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.

Unknown Analyst: 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?

Kimberly Dang: 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.

Operator: Our next caller is Jeremy Tonet with JPMorgan.

Jeremy Tonet: 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?

Kimberly Dang: 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.

Jeremy Tonet: 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?

Kimberly Dang: 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.

Jeremy Tonet: 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?

Kimberly Dang: 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.

Operator: Our next caller is Elvira Scotto with RBC Capital Markets.

Elvira Scotto: 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?

Kimberly Dang: 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.

Richard Kinder: 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.

Operator: Our next call is Jason Gabelman with TD Cowen.

Jason Gabelman: 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?

Kimberly Dang: 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.

Michael Garthwaite: 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.

Jason Gabelman: 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?

Kimberly Dang: 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.

Operator: Our next question is from Zach Van Everen with TPH.

Zackery Van Everen: 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?

David Michels: 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.

Zackery Van Everen: 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?

David Michels: 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.

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

Richard Kinder: Okay. Thank you all very much.

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

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