Kinder Morgan Inc - Class P (KMI) — Q1 2026 Earnings Call Transcript

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 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 concerns 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 made turned 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-fired 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 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 a 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 INGAA Foundation in a study released in March estimates that North America needs 70 Bcf a day of new gas pipeline capacity by the 2050 time frame. And I believe Kinder Morgan will fare very well in this environment. Let me tell you why. We have a superb set of assets located in the areas where gas demand is growing dramatically. Our strategy is to concentrate on expanding and extending those assets in an aggressive but disciplined manner. This means we will continue to identify and pursue the myriad of growth opportunities we are currently seeing and once undertaken to complete the resulting projects on time and on budget. Because our cash flow is very strong, we will be able to finance these projects primarily with internally generated cash flow, and I can promise you an intense and unrelenting focus on these unparalleled opportunities. This strategy will enable us to grow our EBITDA and EPS substantially over the coming years as these projects come online, while still maintaining a strong balance sheet and growing our dividend. To me, that's a pretty good recipe for success. And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. We had a remarkable first quarter. The best I can remember with adjusted EPS up 41% and EBITDA growing by 18%. Importantly, every segment delivered growth versus the first quarter of '25 and every segment outperformed our budget. Natural gas drove the most significant share of the outperformance, benefiting from winter storm burn and the extended cold in the Northeast. These results reflect the value of our critical infrastructure and the essential role it plays in serving our customers, especially in periods of high demand. During the quarter, we entered into an agreement to acquire the Monument pipeline system in Texas for approximately $500 million. These assets are a natural fit with our existing network, supported by long-term contracts and acquired at an attractive multiple. We received early termination of HSR yesterday and expect to close by the end of the month. On full year guidance, we now expect to exceed our EBITDA budget by more than 3%, excluding any contributions from the Monument acquisition. Most but not all of that outperformance is attributable to the first quarter. Given that we are still early in the year, we've taken a somewhat conservative approach to our expectations for the year. However, continued outperformance in our gas group and/or higher oil prices, which benefit our approximately 10% unhedged oil in the CO2 segment, could provide upside for the balance of the year. The growth in the overall natural gas market of over 36 Bcf since 2016 has driven utilization on our five largest gas pipelines to over 90%. That utilization, combined with the projected growth in the market to approximately 150 Bcf a day in 2031, highlight both the need and the opportunity for expansion. Our expansion project backlog increased to $10.1 billion this quarter, up $145 million from the last quarter. We put approximately $230 million of projects in service and added $375 million in new projects, including three data center deals. The backlog multiple remains below 6x with an average in-service date of Q1 2028. With respect to our three largest projects, which make up over 50% of the project backlog, we continue to be on time and on budget. Beyond our reported backlog, we're actively advancing a number of identified opportunities. Much of this activity is being driven by power growth, and we expect a meaningful amount of these opportunities to convert into approved projects during 2026. Our performance this quarter demonstrates the strategic positioning of our 78,000 miles of pipeline and 136 terminals and the tightness of energy infrastructure. As we look ahead, we're confident in our ability to complete our $10.1 billion backlog of projects, add to that backlog and deliver tremendous value to our investors. And with that, I'll turn it over to Dax.

Thanks, Kim. Starting with the natural gas business unit. Transport volumes were up 8% in the quarter versus the first quarter of 2025, primarily due to increased LNG feed gas deliveries on the Tennessee Gas Pipeline. Natural gas gathering volumes were up 15% in the quarter from the first quarter of 2025 and increased across most of our gathering and processing assets with the largest impact coming from our Haynesville system. The winter storm burn 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 and 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 net oil production volumes compared to Q1 2025, led by a 5% increase in production at SACROC. NGL volumes were 5% higher and CO2 volumes were 1% higher. Notably, RNG volumes increased 63% due to greater uptime at our facilities and greater hydrocarbon recovery as the team running that business has made great progress in improving the overall operations of those assets. With that, I'll turn it over to David.

Thank you, Dax. So for the quarter, we're declaring a dividend of $0.2975 per share, which is $1.19 annualized and an increase of 2% over 2025. As you've heard, we had an outstanding first quarter, generating net income attributable to KMI of $976 million, an EPS of $0.44. These are 36% and 38% above the first quarter of 2025, respectively. These very impressive results reflect strong demand fundamentals across the country, combined with strategically positioned assets and skilled execution by our colleagues to capture the associated opportunities, and we saw growth across the business segments. The natural gas segment grew the most with colder-than-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 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 the 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 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 three rating agencies. Additionally, the treasury issued guidance in March that will allow us to more fully take advantage of bonus depreciation across all of our assets, and that creates nice near-term cash flow benefits, which will generate additional investment capacity. With that, I'll turn it back to Kim.

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

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

I'll say a couple of things, and then Mike Garthwaite, if you want to add anything. We still have 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 and get through these discussions, assuming that we get through these discussions with our partner.

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

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

The need is clearly there. But I think we've said this a number of times: we would have to have certainty on state permits, and we would have to get the commercial support we need to underwrite a project. 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.

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?

That's quite specific. Okay. So let me just say a couple of things about that. The $500 million purchase, as we mentioned, has long-term contracts that are underpinning it; the 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. So I think that's what will help bring what is a high single-digit multiple down, and that's coming primarily from that expansion. There are some synergies associated with storage and I'll let others talk about some of that.

So just taking a step back, a couple of things. One, the system really integrates well on a last-mile basis, it goes through Houston all the way down into the Corpus corridor. So we see the demand profile there is very strong. It does bring an element of incremental low-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, these assets touch our existing storage in ways that we can unlock certain value that an independent buyer by itself cannot. So those are the three primary drivers. And once again, it just makes good map sense, and it fits really well.

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

Yes, the lump sum gets recognized in the first quarter. And I think this is just a great job by our terminals team: we have the termination, they have gone out and they have backfilled all these tanks. All these tanks are backfilled on a long-term basis. Some customers 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. With respect to that contract that was bought out, I think there is a little over a year remaining on that contract.

Through first quarter of '28.

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

I wouldn't say that it drives expansion for the project because I don't think the overall demand necessarily is changing in California significantly. What I think the global situation does is highlight the fact that California has to import some of its supply and that makes it subject to variability in global markets. So 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 California refining capacity. As you know, that refining capacity has decreased as a number of refineries have shut. So I think it's a great solution, for California and for Arizona to be able to access domestic supply as opposed to having to be reliant on the international market.

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

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, our docks have been really busy. Our export docks have been very busy, and so record volumes across that. We do get a small amount of ancillary revenue resulting from those movements. But our tanks are sold on long-term take-away contracts with monthly warehousing charges. 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.

I wanted to ask you a little bit about the GCS expansion and at the same time, the Trident pipeline. 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. I'm trying to understand if that might lead to some dislocation in pricing as we understand between Houston Ship Channel, Katy or Agua Dulce, how are you thinking about these localized gas markets as more gas from the Permian starts to pour in over there and the egress might take a little more time?

Okay, Manav. That was a two-part question. Both projects are on track and moving forward. In terms of basis dislocation, I generally try and stay away from commenting on forward-looking pricing. But at a fundamental level, there are always going to be dislocations as you look forward, when you have demand coming on separately and then the supply getting across, and it goes in both directions. So is that a possibility? Yes. There's also a lot of power demand that we're seeing coming up in Texas. We're talking about 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 draw your own conclusions from that commentary.

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

So perfect. That power comment is very helpful. My quick follow-up here: KMI is somewhat unique. You have natural 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. Can you talk a little bit about the natural gas storage opportunities in your portfolio?

Very good question. As we see this demand coming on and the scale of this demand, one of the big differentiators — and Rich alluded to this — is storage. Storage is going to be a key differentiator for us. We have those expansions on site that we're working on, especially Bear Creek, not yet commercialized, but it's something we're working on. We're looking at storage across our footprint, not only to be able to leverage 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 gas into storage and also pull out storage on a pretty quick basis is going to be critical for their operations. 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.

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 the Monument deal and Western Gateway. 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 Monument. 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?

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

Mike, just to clarify one thing: we're buying the Monument pipeline, not Momentum.

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?

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

Sorry, I meant 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 is it more of a downstream constraint?

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

I wanted to follow up on Western Gateway and how you're thinking about the project. First, confirm you'd be contributing the East line of SFPP — the line from El Paso to Phoenix — to the JV. And then on returns, do you look at it as 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?

It's not the whole SFPP system. It is what we call the East line, which goes from El Paso to Phoenix, and the West line, which moves product from California to Phoenix — though, to be precise, it's the portion we're contributing. There are additional SFPP assets in California that will not be contributed. With respect to returns, 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. We look at it on an incremental return on our capital based on an IRR. So it's not just what is the year 1 cash-on-cash; we look at a full project IRR.

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

The Waha-Houston Ship Channel spread does have some modest benefit for us, but our preference and practice has been to sell transportation capacity to our customers on a long-term basis. Generally about winter storms: you have a peak in demand and therefore, the services that we provide for our customers increase in value. Whether that's storage services or transportation services, when you get increases in demand, high volatility and a system that's running at the high utilizations that we talked about, that just creates opportunity for us. So I think that's what you're seeing in the first quarter results.

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 the other key geographies or sizes to expect?

I can describe it generically. We don't give full detail because most of these are competitive situations and we don't want to cause competitive harm before things are tied down. But in general, beyond the backlog there's a lot of power-driven opportunity and some LNG, a bit of industrial, and it goes across the entire Southern United States. So there are opportunities from Arizona all the way to Florida.

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

That's very helpful color. Are you seeing any signs of volume changes on your system in response to higher commodity prices, either from a gathering & processing or refined products perspective?

Refined products in the quarter are down a little bit, but we don't think that is a function of higher prices. We haven't seen higher prices noticeably affect consumer demand to date, but we'll continue to watch. On the G&P side, volumes were up nicely in the quarter — up 15% — and our KinderHawk volumes in the Haynesville were up 34%. Our crude gathering is primarily in the Bakken and it's doing okay. Continental dropped rigs earlier this year, but prices are better, and at some point producers may increase rigs, but we have not seen that yet.

Just wanted to come back to tracking more than 3% above budget. How much of that is one-time in nature versus recurring? If we're thinking about 2027 go-forward, how much of that 3% should we think of as recurring next year versus one-time?

With respect to the buyout on terminals, that's somewhat one-time in nature. The balance depends on commodity prices and weather. On the margin, we do get some benefit from commodity prices and good winter weather. So volumes in CO2 are up and RNG did better. Products is stable and doing well. The base business is performing very well, and then the increased demand, volatility and commodity prices are driving outperformance around the margin.

Got it. And a quick follow-up: we have not heard much conversation on carbon capture in some time. In the marketplace, do you see any demand for that? Or is that mostly gone away at this point?

I would say it's mostly gone away at this point. We're looking at a few things, but it's largely dormant. We have the expertise, and if the opportunity presents itself again and it's economic, we'll look at it.

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

We're about 90% hedged for the balance of this year. Our sensitivity is roughly $3.5 million impact per $1 move in prices. For 2027, we're about 76% hedged, roughly in the high $60s to mid-$60s per barrel area on those hedges. Our near-term approach is to hedge a large majority — generally above 80% for the current year and get to roughly 90% as the year progresses. For year two, we hedge more as we move closer to it. Years three and out, we typically wait to add hedges because parts of our cost structure are driven by commodity price, and we want to match those exposures. So very stable cash flow in the near term with some margin exposure.

And of course, to the extent that we outperform our plan, those percentages are based on planned volumes. To the extent we have a very nice year as far as volumes, we'll sell those into the open market.

I wanted to first go back to Western Gateway. Two clarifying questions: 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 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 getting this project over the finish line?

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 or FID-ed. Regarding the steps to FID, entering into an open season requires a lot of market understanding and was probably one of the harder pieces. Looking forward to executing and getting to FID, there are regulatory aspects, of course, but we have experience in the states involved and confidence in moving that forward.

As you go out with an open season, there's a lot to understand in the market and that was probably the harder piece. As we look forward to executing and getting to FID, we have regulatory aspects to address, but we have experience with those regulators and confidence in moving that forward.

Got it. And as you think about future growth and the more constructive outlook for gas demand in the country, thinking back to the Permian pipeline 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 the country, particularly given the competitive position of your asset base?

We approach that project the way we do all of our others, and I don't think there were any specific lessons learned that change our general approach.

When thinking through natural gas demand in the Gulf Coast, how much open capacity do you have on NGPL southbound if you were able to source more gas to that pipe?

We're operating at very high load factors; most of the low-hanging fruit is pretty much off the table. We're looking at expandability and working on a robust opportunity set in both directions. Specific pockets of capacity exist, but I would be surprised if there's significant available capacity in the key areas you need.

That makes sense. On KinderHawk, volumes continue to perform well. Have you brought on a portion of that expansion project and what's the cadence for the rest of the year for bringing that capacity on?

We are operating near capacity and the volumes are there. We still haven't brought on the expansion yet, but we plan to 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.

Okay. Thank you all very much.