Third Bridge 专家复盘 Williams 收购 Momentum Midstream 的战略价值与高估值风险

[[00:02:20]]
Looking at Williams' July 2026 announced acquisition of Momentum Midstream, what structural characteristics of the asset package made it strategically attractive to major midstream players, and why might acquiring these assets have been preferable to greenfield development opportunities?

[[00:02:58]]
It's a pending transaction, been discussed by Williams as in pursuit or final stages. Yes. The M6 assets are actually really interesting as a combined gathering/transmission/last mile infrastructure asset. About 4,000 miles of overall pipeline in East Texas and Western Louisiana. Only about 250 miles of that is their NG3 system, which is about 1.65BCF per day, more like a transmission line, although regulatory-wise, it's neither intrastate or interstate. It's more non-jurisdictional gathering and processing. As far as how it's permitted, so it has a lot of footprint in the Haynesville tier 1 and tier 2 acreage, so good acreage on the gathering and processing side, so very attractive, about one billion acres dedicated, although they indicate they have a lot of minimum volume commitments and 140 customers. What's interesting about this asset and possibly why it's attractive to Williams other than footprint synergies, operational synergies for Williams, given that Williams has assets in the Western Louisiana area. The M6 asset really looks more like transmission in terms of how the asset would trade in an M&A transaction, and a little more deeper on that, pure gathering systems typically trade 5-7x EBITDA for overall transaction value. Transmission lately has shown anywhere from 10-12x EBITDA and last mile infrastructure may be a little bit higher because it's got that dedicated market.

I would expect, given this is a wellhead to market asset, given that all three parts of the value chain are connected, I would expect it to trade more like transmission in the 10-12x range, and this one, although the M6 financials are private, you can get a little bit of information about cash flow from its credit applications. It looks like the current transaction with Williams is pegged at a 22-25x multiple. Williams is really banking on renewals given the dedicated last mile infrastructure, the acreage dedication and maybe long-term MVCs and then also a lot of development in the tier 1 and tier 2 acreage and even tier 3 with a forward fundamental price that most players are forecasting of USD 3.75-4 in the long term, so pretty attractive asset, a little different and really fills the gap for Williams in that they don't have anything in East Texas, but I'll stop there.

[[00:06:45]]
Considering what appears to be an inflated purchase price – how should we interpret this multiple? Given that transmission assets typically trade at 10-12x EBITDA, and this transaction is looking like 22x, is it common to overpay when you already hold an existing stake in a given asset, or does this suggest more around Williams conviction?

[[00:07:22]]
Yes. The one thing that's different a little bit about this system is that it's already built and it's got large acreage dedications, and so you don't have the build risk associated with a non-jurisdictional asset. What I mean by that is non-jurisdictional from a permitting perspective, that's really gathering and processing as opposed to intrastate or interstate that have the power of eminent domain and have condemnation authority, so building with a gathering and processing regulatory footprint, there's some risk in securing right away, and the way that you overcome that because you don't have condemnation authority or in Louisiana known as expropriation is by paying a lot for right of way, and so that increases your build cost. For a lot of this, especially the big trunkline NG3, that's really been overcome. I would point to that as far as offering something compelling on purchase price for Williams is that the build risk is, to a large degree for the mainline has been taken care of, although there's still that risk out in the gathering lines. The other part that I would point to for Williams is it's got the direct connectivity. They report 10 LNG facilities that it's connected to 26 power plants with direct connections and 34 industrials, and so what that means from an M&A perspective or points towards is that when looking at the economics, the terminal value associated with the economics has a lot more certainty associated with it with that direct connection.

It's harder for another party to come in with capital recovery on new build economics, and so all of that, really, those two factors really allow there to be higher than a 10-12x multiple on the transaction, although really still to be seen whether if the private financials from the credit reports are right, that there's about USD 225m-250m of EBITDA on these assets, then it's to be seen whether the 22-25x that the Williams offer at USD 5.5bn is really purported to be is really too much. That's to be seen. We don't really have an indicator about how the market feels about this on the day of the announcement, the Williams stock price fell that day, but the general midstream's end market fell that day as well, so to be seen how shareholders feel about this.

[[00:10:41]]
Are there any key assumptions that you think major midstream companies tend to get wrong when acquiring smaller assets? Is there anything often overlooked regarding asset quality that you think we should keep an eye on?

[[00:11:08]]
We haven't spoken to it much yet, but one of the key assumptions is going to be operational field, operations synergies and quantifying that and then G&A synergies, so corporate synergies I haven't seen what Williams is saying for the actual synergistic value attributable to the transaction. To your question as to what companies can sometimes get wrong, those key assumptions are critical in this and sometimes difficult to achieve. Yes, companies sometimes get those wrong as well.

[[00:11:56]]
You mentioned that this fills a gap in Williams' East Texas portfolio. Could you elaborate on the value that actually adds for Williams, and perhaps what specific gaps it covers within the company's existing portfolio?

[[00:12:17]]
Yes. Williams really sees the Haynesville as one of actually the production basin that has the most growth in their fundamental forecast in their investor presentation, etc. Really, Williams is, they're showing Haynesville as 7% annual growth as opposed to the Northeast, which is takeaway constrained at 3-4% and Permian at 4%. Williams Book is really seeing this gas play in the Haynesville as a really key basin to move forward in. With that, they don't have anything in East Texas, as I talked about, a lot of the tier 1 acreage is in East Texas, and so when we look at Cattle County, Panola, Sabine, San Augustine, those sort of counties, Shelby that are very prolific in the Western Haynesville, but our tier 1 acreage, any given tier 1 well can have initial production volumes anywhere from 25 million to 35 million standard cubic feet per day. It's a very prolific area in terms of volume and something that Williams is key to capture in addition to what they have in Western Louisiana.

[[00:14:05]]
As you've mentioned, the footprint also provides exposure to a pure-play natural gas basin rather than just associated gas production tied to oil economics in the Permian. How does this distinction impact volume stability, producer behaviour and the actual structure of commercial contracts compared to operators with greater exposure to associated gas in the Permian?

[[00:15:00]]
Yes. Yes, that's an interesting question because on its face, you would look at a pure natural gas play production area like the Haynesville. You would say that given that there's no crude oil, it's not associated gas, pure spot price is an issue. It is going to be an issue. Pure spot price for natural gas is going to be an issue, and that's going to be key for volumes. If you look quite a bit deeper underneath that currently, so if we look at tier 1 acreage being breakeven price USD 2.50 and less, tier 2 acreage, USD 3.50 and less. That's really about development costs, finding and development cost, and so as natural gas price decreases, the amount of development in those key acreage areas, of course, tier 3 is the first to fall off at USD 3.75 plus followed by tier 2, followed by tier 1, and so that really presents a risk for a gathering company that's really focused on the Haynesville for future development. One might say, "Well, that's future development, and you'll still have the base volumes, the base production volumes out there." There just won't be that growth wedge at depressed prices. That's true, but the problem with that scenario is that a typical Haynesville well, especially a tier 1 well, after the first year, its production decline from initial production to the end of the first year can be 60-75% on a given well. That's a significant volume decrease.

A player's really got to take that into account, and so what do most fundamental houses feel the forward environment looks like in comparison to that. From what I've seen, most of the fundamental houses have a forward view that gas on the Gulf Coast is going to be relatively short. Most consultants fundamental houses were at the USD 4 planning price range, given that there's going to be a gas short as more LNG comes on, more data centre load, etc, power gen. I'll stop there.

[[00:17:48]]
You mentioned pure spot price is going to be an issue. Can you elaborate on that, and why do you feel that way?

[[00:17:58]]
Yes, in order for these systems to… Your scenario about natural gas price falling, if natural gas prices fall and a lot of new contracts today have minimum volume commitments, that means that producers may be falling below their minimum volume commitments, and so when you're in a gassy basin like this, where there's spot price risk associated with midstream parties forward view on volumes, that makes credit of shippers become really critical. Balance sheet analysis, credit rating of producers ends up being a really key part of looking at the asset. It looks like there's a lot of minimum volume commitment risk here, I'm sorry, minimum volume contracts here, although they do purport M6 that there's over one million acres dedicated. Legacy contracts are typically acreage dedications in this area, older contracts, although some modern contracts do have a combination of acreage dedication and minimum volume commitments, so all of that really underlies the cash flow worthiness of the asset. You talked about multi-basin players and producers. The other thing that that brings up fundamentally is multi-basin players, and so what I mean there is producers that have the ability to move capital depending on economics and forward view of pricing between oily plays, which have associated gas and then pure gas plays. If we look at the Haynesville and the multi-player producers, we've got expand who's got portfolio choices in the Northeast.

We've got BPX, which has got portfolio choices in the Eagle Ford and Permian, a little bit with ExxonMobil, and so there are multi-basin players. I think the trouble is that given that a lot of this is private at this point. We're not sure how much of the dedications, the minimum volume commitments come from multi-basin players vs pure players like Comstock and Aethon. That's to be borne out in the future. Players such as Comstock and Aethon, they've been carrying quite a few rigs and deploying capital and things like that, but that's another consideration for this asset. All we know on that today, those of us that haven't been in the data room and etc, is that they have 140 customers. They purport 140 customers on the asset. They seem to have some diversity there, but all back to, again, credit risk, MVC gas price environment and then your forward view in looking at gas price environment.

[[00:21:36]]
What would you want to see in terms of the balance of MVC [minimum volume commitment] contracts relative to acreage dedications? You noted the existing legacy contracts. Assuming those are renewed over the next few years and this exposure to the spot price, as a general rule of thumb, what percentage of the EBITDA exposure would you want to have tied to MVC vs acreage dedications?

[[00:22:22]]
As a midstream player as a rule, you generally want to see as much MVC percentage as possible. That really reduces the risk underneath cash flows. As a rule, generally midstream companies are going to want to show as high as close to 100% as they can typically get. Again, I mentioned in the Haynesville, there are contracts out there in the market that are a combination of acreage dedication and MVC. Those actually are even better because with an acreage dedication, if the spot price turns out to be higher than producers really believe in their fundamental planning deck, there's an upside associated with that dedication and more volume and more rig count and that sort of thing, and so the midstream player can capture that as well. You want to see as close to 100% MVC as possible to eliminate the risk, but that acreage dedication is a nice bonus on top of it since there's a combo dedication in the Haynesville today. The pure acreage dedication tends to be really today with a player that has a policy against MVCs or is able to parlay their position with multiple midstream players or it's so very competitive in that way or it's an older legacy contract with acreage dedication.

[[00:24:05]]
Is there a figure you're comfortable with where you're not directly tied to spot pricing, but if the MVC drops below 90%, you'd be a bit more concerned? Generally speaking, is there a threshold you view as dividing a risk-on from a risk-off position?

[[00:24:30]]
You want to see as much as possible, as I mentioned, but most midstream companies that are public that show their MVC percentage, you're going to want to see something that's over 60-70%. The key here as we talk about Williams is what does Williams, is it accretive to Williams in terms of overall MVC position as a percent of capacity or revenue, and that's really the key for this as a private asset, we're not really sure what percent of the asset is underpinned vs MVC. It's been a while since I've looked at Williams MVC percentage, and so take this with a grain of salt, but I think Williams is in the 60% range of MVC, but don't hold me to that. It needs to be accretive to an operator's position. This is a very material transaction to Williams at USD 5.5bn, so a major asset. I would think that's a really key point as to how it stands on an MVC vs its overall portfolio.

[[00:25:54]]
How much of the premium we're seeing do you think is tied to Momentum having connectivity to both producers and end markets, such as LNG [liquefied natural gas] and industrial customers? Given that historical valuations are around 10-12x EBITDA, is there a specific premium you would associate with controlling the full chain from producer to industrial customer?

[[00:26:25]]
That's an interesting question. There aren't many assets out there that have the full value chain that have been on the market that are gathering and processing, so wellhead connected that have transmission downstream of that and then have last mile connectivity all in one package that is a measurable discrete package. We don't have the transactions that have been full wellhead to market are relatively few recently. We don't have a lot of empirical data on that. If I were to attribute a multiple just for, in my opinion, that would be a value chain impact, which, again, shows that there will be higher renewal on overall transmission contracts typically 10 years, although some LNG players go for longer-term contracts like 20 years from time to time. What it does is bolster the confidence that there's going to be renewals that there's going to be increased volume from those players. I would think it's less than 4x, in my opinion, 4x EBITDA premium with that source of value alone outside of operational synergy source of value outside of G&A sources of value and others. Just a few multiples, I would say, on that premium as it relates to affecting the terminal value and then the growth wedge of the asset.

[[00:28:23]]
Could you give us your view on what the key drivers are today for contract duration and renewal risk?

[[00:28:48]]
Yes. Each of the components of the value chain tend to be a little bit different, and that's really about… I say that because of market, market of those players, new transmission, although the NG3 asset is gathering and processing from a regulatory standpoint, it looks a little bit like an intrastate system in terms of market and players, producers there and industrials, they're typically in a 10-year contracting. Again, this information is private with M6, but in terms of general market, that's about a 10-year scenario. LNG customers, to the degree they're actual shippers instead of just a market where they're doing in purchase and sale agreements of gas at the inlet to their facility instead of being a shipper, they can be as high as 20 years. With good credit, midstream companies are willing to do those 20-year contracts with LNG customers. Those typically are looked at as long-term contracts. The variable on the term side is really the gathering and processing side. To the degree they have any legacy contracts on the Texas side, those can be shorter term if they're older or low remaining term. I would think the newer contracts on the gathering and processing side tend to be in the 5-10-year range or if they're not pure acreage dedication.

I think a player looking at this is really looking at the chance of renewal by producers that are listed in the data room that have long-term contracts by marketers and then by industrials and lastly, by LNG. It's really a view of long-term renewal of all of the above, given what they learn in the data room associated with the length of those contracts.

[[00:31:16]]
How should we think about the value of direct connectivity to LNG facilities such as Gillis vs traditional hub delivery, particularly in terms of pricing power, contract quality and cash flow durability?

[[00:31:43]]
Your question, it relates to the attractiveness for an LNG player in this area vs taking gas from the Permian. Is that what you're getting at?

[[00:31:54]]
No, how should we be thinking about the value of the connectivity to LNG facilities such as Gillis, so the connectivity to LNG facilities vs traditional hub deliveries in terms of pricing power.

[[00:32:13]]
I think a couple of things when it comes to pricing power. I think about connectivity and then I also think about source of gas, if you don't mind going into that. I've already spoken to the last mile infrastructure means a lot in terms of value chain, I guess, value, the chance of those contracts staying on… When they get to term, when they get to full term, the chance of the LNG player or industrial renewing is higher because a new player is going to have to get in there and compete with inflated future value capital recovery. The capital of new infrastructure is going to be higher in the future due to inflationary forces, steel prices, escalation in right-of-way costs over time, and so that barrier becomes higher over time. While we've already spoken to that last mile infrastructure and direct connectivity really does mean something in terms of renewal and making sure those cash flows stay on that Midstream asset. The other thing that I think is important to think about is the actual price of gas and how it makes that LNG player competitive related to its peers, and as you look and there's many things that relate to an LNG facility competitiveness as we know, and price of gas is not just it.

As we look to your question, just that source of value, those that are taking gas from Waha, for example, in Texas and transporting it on Permian takeaway systems, we've got to remember what that looks like, which is a transportation cost of anywhere between USD 0.50 and USD 0.70 per dekatherm. We've got that big disconnect sometimes between Waha pricing and Henry Hub, so every 1.5 years, roughly, roughly or less, even one year sometimes that Waha pricing, it really trades at a discount as an associated gas basin and the natural gas takeaway systems get constrained and new infrastructure needs to come on. We've seen Waha gas prices, as you know, go negative. Then on top of that, there's a transportation cost to pay, and a larger one than in the Haynesville, which we'll cover in one second. We've got to remember that cost of gas can be really at a discount to Henry Hub. As we contrast it to Haynesville, it's going to trade roughly flat to Henry Hub on the long-term view. It's got a USD 0.25-0.30 roughly, roughly transportation fee out in the market. The transportation fee is less, but the absolute price of gas in this area in the Haynesville is much, much closer to actual Hub price. I would give the cost of gas analysis really in terms of connectivity over to those that are connected to the Permian.

[[00:36:15]]
Could you elaborate on the downside risk with MVCs in a scenario where gas prices fall below USD 2.50? You mentioned the importance of the balance sheet earlier for some of the shippers and producers, but how are these contracts typically structured if we don't see any tier 2 or 3 production for an extended period? What actually happens on the contracting side if pricing were to drop for a prolonged period?

[[00:36:50]]
Yes. If in the scenario that the fundamental view of most fundamental houses at USD 3.75-4 is not the case, and we're in a low price environment, what we really see in this area and have seen in the past is a rig pullback, and so that relates to the growth wedge of development in the Haynesville, and so what we've talked about is because the Haynesville wells are such high pressure with such high initial declines, and we've talked about after the first year, the well is producing 60-75% of its initial production. That means that that base wedge has a high initial decline, much higher than other areas, and so what's key about this is that it can put a given producer or shipper in a shortfall scenario. They're actually not in a take-or-pay contract or a minimum volume commitment, they're actually paying for transportation that they're not using. That's all back to the credit rating of the shipper, the creditworthiness of the shipper, balance sheet analysis, etc, and so there's a lot of time by an acquirer really spent looking at that. Again, I stress that most fundamental houses are in the USD 3.75 range in the forward environment. We can go into, why that is, if you like, but at least the view is that natural gas is going to be short on the Gulf Coast, and so we're in a good place here relative to your question.

[[00:38:49]]
To what extent could a midstream operator such as Williams protect its margins and cash flows during cyclical downturns? When we see the latter effect of reduced rig counts, what could midstream operators do to protect margins?

[[00:39:21]]
This credit assurance typically, depending on the shipper, midstream providers will put in place parent guarantees, typically, if the shipper is investment grade, so BBB and above, they'll put in parent guarantees or accept parent guarantees. Below that, if there are any smaller producers that are not rated investment grade, they can put in place letters of credit, and in the case of a minimum volume commitment and the producer is not able to cover it, you've got that draw on a letter of credit that a midstream party can really draw on. The issue associated with the letter of credit is the letter of credit production, degree of insurance or assurance is that they don't last very long typically. They're typically for a number of months, reservation fees, so anywhere from, I'd say six months would be the average, but I would say one year and less would be the range of reservation fees. If you're in that depressed price environment, for example, where a producer or shipper is below their minimum volume commitment and there's a shortfall, you're really only covered for a matter of months. If it's longer than that six months for interstate pipeline, sometimes three months period, that's where there's risk for the midstream party, but those are the main mitigations. The other thing that midstream companies do a lot of is, is to the degree they're working with a producer as a shipper rather than an industrial is really assessing the acreage.

All of us has midstream professionals. We have geologists and production engineers that typically work for us that are helping assess the value or what the acreage looks like from an E&P perspective relative to others. There is a lot of that that goes on, not just on an acreage dedication contract only, but even on MVCs because as I mentioned, the long-term value is about the productivity and potential of the acreage and seeing that being robust in a wide variety of price environments as possible given that the mitigations I mentioned from shippers are relatively short term?

[[00:42:24]]
Could you elaborate on the consensus view that gas will be in the USD 3.75 range? What's driving that? What are the key downside risks we should monitor to signal whether those assumptions are fair?

[[00:42:49]]
That has to do a bit with fundamental house view of supply and demand in the US and so if we turn to supply first, the range at least that I've seen of in the next five-year period to early 2031. We've got Haynesville growth ranging anywhere from 5BCF per day to 7BCF per day. The Permian growth for natural gas, it really seems to vary based on the position of the midstream party that I've seen doing that forecast. In other words, are they more gas focused or are they more liquids focused. I've seen that range go 5-8BCF per day in the Permian. Then on the demand side, we've got the new LNG coming on ranging anywhere from 13-18BCF per day in that period combined with power generation demand, power gen demand, including data centres within that, ranging anywhere from 4-6BCF per day as well. It really looks like the industry is forecasting a supply shortage. We're sitting at gas prices of USD 2.90 today. In the forward view, parties are really seeing that short come on, and so natural gas will go a bit more of a premium, and so that long-term view of… It used to be the consensus view more like USD 4, but now lately, they've been tapering down to USD 3.75, so that's the supply-demand balance is the reason for that.

[[00:45:07]]
When you merge two large-scale midstream systems within the same basin, where do you see the most immediate tangible operational integration opportunities within the first 12-18 months? Alternatively what do you think is typically overly optimistic when we think about midstream companies targeting particular synergies within the first 1-2 years?

[[00:45:46]]
To the latter part of your question about overly optimistic, the one to watch is what Williams declares as a G&A or corporate synergy. That one will be key to bear out and is sometimes overestimated. The quickest ones to the former part of your question would be field operation synergies. The NG3 system and the Louisiana Energy Gateway system have a lot of overlap, and so when it gets to field operations, line encroachment monitoring, things like that that the personnel do in the field, there's some consolidation synergies there. Most of the mileage is actually over in the gathering systems. M6 has 4,000 miles of pipeline total and only 250 miles are on the NG3 system. Williams has a gathering system there, and so a lot of that, too, can be operational synergy associated with measurement technicians and the various wellhead metering systems that are out on the gathering systems. There's going to be a lot of them on 4,000 miles of pipeline from M6 and then Williams has got about 590 miles of gathering out there. That's going to be, to your question about synergies, field operations, encroachment staff, measurement techs, compression tech. A lot of that is going to be the stuff that's deliverable in the first 12-18 months. There's got to be some commercial synergies in terms of more… This could be viewed as G&A, but they've got to have some customers in common.

This is going to be a small source of value, relatively small, but the number of commercial representatives that are facing the individual producers, those may be consolidated to some degree. It's not a big number, but you can see that. Those are the synergies that most people look to. The one that I don't think has been spoken to for Williams, and I think there's a potential here is a hydraulic consolidation of the gathering systems. In other words, there are two distinct systems today hydraulically and they're owned by different entities. Being able in a similar area to the degree there's overlap in Western Louisiana, again, there's not going to be that overlap in footprint in East Texas. In Western Louisiana, what kind of capacity can be unlocked from a consolidation of those systems to the degree that their maximum allowable operating pressures are consistent. That's something that, from a capacity standpoint, may have been factored in by Williams with this. We don't know, and the reason that's important and the reason I bring it up is with regard to ongoing cash flow, ongoing capital spend, that is one of the largest areas of capital spend as you're looking at growth capital, maintenance capital, that sort of thing. We've talked before in this call about the initial production fall-off in the first year.

Really to keep volumes up and keep up with the drill bit, that takes a lot of gathering capital in new well connects, gathering lines, sometimes compression, and so that's going to be a key factor, and so the question is there with the consolidation of the systems between Williams and M6, do they minimise somehow the amount of gathering capital that needs to be put in for what is really the growth wedge on production volumes, but really, in some cases, just keeps up offset with decline. That may be a source of value that from the outside, we don't understand about Williams bid in this pursuit.

[[00:50:35]]
When we think about M6 and how old those assets are, how are you thinking about expected maintenance capital vs growth capital as you integrate the system? Is there additional sustaining CAPEX we need to consider in today's environment?

[[00:51:10]]
In my experience in looking at these systems, the amount of pure maintenance CAPEX, so I'm talking about compression, maintenance to the degree there's that there's turbine compression on the larger transmission systems, that's going to be relatively small relative to what I mentioned, which is the capital associated with keeping up with the drill bit. Compression, putting in new compression and maintenance of reciprocating compression that's on the gathering systems. I would say that's going to be relatively small. Haynesville wells, at least new ones tend to be relatively high pressure in comparison to other gathering systems. At least for me, again, not having been in the data room, not seeing the data, in my experience, I would estimate that those sources of maintenance capital would pale in comparison to the amount of capital that it takes to keep up with their producers' drilling programmes and laying gathering lines out to new wells, which, in a sense, is growth capital, but in a sense, the way gathering systems work and with this really steep decline on Haynesville wells in the first year or so, in a way, that can be viewed as maintenance capital, at least maintenance in the sense of keeping up existing volumes where they are, maintaining existing volumes where they are, even though classically, that's classified as growth capital because you're laying out to new wells.

In a way, a lot of this is offsetting base decline, so that's really the source of capital that would be on my mind with these assets and as the most significant and potentially with the combination of the two systems, one that Williams can mitigate by the combination of the systems hydraulically where M6 cannot on their own.

[[00:53:42]]
In your view, should you pay more attention to the capital spent on keeping up with the drill bit, rather than a particular portion of the asset base being lower quality than expected – where higher maintenance CAPEX is just a drop in the bucket, so to speak?

[[00:54:04]]
Yes. You want to tune up your assumptions on all of the above, but in terms of materiality, new gathering lines are going to be the highest capital need in this area. Outside of a line looping future expansion of NG3 or the LEG system, outside of something like that, just typical, the materiality of capital spend is going to be on keeping up with your producer dedications and their drill bit.

[[00:54:44]]
With the emerging narrative around AI data centres and hyperscaler power demand, how real do you think that opportunity is for pure-play midstream companies such as Williams or Momentum, compared to a full-value-chain company such as Chevron? Given that Chevron is partnering on a 2.7GW project and can both produce gas and provide direct connectivity to the data centre, is that opportunity fading for midstream pure plays, or is it still a genuine growth driver?

[[00:55:38]]
For midstream players, the AI data centre opportunity is all about the location of the midstream asset, and so starting with the fundamentals, we talked about earlier the size of the price or growth on the demand with LNG ranges anywhere from 13-18BCF per day in the next five years or so, and relative to that, in comparison to that, the range for AI data centre behind-the-meter power generation, natural gas-fired generation associated with data centres, that range, at least from what I've seen, tends to range anywhere from 3-6BCF per day in that same five-year time period. It's a smaller price. Then given that data centres are chosen based on many criteria, land availability and price, the ability for there to be nearby water, cooling, nearby gas and the price of that gas or grid connectivity, ease of grid connectivity, those would be some of the factors for where a data centre is chosen to be placed. When we look at that part of the element of demand and where those data centres are going to be from the information that I've seen, most data centre projects in the nation are really planned to the highest number in a given state are planned to be in Texas.

Then as we look to what other states, Virginia trails Texas, but actually in terms of natural gas demand for those projects, at least what is known as we look at hyperscaler announcements and things like that, the amount of gas volume utilisation is forecasted in Virginia in that period for projects is about half, a little more than half that which is forecasted to be in Texas, and so we're not to Louisiana yet, although the Momentum assets, they have a significant amount of E&P, G&P on the Texas side. A lot of their industrial connectivity, more of it, in my understanding is on the Louisiana side. We're really, to this question, looking at the Louisiana side and at least at this point. As we look to what States have, at least in terms of announcements today, the highest apportionment of data centre after Texas and Virginia, we look at Georgia, Utah, Pennsylvania, Arizona in that order being the most prolific. Then we don't get to Louisiana until 12 on that list, and so at least as far as what we know today, although there have been some major announcements in Louisiana, partnerships between Entergy and Amazon and Meta and that sort of thing.

There have been some big announcements in Louisiana, but it looks like at this stage, Louisiana really trails on that list, and so looking at a price of 3-6BCF per day over a five-year period compared to LNG that's in that immediate area, it really looks like the source of value that we're talking about here in terms of demand is, it could be much smaller on the Louisiana side of the equation. The Texas side of the equation is a little bit to be seen. A lot of the data centre activity have been a lot more in the western part of the state and then the northern part of the state, although there… As we look at the Momentum asset in East Texas from Carthage and going south, there's been some data centre announcement activity out that direction, but just not a lot. I would say some source of value and growth, but not as significant as other sources of value attributable to the transaction.

[[01:00:27]]
Given the potential consolidation – if we continue to see it across the midstream space in the Haynesville – does this create greater pricing power for midstream providers? Or do you think competition for LNG, as you pointed to, keeps negotiating leverage primarily with the producers?

[[01:00:55]]
Yes. There are still a lot of players in gathering and processing and transmission in this area. We still have KMI, DT Midstream, Energy Transfer, ONEOK enterprise, Aethon has got their own midstream out there, Expand has got their own midstream out there. We've got TransCanada or TC Energy, sorry. Then we still have private equity players out there as well. We've got WhiteWater, Clearfork, Voyager, Trace, Align, so there are quite a few players out there, and so producers really have a lot of choices depending on where those systems are relative to their footprint. I'm not really seeing that as a material impact just for this one transaction, given there's a lot of variety out there in the midstream space in this area.

[[01:01:58]]
I'm going to leave it there, but I just want to say thank you so much for joining me and sharing your insights on Momentum Midstream as well as the broader space.

[[01:02:12]]
Thank you. Appreciate you very much.

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