And this earnings season highlighted a maturing industry: consolidating into a single hub, bearing more fixed costs to reduce risk, and closing the door on projects that are no longer viable. It’s also one still prone to provocative — perhaps outlandish — goals and regional price dislocations.

No one wants to hire an oil and gas executive outside Houston

The consolidation of the US oil and gas industry into Houston-based companies dates back decades, but after supermajors ExxonMobil and Chevron moved their headquarters to Houston in 2023 and 2024, respectively, the trend is only accelerating. This earnings season, Devon announced its acquisition of Coterra and concomitant move to Houston, and a week later, Expand announced its own move to Houston.1

In regional-economy terms, Houston is becoming much more like Los Angeles than it is Dallas or Chicago or Atlanta. Which is to say, Houston absolutely attracts a disproportionate share of the top 1% US oil and gas industry talent, just as Los Angeles does in the entertainment industry. For a market leader like Diamondback, with a strong executive team in place, there’s no urgent need to move. But for smaller companies trying to make the leap to big-time, they have a better chance of making the key hires to do that in the place those people disproportionately live. I expect continued relocation — whether organically or inorganically — of public E&Ps headquartered in Denver, Midland, or Oklahoma City.

LNG projects are being canceled instead of remaining on life support

After Energy Transfer officially suspended development of its Lake Charles LNG facility in December, Sempra announced this earnings season that it had terminated the development agreement for Vista Pacifico LNG. Many proposed US LNG projects are going nowhere but have not yet been formally canceled. These two cases are interesting because the developers opted to formally pull the plug.

Perhaps the formal cancellations reflect these developers’ size and backlog depth. But usually, there’s more of an angle than that. For Energy Transfer, perhaps it’s that the economics of Lower-48 pipeline development are so much better than for US Gulf Coast liquefaction; for Sempra, perhaps about the regulatory climate for pipeline development through central Mexico.

Venture Global’s FT pivot

With its first two LNG projects, Venture Global took a minimalist approach to pipeline contracting, focusing on securing sufficient feedgas liquidity. In contrast, Cheniere contracts for pipeline capacity to multiple basins. After this strategy led to Plaquemines’ in-service bidding TGP 500L prices to as much as a $0.50/MMBtu premium to Henry Hub, Venture Global pivoted. For CP2, Venture Global is making two large investments to source Permian gas supplies:

• spending more than $1 billion to develop large-scale nitrogen removal units

• developing CP Express, partnering with WhiteWater to develop Blackfin, and contracting for 2 Bcfd of Permian capacity, presumably on Eiger Express

Contracting further upstream was clearly the right decision for a player of Venture Global’s size. However, Permian associated gas growth is likely to fall well short of takeaway capacity additions, narrowing Waha differentials sharply. Paying a levelized ~$1.25/MMBtu for the FT and NRU may end up much more expensive than committing to ~$1.50-1.75/MMBtu in FT to move gas from much weaker Appalachian hubs.

A $0.20/MMBtu improvement in price realizations?!

In the same press release announcing its move to Houston, Expand’s former CEO Nick Del’Osso “stepped down,” with board chairman Michael Wichterich appointed interim CEO. On Expand’s earnings call the next week, Wichterich announced a target of improving price realizations by $0.20/MMBtu. Analysts pressed for details, and Wichterich reiterated the target but offered few specifics.

Typical third-party marketing margins are a penny or two, so $0.20/MMBtu requires much more than insourcing. In a market that’s been deregulated for more than 30 years, there aren’t any free lunches — improving realizations more than a couple cents entails taking more risk, typically in the form of FT commitments or reduced hedging.

EQT’s approach was to own its wellhead gathering. This lets EQT shut in without the burden of fixed gathering commitments, and therefore hedge less, avoiding the vig paid to market-makers. But with Transco alone likely worth more than Expand, Expand can’t run the EQT play.2

Bigger picture, I don’t buy the construct of improving realizations by $X/MMBtu, regardless of what X is. On EQT’s earnings call, the company detailed its strategic decision to sell all of its February volumes at bidweek rather than take exposure into the month, based on its view that fundamentals did not support such strong futures prices. But EQT rightly did not extend this thinking to a promise of continued outsize realizations. Expand’s goal may be a headwind as it tries to staff up its marketing team, and the company probably needs to walk it back.

The coming Ohio gas shortfall

I previously wrote about the specific connectivity deficiencies that constrain various western Appalachia takeaway utilization, leaving ~900 MMcfd of spare capacity in aggregate. But across all four pipelines, the overarching issue is that the Utica in Ohio, and to a lesser extent the rich-gas Marcellus, are short inventory relative to the dry-gas Marcellus further east.

Against that backdrop, this earnings season suggests the situation is likely to get worse before it gets better: TC Energy announced that its Columbus Area Project and Crossroads expansion could each add 1.5 Bcfd, while Williams upsized its planned Ohio power projects. I’ll dive into the details in a future post, but the pre-2019 TCO Pool dislocation from other Appalachian hubs looks set to return.

On February 28, US and Israeli forces launched surprise airstrikes on several sites in Iran, killing Supreme Leader Ali Khamenei among other Iranian officials. This attack, along with subsequent Iranian counterstrikes, destabilized the region’s production and especially shipping routes, with attendant impacts on global energy and agricultural markets.

The degree of disruption in global oil and LNG markets, and by extension North American gas markets, depends on when and how the crisis is resolved. But regardless of the ultimate resolution, I’m reevaluating my view that it’s a bad time to be contracting for US LNG. Being an analyst means not just building a forecast but also thinking about how solid its foundations are. I underestimated the likelihood of war in the Middle East; for both LNG-market and oil-market reasons, instability there increases the option value of US LNG.

What are the war’s impacts on LNG markets?

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Figure 1 | Spare western Appalachia takeaway capacity

Getting more Northeast gas into one or more of these pipelines is likely the cheapest and easiest way to grow Appalachian production in the near term. Range looks set to grow ~250 MMcfd into new Rover capacity, and new power plants will likely pull almost as much gas south on TGP. EOG could grow into ~150 MMcfd of unutilized Nexus capacity, but the largest tranche of unutilized takeaway — ~300 MMcfd on Columbia Gulf — does not yet offer a compelling risk-reward for producers.

Columbia Gulf: Spare capacity likely not held by producers

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After no new Permian gas takeaway capacity was sanctioned between mid-2022 and mid-2024, an unprecedented 9.3 Bcfd of Permian gas pipelines took FID between July 2024 and August 2025. Remarkably, operators then upsized these commitments by a further 2 Bcfd in late 2025.

The first ~4.5 Bcfd of this capacity is due online later this year: ~550 MMcfd from a Gulf Coast Express expansion in the second quarter, along with 2.5 and 1.5 Bcfd from Blackcomb and Hugh Brinson pipelines in the fourth quarter. For E&Ps, it can’t come soon enough: gas takeaway capacity in the basin has been consistently constrained since March 2024, with only a brief period of basis relief following Matterhorn Express Pipeline’s in-service in winter 2024-25.

But this buildout is much larger than what would be needed to accommodate today’s Permian activity, or even a realistic high-drilling case. Either E&Ps will target more gas-weighted acreage or intervals, or Permian takeaway capacity will be consistently underutilized.

How does gas production compare to takeaway capacity currently?

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But that assumption is startin…

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If my analysis has been useful, I hope you’ll subscribe. (If you prefer annual billing, email me at amber@measureddepth.com, and I’ll send an invoice.)

For teams of seven or more, I offer an enterprise license — please get in touch for details.

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Building this independent analysis over the last four months has been some of the most fun and rewarding work I’ve done, and I hope it has resonated with you, too.

Amber

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A former colleague texted me last week, amid the disruptions from winter storm Fern, to ask what I thought about freeze-offs. He had heard estimates he thought were too high but was skeptical. My answer to him, and to all of you here now, is that we really don’t know, and we won’t have any idea until we see the storage number for the week ending January 29.

What do we actually know

Let’s start with what we actually can observe in real-time.

Typical Permian gas flows

El Paso, TransWestern, NNG, and NGPL typically move1 ~6.5 TBtu/d, from a combination of direct connections to gathering systems and processing plants (shown in teal) and receipts from intrastate pipelines within the Permian (in pink). Since the final Matterhorn Express compressor station came online, it (in purple) and Whistler (in light blue) usually move ~2.5 TBtu/d to south Texas. Interstate receipts from Enterprise typically total an additional ~0.3 TBtu/d.

Figure 1 | Observable Permian scheduled gas volumes

Reduction in gas flows last week

During winter storm Fern, these typical ~9.4 TBtu/d of flows fell to a low of ~4.9 TBtu/d. As of Monday, February 2, ~22 TBtu of production had been lost in aggregate. I show these flows in Ttu/d rather than converting to MMcfd because, as I'll discuss below, the conversion factor itself is uncertain.

Figure 2 | Recent observable Permian scheduled gas volumes

Historical Permian wellhead production

While the EIA only reports state-level production, operators must report lease- and/or well-level production to state regulatory agencies, for tax purposes. Aggregating this well-level data, then, gives insight into Permian-specific production.

Figure 3 | Reported wellhead Permian gas production

What we don’t know

However, these two data sets are not directly comparable for three reasons: volume versus energy, state reporting lags, and intrastate flows.

How much ethane was extracted

The first challenge in grossing up scrapes to total Permian dry gas production is that the latter is never actually reported. Analysts typically model it using a fixed (or slowly moving) dry-to-wellhead gas ratio, but in reality, the extent of ethane extraction varies with market conditions. In both Texas and New Mexico,2 the EIA’s estimates of dry-to-marketed gas ratios have been trending down over time, but the frequent step-changes between the end of one year and the beginning of the next point to uncertainty even in EIA’s state-level dry gas production estimates.

Figure 4 | Texas and New Mexico dry gas share of marketed gas production

On January 26, gas quality at a range of Permian interstate locations ran about 2% hotter than earlier in the month, as operators extracted less ethane in response to much higher gas prices. For a basin producing ~30 Bcfd at the wellhead, this ethane rejection could offset more than 1 Bcfd of freeze-offs.

How complete state-reported production data is

I’ve built many a well-level production model, and while 95% reporting is more than sufficient to construct an accurate type curve for a given operator, county, or play, it’s nowhere near sufficient for real-time production estimation. In a ~30 Bcfd play, the difference between 94% reporting and 96% reporting is 500 MMcfd — and you have no way of knowing which one you’re looking at. In both Texas and New Mexico, some well- or lease-level reporting trickles in over the course of a year or more after first production.

Figure 5 | EIA and state-reported New Mexico gas production

How observed routes behaved relative to unobservable ones

Two increments of “missing” dry gas production — lease/plant fuel and local consumption — are small and predictable. But most of the gap between wellhead production and interstate nominations is gas that moves on intrastates, which is neither.

All of the post-2018 Permian intrastate pipelines — Gulf Coast Express, Permian Highway, Whistler, and Matterhorn Express — move gas to south Texas. We can reasonably assume that these pipelines’ 9.6 Bcfd of capacity is fully utilized in normal market conditions, given how weak Waha prices have been. The typical ~2.5 TBtu/d of Whistler and Matterhorn deliveries into south Texas therefore accounts for just ~25% of this capacity.

But the freeze-offs in west Texas (and elsewhere) last weekend changed the underlying economics of Permian gas flows. Waha prices traded over Houston Ship Channel, meaning that if anything, the reduction in Permian→south Texas flows on these new intrastates was modest. Given this price signal, it is possible that GCX and PHP shippers made even bigger changes, and that the actual observed deliveries on Matterhorn Express and Whistler constituted more than the typical share of flows — or even all the flows — along this route.

Implications for freeze-off estimates

Given these uncertainties, to estimate freeze-offs, we need to compare the two series we actually know: scheduled interstate pipeline volumes and wellhead gas production. Even putting these two series on the same chart requires an assumption about calorific value, which, in reality, varies over time depending on market conditions.

During winter storm Uri in February 2021, the observable share of Permian wellhead production increased by 1.7 percentage points relative to the surrounding six months, as shown in the gray line in Figure 6. Given that these disruptions lasted only 12 days and were severe for just five, the observable share of wellhead production likely rose 6-8 percentage points during the shut-ins. Conversely, freeze-offs in January 2024 were more evenly distributed, with the observable share of total wellhead production broadly consistent with the surrounding six months.

At the scale of today’s Permian production, whether this storm is more like Uri or like January 2024 cold weather could swing Permian freeze-off estimates by 3-4 Bcfd at peak, and 15-20 Bcf in aggregate. Uncertainty, due to state reporting lags and varying levels of ethane extraction, about what the baseline Permian dry gas production was before the storm widens the possible range by an additional 5-8 Bcf.

Figure 6 | Permian wellhead gas production and pipeline scrapes

In a basin like Appalachia, where more than 95% of gas flows on interstate pipelines, and where higher transportation costs mean ethane extraction doesn’t swing in and out of the money as frequently, pipeline scrapes provide a reliable real-time production estimate, even during market disruptions. In the Permian, though, the combination of slow production reporting, mostly intrastate flows, and significant month-to-month variation in ethane extraction means that scrape-based production models often provide more noise than signal.

This cold front sent gas demand forecasts and Henry Hub prices skyrocketing. As recently as January 16, the February NYMEX futures contract traded at just $3.16/MMBtu. Monday, it closed at $6.52/MMBtu. The dislocations were even larger in the January market, with Henry Hub cash printing ~$28/MMBtu for the January 24-26 weekend package and balance-of-month trading ~$20/MMBtu.

Gas liquefied this weekend would be sold no sooner than February in destination markets. TTF trades at ~€40/MWh for February delivery, equivalent to ~$14/MMBtu. At ~$28/MMBtu, then, US LNG was ~$14/MMBtu underwater on a variable-cost basis.

On Saturday — before the storm disrupted Haynesville production and likely precipitated additional involuntary cuts — feedgas reductions totaled ~3.8 Bcfd, with tollers cutting ~36%, Cheniere ~25%, and Venture Global hardly at all. The financial stakes are significant: I estimate Cheniere could have made as much as $80 million by unwinding its feedgas purchases over the weekend.

When Henry Hub price spikes push US LNG this far out of the money, liquefaction is no longer baseload demand but rather a financial option. But who holds that option — and can exercise it for tens of millions — varies by project.

Who holds the options?

In the first wave of US liquefaction, most projects had a commercial structure similar to an interstate gas pipeline, on which a shipper pays a monthly reservation charge in exchange for access to an increment of capacity. The shipper, though, is responsible for buying (or producing) the gas, scheduling the volumes, and then selling (or consuming) the gas. Freeport, Cameron, Elba, and Cove Point liquefaction contracts are structured similarly: the LNG offtaker pays a monthly reservation charge for access to the liquefaction capacity but is responsible for procuring/shipping the feedgas. These LNG offtakers maintain title to the gas through the value chain.

Cheniere’s projects were structured differently, with Cheniere responsible for feedgas sourcing, pipeline and storage contracting, and pipeline scheduling. Cheniere’s counterparties still pay a reservation charge, but at these projects, that is in exchange for the right to receive FOB LNG. Cheniere, instead, has title to the gas until after it is liquefied. Cheniere’s offtakers also pay 115% of the Henry Hub price for volumes they do lift, to cover losses in pipeline transportation and especially liquefaction.

In that first wave, feedgas procurement and transportation were straightforward for companies like BP (at Freeport) or Shell (at Elba), as these firms are among the largest US gas marketers. Other companies, most significantly Toshiba (at Freeport), underestimated the complexity of US gas marketing and ultimately exited US LNG. Not coincidentally, all second- and third-wave US LNG projects use the FOB model pioneered by Cheniere.1

At Cheniere’s facilities, LNG offtakers must exercise their option by the 20th of the month two prior to when they would receive the cargoes.2 That means offtakers made decisions about January cargoes by November 20, when January TTF traded ~$6/MMBtu over Henry Hub.

So while LNG tollers at Elba, Cove Point, Freeport, and Cameron could sell back gas purchases this weekend in response to changing market conditions, the window for Cheniere’s and Venture Global’s customers has long since passed. In the case of Plaquemines, although its final trains came online in December, the project is still pre-commercial, meaning that Venture Global remains the project’s only offtaker.3

But while Calcasieu Pass, Sabine Pass, and Corpus Christi offtakers no longer hold a January (or February) US LNG option, Cheniere and Venture Global themselves still do. Because their customers only take title to the LNG FOB, Cheniere or Venture Global can serve their customers from LNG storage rather than continuing to liquefy gas. They could then cover this short by fulfilling their own DES sales with ~$14/MMBtu LNG from elsewhere or, in a best-case scenario, by refilling LNG storage with ~$6/MMBtu February gas.

Who’s exercising their options?

By analyzing LNG transportation portfolios and pipeline nomination data, I estimate which US LNG option-holders unwound their gas purchases this weekend. This exercise isn’t completely straightforward — some Freeport and Cameron tollers have overlapping feedgas portfolios; some intrastate pipelines serve Corpus Christi and Freeport; Cove Point Pipeline serves other load besides the liquefaction facility — but nonetheless, the results are directionally informative.

In gas markets, the weekend trades on Friday as a Saturday-Sunday-Monday package. Companies can and do make single-day deals, but typically these reflect operational disruptions, such as cuts due to Haynesville production freeze-offs. On Saturday, before Haynesville production declined sharply, LNG feedgas reductions totaled ~3.8 Bcfd, with tollers (in aggregate) and Cheniere cutting much more aggressively than Venture Global. The latter’s reduction came almost entirely at Plaquemines, where it does not yet have customer obligations.

Figure 1 | January 24 feedgas reductions

As long as upstream cuts on Sunday and Monday were not significant relative to the total feedgas reduction, the financial impact of Cheniere’s operational changes is likely to be material to the company. In 3Q25, the company reported $1.6 billion in adjusted EBITDA, whereas I estimate that Cheniere could have made as much as $80 million by unwinding its feedgas purchases over the weekend and backfilling these sales with $14 LNG. If the company has sufficient storage flexibility to replace these sold volumes with February (or March) Henry Hub gas at $6 (or $4), the impact would rise to ~$140 (or ~$150) million.

Venture Global, in contrast, made much smaller changes, perhaps due to broader corporate considerations. If the company were to change Plaquemines operations in response to market conditions, it may risk jeopardizing its claim that the facility is pre-commercial. In other words, the value of Henry Hub gas resold this weekend was very high, but nowhere near as high as the aggregate value of all pre-commercial Plaquemines cargoes. Shell and Venture Global have been locked in a lengthy legal dispute about when Calcasieu Pass was commercial, and Shell is also a Plaquemines offtaker.

Among tollers, Shell made the biggest change, reducing Elba feedgas to zero. Despite Elba’s small 2.5 MMtpa size, the change could have been worth as much as ~$65 million to Shell, because Transco Zone 5 traded at more than $60/MMBtu this weekend. At Cameron, feedgas reductions varied by pipeline, with the largest cuts on routes where Total holds the most capacity — though differences in upstream freeze-offs may also explain the pattern.

Figure 2 | Estimated LNG option impact on earnings

How long will this last?

At the four tolling facilities, reduced feedgas is likely to last as long as Henry Hub prices stay higher than those for LNG — at least through the end of the month, based on the latest forecasts. If anything, tollers’ feedgas nominations are likely to continue to decline if prices remain high, as operational factors likely limit how quickly and efficiently a liquefaction plant can ramp down. Inasmuch as US LNG tollers have already on-sold their US cargoes, they could instead procure LNG from elsewhere and pocket the difference between Henry Hub and LNG prices. (Of course, reduced US LNG output is likely to bid up February global gas and LNG prices.)

Cheniere’s ability to maintain FOB LNG deliveries to its customers with lower feedgas intake will dwindle quickly through the week. Most of Cheniere’s customers take LNG FOB, so by week’s end, Cheniere likely will need to renegotiate with them — and surely share the value of its now-deeply-in-the-money option. But with ~$6/MMBtu of value at stake and some of the largest LNG marketers as counterparties, unwinding this option is likely to continue accruing profits for Cheniere.

Applying that fra…

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About 10 years ago, I gave a presentation to a large utility’s board, and afterward, one of the directors asked me if I had been doing this for a long time. Thinking about his question crystallized something for me — that I’ve always been an analyst. In kindergarten, I checked the Rangers and Mavericks box scores and standings in the Dallas Morning News every morning.

I’m writing this because methodology matters, especially when markets are noisy and data are incomplete.

Conviction and uncertainty

Although I’ve been an analyst for a long time, a book I read this summer about religion, of all things, helped me articulate how I approach my work as an analyst. In The Road to Wisdom, Francis Collins writes about a web of beliefs, wherein the believer is most sure of (and attached to) the views at the center, but less so to ones further out.

And this resonated with me because I think the core job of being an analyst is deciding when to change your mind: thinking not just about models but about heuristics and how well-suited your tools are to capture changing market dynamics, about where models might not be accurate even though they’re precise, and updating your priors accordingly. Do it too infrequently, and the market passes you by; do it too often, and no one will take you seriously. It’s essential to be transparent not just about your analysis but about how strongly you hold it, which requires both methodological rigor and epistemic humility.

Figure 1 | Views about the gas market

Heuristics versus models

Some analysts — typically older and oil-focused — eschew models, arguing that the job is about more than pressing run and that understanding how companies (and sometimes countries) make decisions matters more. It probably goes without saying that I do not belong to this school. I’m an unabashed model lover, not because they are magic, but because they are tools for rationalizing how disparate pieces fit together, in ways that aren’t obvious when looking at problems in isolation. But I nonetheless think the OPEC-watcher’s critique has some merit.

The most important thing about models is to understand what’s not in them. In the 2010s, our Henry Hub forecasts were wrong because they didn’t account for future breakeven improvements. More broadly, you need to consistently ask yourself not just whether the model’s input data are robust but whether the model’s algorithm needs to change to accommodate new features of the market.

For example, Permian gas pipeline development is accelerating and is likely to outpace the growth in associated gas production. That, in turn, will narrow basis differentials. But what would those narrower basis differentials, in conjunction with higher Henry Hub prices, mean for upstream activity and therefore the pace of production growth? Before you can consider using a model, you need to have a heuristic.

At Wood Mackenzie, I spent 10 years using one linear programming model to forecast North American gas flows and basis differentials; another to forecast global LNG development, flows, and prices; and others to optimize power systems. Next, I went to RS Energy Group, where we had a best-in-class understanding of onshore North America upstream but no long-term activity model, to say nothing of a gas pipeline flow model. While I prefer having those tools, a strong mental model is more important. Because at the end of the day, having a model isn’t about updating the numbers and pressing run — it’s about understanding what the model does and what it doesn’t, and how to rework it as the market changes.

In practice, I can tell you where specific compressor stations are on Transco and TGP, but I can’t rattle off all the regas terminals in Japan. So when I write about sustainable long-term global gas prices, or clearing the medium-term LNG oversupply, I’m using a heuristic rather than detailed dispatch or flow models.

Accuracy versus precision

Sometimes, though, the problem isn’t the heuristic but the availability of data. My econometrics professor told the joke about the econometrician looking for a lost ring under the lamppost, not because that’s where he lost it, but because that’s where the light was. And I think of this often with respect to models of gas production scrapes, whose problems are twofold:

• First, the independent variable is itself unknown: operators report well-level two-stream production to state regulatory agencies, but they do not report three-stream volumes. The EIA reports dry gas production only at the state level, and even then with a three-month lag. In the Permian, wellhead NGL content and ethane extraction both vary widely, meaning no one really knows what gas production was, even historically.

• Second, the relationship between observed and unobserved gas production changes frequently. With scheduled quantity data reported for interstate gas pipelines, you can observe how much production moves onto interstates in real-time. But modeling total gas production from the volume moving onto interstates requires that relationship to be stable, which it is not.

Recently, the in-service of Louisiana Energy Gateway re-routed flows from less-visible intrastates.1 Applying the same gross-up factor resulted in Haynesville production being substantially overstated until analysts recalibrated their models. But even that recalibration doesn’t solve the problem, because you don’t have any way of knowing how much gas was redirected versus newly turned in line. You can make an assumption, but it’s that view that’s driving the model results, not the observable data.

If growth were mostly coming from Appalachia or the Rockies, production scrapes would probably have more signal value than noise. But growth is overwhelmingly coming from the Haynesville and the Permian, where intrastates move a large and growing share of production, and NGLs make historical dry-gas production estimates uncertain. With infrastructure as large as LEG, these model deficiencies are obvious. But gas flows change not only with new pipelines like LEG but also with new gathering interconnects, processing outages, or shifts in destination prices.

So when someone asks me to explain why gas production has unexpectedly risen or fallen, my answer is often to question whether it has indeed.

How I reevaluate when evidence changes

I make a good conference panelist because I’m opinionated2 and not afraid to express views outside the consensus. With this framework, I tend to grow less certain before eventually changing my mind. This year, though, I doubted CP2 FID until the moment it happened:

• First, I weighed soft factors — like the ongoing lawsuits and arbitration between Venture Global and its Calcasieu Pass offtakers — too heavily relative to cold hard dollars: Venture Global offered the lowest capacity charges.

• Second, I held too much conviction relative to how connected I was with LNG developers and offtakers. SPAs are public, but tracking those agreements isn’t enough to call which projects will proceed. Pointing out that some of CP2’s SPAs might have lapsed was appropriate; extending that to FID risk was not.

For me, good analysis is less about never being wrong than about knowing when to become less certain. With that in mind, don’t hesitate to comment or e-mail when your analysis suggests I should be changing mine. And in the meantime, merry Christmas!

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That shift, in this cycle, turns North American LNG from a…

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How Antero intends to keep up with growing peers

Antero’s long-haul FT strategy — once questioned,3 now thoroughly vindicated — remains central to its positioning. The downside of Antero’s FT capacity, though, is that it sources gas almost exclusively from its own upstream and midstream assets. In contrast with, say, EQT’s TETCO capacity, Antero can’t easily capture the value of its FT without also producing its own equity gas. Before this deal, this situation posed two challenges:

• Ohio production fills less than half its 400 BBtu/d of REX capacity

• In West Virginia, Antero has more in-the-money FT than processing capacity

The Ohio sale to Infinity solves the first problem, and the HG acquisition addresses the second.

Figure 1 | Antero’s firm transmission capacity (to scale)

Recently, other Appalachian operators have consolidated aggressively, while Antero and Range sat out. Now, Range guides to 20% organic growth by 2027. With scale growing increasingly important in a likely-persistently-constrained basin, Antero’s future as an independent company depends on its ability to scale up.

While it has the most extensive4 and best-structured transportation portfolio of any major Appalachian operator, its access to processing capacity has limited the company's growth potential for its core rich-gas West Virginia asset. With 13 trains at Sherwood and 1 at Smithburg, the company accesses 2.8 Bcfd of processing capacity, versus 3 TBtu/d of capacity to move gas away from Sherwood/Smithburg.5

But buying HG was not the only way Antero could have addressed this. Most straightforwardly, the company could have backstopped another Smithburg train, which was previously permitted, and indeed Antero paid $12 million in 2022 to cancel its construction. But the company dismissed this possibility on its 1Q25 earnings call:

If you have to make future commitments on FT or processing, that’s not something we’re interested in. … [We] are full or above nameplate on the processing.

This reticence points to a broader shift toward dry-gas growth, which does not require long-dated midstream commitments, especially as Northeast demand grows.

Another alternative would have been for Antero to ramp up its own West Virginia dry-gas production, bypassing the Sherwood/Smithburg constraint and connecting volumes directly into Stonewall Gas Gathering. Instead, the company expects to integrate HG’s production into SGG, choosing to buy dry-gas volumes rather than drill its own, either because HG’s PUDs are higher-quality or because a PDP-PUD valuation gap made the acquisition more capital efficient.

Future of Ohio gas production

Following Marcellus takeaway challenges, Utica operators contracted more aggressively. The play’s subsequent underperformance left some takeaway capacity available and only the pure-plays driving Ohio activity.

Infinity intends to ramp up activity on the newly acquired asset, which highlights a broader development trend in today’s capital-disciplined environment. Investors in mid- and large-cap independent E&Ps have little appetite for exploration risk, instead focusing on capital efficiency. HG derisked its position to the extent that Antero could take it on. In contrast, the next development phase on the Utica asset is now too risky to compete in Antero’s portfolio.

But gas demand growth is accelerating, and long-dated Henry Hub prices are likely to rise, creating opportunity for the small-cap or PE-backed E&Ps now proving up a next round of dry gas acreage. With Haynesville productivity deteriorating even more sharply than in the Utica and weak oil prices slowing associated gas production growth, the opportunity for Ohio growth — which is better-connected to markets than the rest of Appalachia — is improving. Infinity’s presentation indicated that it acquired REX capacity6 as part of the deal. In a rising Henry Hub price environment, this capacity becomes more valuable.

Outside of the companies party to the deal, MPLX is the biggest winner. While Antero’s processing commitments likely reduce MPLX’s near-term revenue exposure to Antero’s declining Seneca throughput, the prospects for future throughput at MPLX’s Seneca plant are much stronger with a new buyer that intends to invest in the asset. Tallgrass also stands to benefit, as Antero’s REX contract expires in early 2035 and, prior to that, steps down from 400 to 200 BBtu/d for its last five years. The odds of this capacity being renewed increase with a resurgence in Ohio activity.

Taken together, the HG acquisition and Ohio divestiture reframe Antero’s competitive position. In a basin where capital discipline now means avoiding new off-balance-sheet midstream commitments, large operators’ growth will come from underutilized processing or flexible dry-gas acreage. For Antero, the choice was clear: rather than fund a more speculative Utica development phase or backstop another Smithburg train, it bought dry-gas volumes that fit its existing midstream footprint. For Ohio’s pure-plays, though, the opportunity remains. Henry Hub prices are rising, and a more favorable takeaway position relative to the Marcellus means the Utica may enter another gas growth phase.

In today’s post, I walk through three of the most interesting pieces — not to “fact-check” them, but to highlight what I admire about them, where I disagree, and where they raise deeper analytical questions that I’m investigating now and will address in more detail soon.

A16Z: Gas-fired intelligence (part 1 and part 2)

What makes this piece notable is its audience: A16Z is introducing Silicon Valley to gas-market fundamentals, and Michael Spyker does an admirable job explaining the value chain while also offering original, forward-looking insights.

Central thesis: The combination of LNG demand under development and accelerating growth in gas-fired generation will send Henry Hub prices sharply upward, and both consumers and policymakers need to make major changes now to avoid calamity later

Money quote:

The sooner we can commit to a more-firm gas consumption trajectory (i.e. the sooner Silicon Valley can care about gas for the first time!) the sooner the upstream industry can prepare a supply response, the LNG industry can adjust their infrastructure plans; and the better off the world is.

Spyker also posits several other counter-consensus ideas that I think are correct:

• Consumers should agree to fixed-price contracts so that producers have a reliable price signal to invest and deliver the needed higher-cost gas volumes

• The US should stop permitting more LNG exports, because eventual higher gas prices will strand gas infrastructure investments in less-developed countries and therefore bring geopolitical challenges

• Long-haul gas transmission development from Canada will pay off

• Relying on associated gas growth is dangerous, given divergent oil and gas fundamentals

Where I differ: My main point of disagreement is that Permian gas isn’t neatly “associated” or “non-associated.” Rather, it sits on a spectrum, with varying responsiveness to oil, NGL, and gas prices. A 6–8 Bcf well that also delivers ~200,000 barrels of oil — of which thousands could be drilled in deeper Permian intervals — is meaningfully more attractive than a dry-gas 6–8 Bcf well in the Rockies. The Permian isn’t a top-tier gas basin, but it’s not the Fayetteville either. Even at $60/bbl WTI, $3+ Waha prices will incentivize additional gas volumes. Treating it as purely “associated” misstates the shape of the gas supply curve.

Draft posts coming: Why the AECO outlook is much more bearish; The needle producers need to thread to avoid prices getting too high

That supply-curve nuance matters a lot when you zoom in on the Permian basin, which several major consumers are counting on for gas production growth.

East Daley: the Permian Basin at a crossroads (part 1 and part 2)

Central thesis: The forthcoming buildout in Permian gas takeaway — driven by a different set of players than has been the case historically — is so large as to reshape not just gas markets but also upstream capital allocation decisions

Money quote:

Higher in-basin prices would make gas-focused development more attractive in the Permian, enabling producers to diversify their drilling footprints and capture profits from crude oil as well as natural gas.

What East Daley gets exactly right is that different shippers are driving this wave of Permian gas takeaway than the last one. Midstream firms and gas-market analysts already see how a structurally tighter gas market, combined with weaker oil prices, could reshape upstream capital allocation. But upstream and oil-focused teams haven’t yet fully internalized this.

Where I differ: East Daley suggests that new Permian gas pipelines could create basin-on-basin competition by unleashing new supply. I think the more likely scenario is the reverse: Permian non-associated gas emerges precisely because other basins aren’t positioned to deliver the needed volumes.

Draft post coming: All these Permian pipelines are not going to fill with associated gas

While new Permian pipelines face questions around the sources of gas supply growth, in the Northeast, the economics of potential new pipelines depend on volatile seasonal demand.

S&P: Constitution Pipeline market impact report2

Central thesis: If built, Constitution Pipeline would save Northeast consumers money in cold winters and facilitate emissions reductions

Money quote:

Avoiding a single extreme price event in addition to average weather savings offsets 15 years of end-user costs

Where I differ: S&P’s analytics are gold-standard for a project like this: jointly using a power-dispatch model and a gas-flow model. But while the individual slides are compelling, the report doesn’t shift my view that Constitution no longer makes economic sense. Their own numbers show why:

• Under normal weather, shippers’ demand charges would be ~$400 million in the red

• In peak months, only 100-250 MMcfd of capacity is available into constrained markets on Iroquois (and presumably none on TGP)

The report convincingly argues that Constitution would save consumers money compared to the status quo in cold winters. But it does not address whether other options, such as ramping up LNG imports, would save consumers more money. I am skeptical that a pipeline — a 365-day fixed-cost solution — is the most economic option for meeting what is, even in cold winters, a ~60-day problem.3

Draft post coming: We need to stop talking about Constitution

Taken together, these reports show how quickly the gas narrative is shifting — and how unevenly different sectors are updating their priors. The next few quarters will bring clearer signals on Permian gas, Northeast pipeline development, and how LNG and power growth will reshape Henry Hub prices. I’ll be digging into each in upcoming posts.