Reduced coal-gas competition, capital-discipline-era supply inelasticity, 15 years of storage underinvestment, and rising power and LNG demand combine to drive continued increases in gas price volatility. And this rising volatility creates outsize profits for companies positioned on the right side of it, which Expand now clearly aims to be. In conjunction with the deal, Wichterich announced an increase in target incremental marketing profits from $500 million to $750 million annually.

But realizing that value depends on future strategic decisions around contracting and risk management, not the book of deals that Twin Eagle currently holds. If successful, Expand will differentiate itself from smaller gas E&P peers, none of whom has the scale to execute a similar playbook. If not, the volatility-induced profits will remain concentrated among the funds and consumers (and EQT) that are willing to shoulder the associated risk.

Limited immediate FT integration

Producers typically contract for FT to backstop needed takeaway capacity from constrained basins, whereas marketers and traders view pipeline capacity as an option and make contracting decisions accordingly. Expand’s interstate FT — from both legacy Southwestern and legacy Chesapeake — moves gas from Marcellus and Haynesville producing areas to markets in the Northeast, Midwest, and Gulf Coast. Twin Eagle’s capacity is for smaller quantities (thinner lines in Figure 1) and is more geographically diffuse.

Immediate integration opportunities are likely limited to the Midwest. Some of Expand’s Rover and REX volumes might be able to flow into Twin Eagle’s capacity, although it’s uncertain because the receipt points are out of path. If these volumes are successfully scheduled further downstream, Expand’s realized prices would improve during peak winter heating months.

Figure 1 | Expand and Twin Eagle US interstate FT (2026Q3)

But in that scenario, Expand’s improved realized prices cannibalize what would otherwise have been Twin Eagle marketing profits. Pre-deal, Twin Eagle could buy either Expand’s or another producer’s gas and capture the value of its capacity. To the extent that these volumes came from another producer, the pro forma entity could unlock perhaps a couple cents per MMBtu of marketing margin. But the bigger incremental benefits to the combined organization depend on future FT or other strategic marketing decisions.

Strategic rationale

The strategic rationale, therefore, is more about the Twin Eagle team and its capabilities than the specific capacity agreements. That capacity position itself is likely to change: Twin Eagle’s FT is not just for smaller capacities but also for much shorter tenors, as shown in Figure 2.

Figure 2 | Expand and Twin Eagle US interstate FT history

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I was never anywhere near that bullish; my own outlook called for Henry Hub prices reaching the mid-$4/MMBtu range by 2030. But an analyst’s job is to keep re-evaluating, and the evidence since then suggests I made the same error Chronometer did — underestimating elasticity — albeit on a much smaller scale. Given recent Haynesville activity levels, I now expect Henry Hub prices to rise to the low-mid $4s by 2030.

What is the purpose of this whitepaper (and media tour)?

After 18 years in this business, I can tell you that written research — even paid written research — is almost always a loss leader for something else, typically banking or software. Here it’s likely marketing, for raising additional capital and/or recruiting partners and analysts. In both cases, your incentive is to gain attention by positing interesting, thought-provoking ideas. In other words, to identify a real problem and sell it hard. If Henry Hub prices briefly go to $8/MMBtu and then settle at $4.50, Chronometer still looks great, even though that’s nowhere near a structural doubling or tripling.

What’s wrong with Chronometer’s analysis?

Energy FinTwit immediately and comprehensively documented the flaws1 in Chronometer’s analysis — even Kimmeridge’s Ben Dell weighed in — so I won’t rehash those here. (Kimmeridge itself is a good example of a firm that produces serious, deep research as a loss leader.)

At a high level, though, this analysis falls down by consistently understating elasticity — in gas supply, LNG exports, gas-fired generation, and gas pipeline development — and thereby overestimating the impact of real market changes (Figure 1). And then all of these overstated partial equilibria compound into an even more ridiculous general equilibrium: that Henry Hub prices will double or triple structurally.

Figure 1 | Chronometer’s claims and my views on them

To be fair, Chronometer is right that complacency about long-term gas prices itself increases the odds of a spike, that Silicon Valley is taking gas-price risk lightly, and that rising gas and power prices are likely to become more politically salient. But it’s a long way from any of those to a structural doubling, which none of Chronometer’s analysis supports.

Why I was already getting less bullish

But even before Chronometer gave all of us gas bulls a worse name than we already had,2 market fundamentals had me reevaluating that mid-$4/MMBtu view. Starting in mid-2025, weather-adjusted gas-fired generation flattened, while production growth accelerated despite modest prices. The former is likely transient, but I am revising my thinking on prices based on the latter — and I’ll take each in turn.

Gas-fired generation: likely to accelerate over the next year

So far this year, gas-fired generation is roughly flat year-on-year, after normalizing for gas prices and fossil generation levels (Figure 2). The slowdown in coal retirements has ended a long-term tailwind for gas burn.

Figure 2 | Year-over-year change in gas-fired generation

But while gas’s competitiveness with coal (holding gas prices constant) is unlikely to shift much in the short or medium term, fundamentals for fossil generation look stronger. Data-center development is diffuse and opaque, so it’s hard to know exactly why total generation levels slowed in the first half of this year after accelerating sharply in 2023-25. But hyperscalers (Microsoft and Google) and frontier labs (OpenAI and Anthropic) all point to a common explanation: demand for AI tools outstrips computing capacity.

I expect that weakness in load growth from mid-2025 through 1Q26 reflected constraints on data-center capacity, and that load growth is likely to accelerate as new capacity comes online. Some evidence of this is already visible in US power data: weather-normalized generation since April has grown at a ~1.5% annualized rate, up from ~0.4% over the prior three quarters.

Figure 3 | Weather-normalized run-rate US electricity generation (30-day MA)

Add in a decelerating solar build following the tax-credit phase-out, and I’m not worried about medium-term fundamentals for gas-fired generation, even though gas burn this year has been weak.

Haynesville activity: stronger than I expected

Permian gas production growth filling available takeaway capacity this summer is unsurprising, and still consistent with a bullish long-term view. But ~2.4 Bcfd of Haynesville gas production growth since September 2025 is more than I expected, as was the high-50s rig count in February-March.

However, the implications of these higher drilling levels are less severe than they seem at first glance. The currently active 41 rigs don’t necessarily mean that operators see that activity level as optimal relative to prompt-month prices of $2.75; rather, operators made those drilling decisions last fall, when the 2026 strip traded at ~$4. But the 52 rigs active on average so far this year do mean that operators saw $4/MMBtu as a sufficient price to ramp up Haynesville drilling and production, which is a lower threshold than I expected (and lower than major operators guided).

Figure 4 | Haynesville activity and year-ahead Henry Hub prices

Implications for long-term gas prices

Since I wrote about my bullish view last fall, the 2027-30 Henry Hub strip has sold off from ~$3.85/MMBtu to $3.60. Given this year’s stronger-than-expected Haynesville activity, I’d fade my medium-term outlook by a similar amount, to the low-mid $4s.

In 2024-25, operators ran ~40 rigs following ~$3.25-3.50/MMBtu planning prices, so I expect a similar 2027 Haynesville activity level with the 2027 strip at ~$3.40/MMBtu. With Haynesville drilling already down to an average of 45 rigs in June, this seems likely — but if it’s not, I’ll need to revise further.

And this trend is likely to continue. Most public gas E&Ps operate in Appalachia, where production growth will likely remain slow, limited by modest incremental takeaway capacity and in-basin demand growth. The largest Permian operators are public, but these companies often do not break out dry-gas production guidance separately from their rich-gas or Boe figures. Haynesville acreage, meanwhile, has consolidated, but mostly into the hands of Japanese conglomerates that don’t give detailed Lower-48 gas production guidance, either.

As a result, accurately anticipating near-term Lower-48 gas production inflection points will increasingly depend on synthesizing satellite and state-reported data.

First, estimating current production

Before we can synthesize activity levels into an estimate of run-rate growth, we need to understand current well-by-well production. To do that, I developed an algorithm that estimates likely unreported spuds and completions1 in a multi-step process:

1. Estimating a rig’s (or frac crew’s) capacity for additional spuds (or completions), beyond what has been reported, based on how long it was observed on a pad and typical drilling (or completion) times in that play

2. Netting out reported spuds or completions on the pad, and

3. Constraining this by the availability of candidate wells on that pad that have been permitted (or drilled)

Which companies drove recent growth?

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But as I’ll show, New England LDCs are well-served with existing capacity, while the unit economics of space-heating conversions only pencil out with a subsidy from existing gas customers. Power generators, meanwhile, only need additional gas on a couple dozen days per winter and don’t have a rate base to pass through the costs of additional capacity. In the long run, the region’s consumers would be better off backstopping more LNG imports into Canaport LNG1 than paying for additional 365-day pipeline capacity.

Who holds capacity into New England?

For the first time since 2017, a new pipeline expansion into New England is on offer: Algonquin’s Project Beacon recently launched an open season. Algonquin is one of five pipelines bringing gas into New England on three major routes:

• Iroquois and Portland Natural Gas connect to the TC Mainline at the border and bring gas south into New England.

• Intermittently, Maritimes & Northeast brings gas south from Canaport.

• TGP and Algonquin bring gas northeast from Appalachia.

Repsol holds most of the capacity on M&NP, and LDCs hold ~80% of the contracted capacity on the other four.

Figure 1 | Pipeline capacity into New England

Even though New England power generators hold just ~200 MMcfd of capacity into the region, they burn ~1.3 Bcfd on average. Because utilities contract for peak-day needs, their capacity is under-utilized most of the year, meaning that most days it is available for merchant power generators to free ride.

Figure 2 | New England gas demand by sector

Where and why does New England burn oil?

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When I launched this project late last year, I posed three questions that I was hoping to answer:

• Whether research alone is a viable business

• And if it is, whether subscribers would want something broader or deeper, whether they’d want more attention on production or power or LNG

• Which of my potential product ideas could have a market

This week, I’ll cover what I’ve learned since then and ask for your feedback, both generally and on a few specific questions. I've put together a short reader survey, and I’d really value your free-response feedback. I’ll comp a month’s subscription for responses I find especially helpful.

Is research alone a viable business?

Eight months into this endeavor, and four months into paid subscriptions, Measured Depth has:

• Three enterprise subscriptions. I’m very grateful to them, all of whom I knew as clients prior to launching this endeavor.

• An additional ~25 individual subscribers, each from a different company.1

• ~800 more subscribers to the free version

Relative to what I expected at the outset, Measured Depth has more free subscribers but fewer paid subscribers. And the paid subscription trends also differed from what I anticipated; I thought perhaps 5-10% of free subscribers would pay initially, but that hardly anyone would upgrade afterward. Instead, only about 10 people upgraded to a paid subscription in March, but about half that many have signed up each month thereafter. Realistically, I probably need to double the paid subscription levels for the weekly publication to be worth it, but I’m optimistic that I’ll reach that level within the next 6-12 months.

But perhaps that confidence is misplaced! To that end, I’d like to understand how each of you is thinking about subscribing.

What do subscribers want?

From page views and subscription rates, I have a sense of which topics resonate most strongly with subscribers. But honestly, the readership statistics have been more similar across posts than I expected, suggesting that there aren’t universally “most interesting” topics, but rather a range, each of which resonates with a different subset of Measured Depth subscribers.

And while I’m proud of this range — several angles around LNG exports, coal-gas competition and coal retirements, analytical methodology, Permian production, Appalachia takeaway and new projects, load growth and more — I’m less sure whether it’s the right direction for this publication, relative to something more focused.

I’m not ever going to have a daily fundamentals product like RBN or Criterion or Genscape, or comprehensive coverage of the energy value chain like WoodMac or CERA. I do think I’m offering differentiated depth and quality of analysis and providing unique strategic and tactical insight. And as I build more foundational tools, I’ll have more time to incrementally add functionality and improve the offering. The question I can’t answer from readership statistics, though, is what latent interest subscribers have, and what direction you’d like to see those product improvements take.

Which product ideas could have a market?

About a year ago, my cousin — who works for a small private Permian E&P — came to Houston for a board meeting and wanted to talk about two things: the prospects for higher Waha prices and AI. I told him I more or less wasn’t using AI at all, and he was stunned. At the time, I had a team of 10 or so people, so I spent a lot of time in meetings and wasn’t writing much code myself.

When I wrote in November about launching this venture, I had seen enough to know that AI would make it easier, but in retrospect, I had no idea how much easier. As a parent, I often wonder how AI will reshape jobs by the time my kids are interviewing.2 As an analyst, though, I feel like these tools were made for me: someone with subject-matter expertise who thinks algorithmically, but whose ideas for new models far outpaced her time (or capability3) to build them.

I’ve never set up a database before, or scraped data at scale, or digitized pipelines, but I’ve used these tools enough to know what I’m looking for, and what to ask Claude for direction on. I know it’s trite, but truly, what a time this is to be alive. I’ve been able to build products much faster than I expected, and am excited to share some of those with you this fall.

In the weekly posts, you’ve seen some graphics illustrating pipeline capacity by location, which I can now do algorithmically with location, shapefile, and index of customers data. I want to add more functionality to the application, but I have enough pipelines (Figure 1) digitized to be useful.

Figure 1 | Lower-48 contracted interstate capacity

Then, over the next few months, I want to use this contracted capacity as the backbone of a gas flow model. Maintaining infrastructure data is a major challenge in the traditional approach to gas flow forecasting, so my hope is to streamline this process using the IOC and nodal structures. And then there’s my white whale — a supply model — which I’ve been developing with a partner and hope to begin scaling in the coming months.

If you or your firm would be interested in hearing more about any of these products, please get in touch so I can set up a meeting. Of course, I’d love to hear your thoughts on my survey questions, too. In the meantime, happy belated 4th, and thanks for reading!

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But now, three major Permian takeaway pipelines are under construction to Gulf Coast markets, and Energy Transfer is also developing a new-pipeline-sized expansion of Transwestern. These four projects add ~10.5 Bcfd of capacity over the next four years, and the call on Permian gas from Mexico and within the basin is likely to rise ~1 Bcfd over the same period.

That ~11.5 Bcfd of new market access would accommodate both the currently curtailed ~1.2 Bcfd and 2.5-3.0 Bcfd of growth each year thereafter. Public Permian midstream operators agree that the ongoing Permian gas takeaway buildout will un-constrain the basin, but the market is increasingly worried that Permian gas supplies will fill this takeaway capacity, weighing on Henry Hub prices.

But as I’ll show, accelerating base declines mean that even a consistent pace of Permian activity — itself unlikely — won’t fill forthcoming takeaway capacity unless the pace of single-well gas productivity accelerates sharply.

Declines from existing wells

Because the Permian is now such a mature play, forecasting gas production from existing wells is much more straightforward than forecasting either future activity levels or the productivity of future wells. However, traditional Arps-based approaches to building type curves systematically under-forecast gas volumes in the middle of a well’s life, when the rate of gas decline slows dramatically relative to that for oil and gas-oil ratios rise rapidly.

Instead, I use an Arps-based forecast for oil volumes and forecast gas volumes based on the typical trajectory of gas-oil ratios through the well’s life. This approach adds ~800 MMcfd to medium-term gas production compared with a typical Arps-based approach. However, even this approach points to continued acceleration in base declines. Rising production levels mean that even if the pace of PDP declines remains consistent, the level of base declines increases.

Figure 1 | Permian PDP gas volumes and first-year declines from wells TIL by 2025

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In its April fundamentals presentation, Enterprise pegged curtailments at 2.0-2.5 Bcfd, and a growing subset of analysts now expect the ~4.6 Bcfd of Permian capacity due online over the next year to fill immediately. Whether that happens depends on two factors:

1. How much production is curtailed currently

2. How much production is likely to grow from this point forward

Given the complexity of this topic, I’ll cover the latter in a follow-up post. The former is more challenging in the Permian than it would be in any other basin for two reasons: pipeline scrapes have more noise than signal for Permian production, and while most wells report within 2-3 months of when they begin producing, the long tail of Texas well data trickles in over more than a year.

To address these issues, I’ll triangulate between frac-crew tracking, pricing data, and meta-analysis of state reporting to estimate what Permian dry gas production “should” be currently and, therefore, how much volume is likely curtailed. As I’ll show, Enterprise’s curtailment estimate was likely conservative as of April, due to a surge in March TILs. Since then, easing completion activity and the GCX expansion coming online likely pushed curtailments down to ~1.2 Bcfd.

Volumes (including wellhead shut-ins) from reported wells

As of yesterday, state regulatory agencies reported ~28 Bcfd of Permian wellhead gas production for March 2026, which translates to ~22 Bcfd of dry gas.1 Although most Permian production has oil-weighted revenue streams and therefore little incentive to shut in when Waha prices are negative, some wells are more gas-weighted and respond to gas price signals. These shut-ins mean that true wellhead production potential is understated even in reported data. I analyze cohort-specific gas-oil ratios to identify where reported wellhead gas volumes fell short of what we would expect given oil production levels, indicating price-driven wellhead gas shut-ins.2

Altogether, these curtailments add ~400 MMcfd of missing wellhead production in state-reported data for February and March. Because Arps-based type curves tend to understate gas volumes in oil plays, I use a combination of oil type curves and the typical trajectory of gas-oil ratios over a well’s life3 to estimate production from these wells since March. This translates to 22.4 Bcfd in June, which in-basin demand and takeaway capacity would easily accommodate. But this estimate is incomplete because it does not account for wells that are already producing but have not yet been reported by state regulatory agencies.

Figure 1 | Permian gas production and takeaway capacity

Reported completions not yet reported producing

These wells constitute the biggest source of uncertainty in estimating current Permian gas production because we don’t know how many there are. The last two months are instructive but by no means unique. Over that period, most of the Permian wells newly disclosed by the RRC (medium and light gray bars in Figure 2) started producing in March or April. But an additional four of them started producing in July 2024, meaning it takes more than a year to have a complete picture of Permian wellhead volumes.

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In 4Q25 earnings season, developers announced three major projects that would pull Appalachian gas west to serve growing Midwest data-center demand. Now this quarter, two additional project announcements point to even more gas-fired generation growth in the same area:

• DT Midstream closed an oversubscribed — albeit non-binding — open season on its Midwest Incremental Supply Transportation project on Midwestern

• TC Energy formally sanctioned the Appalachia Supply Project on its Columbia Gas (TCO) system

Both projects are early in their development lifecycles, with no FERC filings yet, but both confirm a rising call on gas-fired generation generally and growing upside in the middle of the country specifically. The Appalachia Supply Project is the more advanced of the two, with an anchor shipper already in place, although TC has disclosed little and not yet held an open season. Even so, its earnings-season comments confirm the project will lift Northeast E&Ps’ volumes and realized prices. MIST, meanwhile, will improve realized prices for Appalachian operators with REX capacity, but its incremental volumes are more likely to come from the Rockies.

DTM’s MIST project on Midwestern

On its 1Q26 earnings call, DT Midstream said customer interest exceeded MIST’s proposed 1.5 Bcfd of capacity, with shippers interested in both the northbound and southbound paths. DTM highlighted Midwestern’s connectivity with “pipelines that traverse all the way down to the Gulf,” suggesting customers interested in stacking Midwestern with either TGP or TGT capacity, which interconnect with Midwestern near its southern end (Figure 1).

Now, on high-demand days, gas moves north across the entire Midwestern system, sourcing some TGP volumes at its southern end and delivering mostly to customers north of REX. In shoulder months, though, gas moves both north and south from REX.

Figure 1 | Midwestern and REX flows in high- and low-demand months

REX supplies (purple area in Figure 2) the overwhelming majority of gas on Midwestern, and these volumes move into Midwest delivery pipes including Guardian (light blue area) in the north, and to both end-users and Texas Gas (light purple) in the south.

Figure 2 | Midwestern supply and customer mix (30-day moving average)

Rockies Express’s future involves the actual Rockies again

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Antero’s late-2025 transactions — divesting its Utica position and acquiring HG Energy — marked a substantial shift in the company’s strategy. Following those deals, Antero is much more weighted toward dry-gas volumes, and the company’s 1Q26 commentary reinforced the shift, highlighting its interest in additional West Virginia acquisitions and signaling that it won’t renew some processing and firm transmission agreements.

For Antero, dropping FT implicitly acknowledges that its West Virginia rich-gas production won’t grow into the FT portfolio designed for it. Antero is not alone among Appalachian operators in having a limited inventory runway on its core assets. But the more it can bulk up by acquiring other companies whose assets it can integrate into its midstream positions, the less it needs to right-size its FT portfolio. Key FT renewal decisions next year will reveal what Antero’s management thinks of its potential to be a West Virginia consolidator rather than an acquisition target itself.

Antero’s capacity position post-HG

Historically, Antero distinguished itself among Appalachian peers by contracting early for pipeline capracity to move gas out of the basin. The challenge with Antero’s portfolio, though, has always been that it is bespoke to Antero and overwhelmingly originates at MPLX’s Sherwood/Smithburg gas processing plant complex, which processes little non-Antero gas. Antero’s in-the-money capacity, therefore, cannot be monetized independently of its own production. Conversely, if, say, CNX’s Marcellus production were to decline, the company could buy another operator’s gas in-path and still capture the value of its in-the-money pipeline capacity.

With its acquisition of HG and divestiture of its Utica properties, Antero’s FT portfolio underwent two key changes:

1. Antero inherited HG’s portfolio, which consists entirely of in-basin FT, moving HG’s gas from southern West Virginia into liquid markets on EGTS, Columbia Gas, REX, and TETCO.

2. Infinity took on 300 BBtu/d of Antero’s 400 BBtu/d of REX capacity. Antero can likely use the remaining REX capacity1 to improve realized prices for some HG production that previously was delivered into REX.

Figure 1 | Pro-forma Antero FT portfolio

Between redeploying its REX capacity to improve market access for HG volumes and HG’s capacity on DT Midstream’s systems that Antero also uses, HG’s midstream position fits well with Antero’s.

Which FT is Antero likely to drop?

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The biggest questions weighing on the gas market right now concern Permian gas production: how much is currently curtailed and how much production will grow once new pipeline capacity is online. As always, the challenge with forecasting Permian gas production is that we don’t have a solid starting point: regional dry-gas production is never reported, complete wellhead gas production isn’t reported to the Texas Railroad Commission for a year or more, and pipeline scrapes capture less than half of the region’s volumes.

With no good way to bridge these gaps, the market is clinging to the signals it has: rising gas-oil ratios, negative Waha prices since early February, two new gas processing plants announced this quarter. Midstream operators probably have the best basin-wide view, since they work with multiple producer counterparties. But the lack of a common starting point makes their comments hard to interpret, and the market misread many of them. A more careful analysis reveals Enterprise, Energy Transfer, Summit, and Targa all expect Permian gas production will not fill the ~11 Bcfd of takeaway capacity under construction.

Figure 1 | Post-FID Permian takeaway capacity

Energy Transfer’s refutation of the processing-additions school of Permian production forecasting

Energy Transfer was unequivocal: Permian gas production growth won’t match the pace of takeaway capacity expansion:

Could you say there’s a bottleneck in the Permian Basin today? Absolutely. By the … first part of next year, that bottleneck is going to open up, and there's going to be enormous opportunities for producers to drill away as much as they want to drill because there’ll be plenty of capacity for a number of years to come.

Just as importantly, Energy Transfer refuted what I’ll call the processing-additions school of Permian gas production forecasting. The processing-additions school holds that, without current well data or comprehensive pipeline scrapes, scheduled processing-plant additions are the best way to forecast gas production growth. And there’s merit to this approach, since midstream operators typically don’t build new processing capacity without commitments from producers.

But it has its pitfalls, too: some commitments to new capacity may just replace expiring contracts on older capacity, and Energy Transfer pointed out1 that some midstream operators are more aggressive with their growth plans:

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1. New York’s refusal to grant various stream crossing permits,2 with a justification that was more or less “because reasons,” was an egregious abuse of the Clean Water Act.

2. The project’s FT economics were always marginal for shippers, and its original producer-push premise no longer pencils out.

Because of the first thing, the industry (rightly) has a stick in its craw about this project. But because of the second thing, the project needs to be paired with a downstream expansion.

How we got here, and where Constitution stands now

Constitution dates back to 2012 (!). By late 2016, New York’s denial of water-crossing permits had effectively killed it, until a horse-trading deal last year: President Donald Trump lifted a ban on Empire Wind, and Governor Kathy Hochul agreed not to block gas infrastructure.

Williams CEO Chad Zamarin suggested last month that the pipeline could be online as soon as the end of next year. But even Zamarin’s optimistic comments had a crucial condition: that the project could be online next year if commercial agreements are signed within the next couple of months. None has been announced yet.

Constitution doesn’t access constrained markets

Although Northeast power generators pay some of the highest gas prices in the world on constrained winter days, Constitution does not access these markets. Rather, Constitution terminates at the interconnect between Iroquois and TGP in Wright, New York, meaning that Constitution would displace gas otherwise flowing into Wright on Iroquois (from the north) or TGP (from the west).

Figure 1 | Constitution and interconnecting pipelines

Historically, gas flowed into TGP from Canada at Niagara, but by the time of Constitution’s conception, projects were already under construction to reverse those flows. Constitution’s premise, therefore, was to displace Canadian gas imported at Waddington into Iroquois. Demand seasonality in New England and New York drives the call on gas at Wright, and with it, imports from Canada. Figure 2 illustrates flows on TGP and Iroquois, which, in some months, move as much gas into these premium markets as they can, but in others are underutilized.

Figure 2 | January and May 2025 TGP and Iroquois flows

Last year’s gas flows at Wright reveal which supply sources Constitution would push out. On 142 days, Constitution would have displaced exclusively Canadian gas (Figure 3). On those days, a potential producer shipper would see realized prices in line with those in eastern Canada; these trade meaningfully above Appalachian prices but well below levels in New York or New England.

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• Gas-fired generation is becoming less elastic at lower levels of fossil generation.

• Coal-gas competition shifted sharply between 2023 and 2025: gas ceded market share in 2024, then rebounded in 2025, but that rebound concentrated on higher-demand days.

This week, I’ll unpack the drivers of these trends, extend the analysis through early 2026, and pull out implications for 2027 and beyond.

Why is gas price elasticity limited on low-demand days?

Examining how gas prices and fossil generation jointly and non-linearly affect gas-fired generation shows limited elasticity on low-demand days, as indicated by little color change from left to right at the bottom of Figure 1. I estimate ~140 GWh (~1.1 Bcfed) of elasticity per $1/MMBtu move in gas prices on these low-demand days, but ~290 GWh (~2.2 Bcfed) on a moderate-demand day.

Figure 1 | Gas-fired generation surfaces

To evaluate whether this reduced elasticity on low-demand days is a robust result, we need to examine both fleet- and unit-level operational patterns. Hourly generation data shows how rising renewable generation has dramatically changed fossil load shapes, albeit in different ways across low-, medium-, and high-demand days.

Figure 2 | Fleet load shapes by fossil generation quartile

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How do analysts typically look at gas demand curves?

Gas-fired generation depends on two main drivers:

1. Total generation levels, and therefore how much fossil-fired generation is needed

2. Gas prices, and thus how much comes from gas versus coal.

However, because both fossil fuel generation and gas prices are important drivers of gas demand, a univariate model based on either one yields spurious results. The gas-versus-price view shows wildly different slopes year to year because fossil generation varies so much from day to day. Conversely, the gas-versus-fossil view shows a tighter relationship, but year-on-year shifts look structural when they’re actually just price moves.

Figure 1 | Gas-fired generation relative to gas prices and fossil generation

Because electric demand varies widely through the year based on the weather, analysts typically try to neutralize for total generation by instead looking at gas’s share of fossil generation, as in Figure 2.

Figure 2 | Gas share of fossil generation

C. Thi Nguyen’s new book, The Score,1 helped crystallize what I think is wrong with this approach and with gas-analyst power forecasting I see. Nguyen argues — and I agree — that:

Real understanding involves having a mental model of some scientific phenomenon that allows you to make predictions, explain new events, and come up with new solutions. You’re not stuck with a few rote, memorized procedures. You can adapt to new circumstances, diagnose new problems, and improvise new solutions, because you understand how the parts fit together.

And in this case, to interpret what’s happening with gas-fired generation, you need to ground that analysis in an understanding of power dispatch, in which individual fossil generators bid into the market based on their fuel input costs and operational characteristics. The most robust way to model power generation, then, is with an hourly dispatch model that accounts for load shapes, minimum capacity factors, ramp times, how heat rates vary with capacity factors, and more. Of course, that requires a huge investment of both time and money, and it doesn’t pencil out for everyone.

But at the very least, everyone can afford to ground their models in how power dispatch works, so as to better disentangle what’s happening. The question we should be asking is: how closely does your simplified model mimic a dispatch model? In the case of “share of fossil generation,” the answer is not at all. That model implicitly assumes that power generators vary the share of their generation that’s gas-fired in response to gas prices, whereas in reality, the share of generation that’s gas-fired is the result of individual unit dispatch.

What can we learn with a better approach?

The good news is that, compared with other demand sectors and especially with production, granular power data is available with very short lags.2

And that data confirms that not only does gas-fired generation depend on fossil generation and gas prices, but that the elasticity in gas demand is non-linear with respect to both prices and fossil generation. Figure 3 shows gas generation on the color scale as a function of gas prices on the horizontal axis and fossil generation on the vertical axis.

These surfaces highlight a key insight that the traditional share-of-generation in Figure 2 misses. On low-demand days in 2025, when fossil demand was ~5 TWh, the color barely changes — meaning gas demand barely declines — as gas prices rise. Conversely, at ~7 TWh of fossil generation, the color changes more quickly, from light green at $2.50 to blue at $4. More concretely, I estimate ~140 GWh (~1.1 Bcfed) of elasticity per $1/MMBtu move in gas prices on these low-demand days, but ~290 GWh (~2.2 Bcfed) on a moderate-demand day.

Figure 3 | Gas-fired generation surfaces

We can also compare these surfaces from year to year to understand how gas-coal competition has evolved. Figure 4 shows the year-to-year change in these gas demand surfaces. We see that coal-gas competition was relatively unchanged in 2024, as shown in the relatively white panel on the left, before gas demand accelerated in 2025, albeit mostly on high-demand days, as shown in the green area at the top.

Figure 4 | Year-over-year change in gas-fired generation

This approach, then, lets us identify impactful trends that the “share of fossil generation” approach can’t, like:

• Why is gas-fired generation less elastic at lower fossil generation levels?

• Why did gas stop taking market share from coal in 2024, and why was 2025 growth concentrated on higher-demand days?

• What does the 2026 year-to-date shape tell us?

I'll work through these in the next post — subscribe to get it in your inbox.

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And that need for scale — for marketing reasons as well as upstream ones — matters most for one company: Range Resources. Range has one of the most attractive remaining-inventory positions in the industry, but as I’ll show, it lacks an attractive path to bulking up, making it a more likely acquisition target than an acquirer.

Why scale matters

Large-cap oil names already trade at a premium to smaller peers, and in the long run, scale will be even more important for US gas E&Ps. Oil E&Ps’ deteriorating rock quality has driven recent (and ongoing) consolidation, as operators both reduce G&A expenses and improve productivity with larger, more contiguous acreage positions. Larger gas E&Ps benefit from the same corporate and upstream synergies plus returns to scale in marketing. In the gas market, transportation and differentials comprise a much larger share of the commodity price, so marketing decisions move EBITDA more.

But realizing that benefit requires substantial fixed-cost investment in trading, scheduling, risk, and fundamentals, which only pays off at scale. This need for scale is even more acute in constrained basins like Appalachia, where intermittent pipeline constraints increase the extrinsic value of pipeline capacity, but only if the capacityholder treats it as an option rather than just flowing it every day.

Expand interim CEO Mike Wichterich targets a $0.20/MMBtu uplift in realized prices from marketing. And while that degree of improvement is unlikely, EQT’s 1Q26 performance shows how these investments can pay off.

Range’s unappetizing acquisition menu

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As a result, future renewable capacity development will likely decelerate. Still, momentum from projects already under construction points to a record ~32 GW of solar capacity coming online this year, reshaping the daily and seasonal call on gas-fired generation. Backward-looking adjustments to the gas supply-demand balance don't capture this shift, which means the industry risks reading seasonal effects as structural — and structural effects as seasonal. The rising solar share of renewable capacity means the gas market will look more bearish than it is in late spring and early summer, and much tighter than it is around the winter solstice.

Wind and solar capacity outlook

The EIA’s 860M electric generator report includes a project-by-project inventory of operational and planned capacity. Typically, this report understates currently operational capacity in recent months, particularly for solar, but the “planned” category includes speculative projects that will never materialize. By analyzing historical versions of this report, I risk-weight each of the EIA’s development lifecycle categories and further discount less-advanced wind projects based on sector-specific headwinds.

Based on the current development pipeline and this risking approach, solar would account for ~53% of combined wind and solar capacity by year-end, up from ~33% when Congress passed the IRA in August 2022.

Figure 1 | Solar and wind capacity outlook

Seasonality of wind and solar generation

If solar and wind utilization rates were consistent day-to-day or at least month-to-month, their impact on gas burn would be straightforward to disaggregate. However, two factors — shown in Figure 2 — complicate this analysis:

1. Load shapes — especially for solar — are highly seasonal

2. Day-to-day volatility — especially for wind — means generation does not reliably follow these seasonal shapes

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But extracting a real-time read on production requires properly accounting for weather impacts, and that normalization is getting harder with rising gas-fired generation.

Building a supply-demand balance

Isolating underlying structural trends requires first accounting for cyclical factors — both direct weather impacts on demand and other seasonal factors, such as LNG maintenance or nuclear refueling outages. For the former, we build a linear model of gas storage injections as a function of heating-degree days, cooling-degree days, and holidays1 over the 2021-25 period. The residual of this model is the gas supply-demand balance, an indicator of underlying market strength or weakness. Because each week’s observation is noisy, analysts typically smooth the time series with an exponential function.

Figure 1 | Gas supply-demand balance

But the resulting indicator still varies throughout the year because non-temperature-related seasonal factors systematically tighten or loosen the gas market at specific times, such as nuclear refueling outages, wind capacity factors, and LNG maintenance. To correct for this seasonality, we net off the five-year2 average supply-demand balance for that week to get a more neutral supply-demand balance.

Figure 2 | Seasonally adjusted gas supply-demand balance

How are changes in the gas market affecting the storage number?

The rise in gas-fired generation means the absolute seasonality of US gas demand is nonetheless increasing, even as the plurality of US gas demand growth has come from LNG exports. Weather-sensitive gas demand — shown in the teal shades in Figure 3 — grew 18 Bcfd from 2010-25.

Figure 3 | US gas demand growth and seasonal range

This growth in weather-sensitive consumption — particularly power generation — means that the impact of degree days on gas burn will increase over time. And if instead of modeling the impact of weather on weekly storage injections over the 2021-25 period, we use shorter, rolling horizons, we can see how the relationship between weather and demand has changed over time.

Here, we face a tradeoff between using the most recent data and having enough data points to reliably estimate coefficients. A two-year sample probably does not have sufficient resolution for a reliable model, but even a three-year rolling horizon shows a consistent increase in the impact of cooling degree days, offset by a higher constant, meaning higher injections in a mild week.

Interestingly, HDD coefficients have stabilized in recent years, even as rising power generation has added demand that is sensitive to cold weather. I expect the HDD coefficient is not rising because gas pipeline capacity — contracted by LDCs — limits gas-fired generation on the coldest days.

Figure 4 | Rolling horizon coefficients

The self-correcting seasonal adjustment partially masks this drift, but not fully, because both the model and its seasonal adjustment are backward-looking — we should expect today’s true CDD coefficients to be higher still.

Forward-looking implications

The US gas market grew 70% over the last 15 years, while US underground storage capacity remained essentially unchanged. EQT and others have rightly pointed out that the same storage inventory levels provide much less of a cushion against gas market dislocations from weather, outages, or other factors. Rising gas-fired generation, meanwhile, means that the call on gas storage is nonetheless increasing. The result, then, is that modest dislocations between supply and demand can quickly lead to extreme price outcomes.

Now, a colder-than-normal winter draws down storage inventories much more quickly; similarly, producers’ outrunning demand by a small percentage risks quickly creating a storage glut. So while the EIA’s gas storage number, released each Thursday morning at 9:30 CT, has always been the biggest needle-mover for NYMEX Henry Hub prices, it is now more important than it has been at any time since the pre-shale era, when supply and demand elasticity were much weaker.

The rise in weather-sensitive demand means that models built on lagging data — which is all of them! — will, in summer months, under-predict the impact of each CDD and therefore under-attribute demand to the weather and over-attribute it to structural strength (and conversely in the spring and fall). In other words, a hot July week looks structurally tighter than it really is, and a windy April one looser.

And while we’re mostly looking at the supply-demand balance for a read on production, understanding the level of gas-fired generation in a given week is different than isolating what that means for the future. In the next installment of this series, I’ll show how the rise in renewable generation overstates market looseness in the spring and tightness in the summer.

Against that backdrop, this earnings season confirms that flows out on these four routes are likely to decline further. Both new power plants under construction in Ohio and potential Ohio pipeline projects source gas downstream of the existing constraints. That means the new projects don’t increase market access for the core dry-gas Marcellus E&Ps best-positioned for growth. But the projects do create an opportunity for these producers, and their midstream counterparties, to develop smaller, intra-basin projects to bring core dry-gas volumes across the Ohio River to access what are likely to be much stronger prices.

Williams integrated power projects

In its earnings presentation, Williams expanded and extended its plans to develop and source gas for power plants in Ohio. The company is now building three power facilities, with a combined capacity of more than 1 GW. One of these projects is due online in each of 2026-28: Socrates (North & South), Apollo, and Socrates the Younger.

These power plants are far from Williams’ own Ohio gathering and processing assets near the Ohio River, so they’ll use gas from other systems. The Socrates plants coming online later this year will source gas from a combination of Columbia Gas (TCO) and Eastern Gas, and the Apollo plant will take gas from Nexus. In all three cases, though, the power plants source gas downstream of typical Northeast takeaway constraints on these systems.

Figure 1 | Williams proposed power projects and feedgas pipelines

Columbus Area Project

TC Energy announced that the non-binding open season for its planned 500 MMcfd Columbus Area Project on Columbia Gas (TCO) was oversubscribed by a factor of three. The project proposes moving gas to Ohio customers near Columbus — possibly including Williams for its power plants — from receipt points at Clarington, Majorsville, Waynesburg, TCO Pool, and Leach. The latter two would not source production directly. Instead, they’d pull volumes north that would otherwise flow south on Columbia Gulf. The former two are directly connected to supply but are unlikely to see strong production growth:

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And while mild winter reduces demand just as much as cold weather increases it, the impact on prices is asymmetric. When Henry Hub prices fall below ~$2/MMBtu, prices at supply hubs in the mid-$1/MMBtu range approach short-run operational costs, precipitating producer shut-ins. But no similar feedback mechanism governs price upside.

The result, then, is that the distribution of realistic Henry Hub prices is right-skewed. But that right-skew in prices means that using collars to protect cash flows will increasingly weigh on E&Ps’ earnings, compared with not hedging, purchasing puts, or even traditional swaps.

How and how much are gas E&Ps hedging?

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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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