Morrisey’s announcement completes the puzzle posed by TC Energy’s surprise May sanctioning of the Appalachia Supply Project on its Columbia Gas (TCO) system, backed by a 20-year, ~800 MMcfd contract with an unspecified investment-grade utility. The project had not previously been announced, let alone held an open season.

Now, project details are crystallizing. TCO’s August 3-7 open season included a stylized map illustrating TCO Pool receipts and a delivery point in Grant County. The project targets an in-service date of November 1, 2030. As Appalachian gas-fired generation ramps up, demand at Mt. Storm could push TCO Pool back in line with Midwest hubs rather than Appalachian points.

Why does Mt. Storm need 800 MMcfd of pipeline capacity?

A 2.6 GW power plant only burns ~400 MMcfd at 95% utilization, and Dominion’s Mt. Storm permit application calls for 2033-34 in-service dates for each of the plant’s two units, considerably later than ASP’s 2030 start.

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The project’s two shippers, Duke and Enbridge Gas North Carolina (formerly PSNC), are short FT relative to demand. EGNC should want the capacity as soon as it is available: MVP Southgate can immediately displace its Transco receipts and diversify its supply mix. But MVP Southgate does not reach far enough south to serve most existing Duke plants, and Duke’s Person County combined-cycle project is not due online until 2028.

MVP Southgate will free up Transco capacity to move gas further south. But with Southeast gas burn limited by combined-cycle capacity, that gas will mostly back off eastbound flows through Transco’s Station 85.

How do Duke and EGNC source gas currently?

Duke, EGNC, and Piedmont — a Duke subsidiary since 2016 and the largest North Carolina LDC — overwhelmingly source gas from Transco, directly or indirectly. All three have many physical Transco meters, but each nominates to a single virtual meter. Duke holds Transco capacity, but that gas reaches its plants via either Piedmont’s or EGNC’s distribution system, and sometimes also through Cardinal Pipeline.1

Figure 1 | North Carolina existing gas infrastructure and gas-fired power plants

Only two other interstate gas systems can deliver into North Carolina, but neither moves much. East Tennessee Natural Gas moves gas out of the state via its Transco interconnect, and Columbia Gas delivers ~10 MMcfd into Piedmont in northeastern North Carolina.

What does MVP Southgate do?

After years of legal battles, the ~2 Bcfd Mountain Valley Pipeline (light blue line in Figure 2) entered service in 2024. MVP Southgate (red line in Figure 2) was originally proposed as a 375 BBtu/d downstream extension of MVP, with EGNC (then PSNC) as its lone 300 BBtu/d shipper. When MVP stalled, Equitrans2 paused MVP Southgate development.

Atlantic Coast Pipeline’s cancellation revived MVP Southgate’s prospects, and MVP’s 2024 in-service made it viable. Without ACP, Duke contracted for 250 BBtu/d on MVP Southgate, and EQT upsized the pipeline to 550 BBtu/d. In Duke’s filings with the North Carolina Utilities Commission, the company justifies its capacity commitment as needed to support its existing fleet and backstop future coal retirements and combined-cycle buildout — 6.8 GW of new CCs by 2033, per Duke’s latest integrated resource plan.

In the near term, though, Duke has only one new CC — 1.3 GW at Person County (red diamond in Figure 2) — under construction, with a 2028 in-service date. EGNC is building a new distribution pipeline, T-15 (yellow dotted line), from MVP Southgate to the plant, due in service in 2027.

Figure 2 | Current and under construction North Carolina gas and power infrastructure

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Antero’s Columbia Gas/Gulf path features its lowest rates to LNG-connected markets but also the earliest expiration dates. The fate of Antero’s Columbia Gas/Gulf contracts expiring in October 2027 and June 2028 will reveal both whether the company is optimizing for near-term savings or long-term cost structure and how willing Antero’s midstream counterparties are to negotiate.

Antero’s three paths to the Gulf Coast

On its earnings call, Antero CFO Brendan Krueger said that over the next five years, the company would move from selling two-thirds of its gas in the “LNG fairway” to about half. These disclosures on volume changes and dollar savings, coupled with the latest index of customers data and FERC filings on negotiated rates, narrow down which specific contracts Antero intends not to renew.

Currently, the company holds ~1.9 Bcfd of capacity to the “LNG fairway” via three stacked routes. Most of the capacity — all but the TGP 100 leg deliveries — terminates in premium coastal markets, as shown in Figure 1.

Figure 1 | Antero’s LNG-connected capacity

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But since then, Antero has made three announcements that begin to address this mismatch:

1. A new intra-basin East Side Express pipeline project to move dry-gas volumes from legacy HG acreage.

2. The $315 million acquisition of 125 MMcfed of production and 15 locations in the dry-gas window near East Side Express.

3. A detailed one-off company presentation outlining how declining to renew expiring pipeline contracts would improve the company’s margins and free cash flow.

As I’ll show, East Side Express is the first step in a re-plumbing that will eventually let dry gas volumes feed pipeline capacity originating at Sherwood/Smithburg. Then next week, I’ll break down how the company’s latest disclosures confirm which capacity Antero will let go.

How East Side Express fits

This earnings season, Antero Resources and Antero Midstream announced a 1.5-2.0 Bcfd intra-basin gas transmission project, East Side Express. Antero Midstream said the project would cost ~$100 million annually for the next three years, implying a 2H28 or 1H29 in-service date. A contract with Antero Resources underwrites the project.

The companies did not publish a map but said the project would run 30 miles east-west across Antero’s dry-gas acreage position and feature seven interconnects with gas transmission systems. HG’s legacy gathering system (coral line in Figure 1) also runs east-west, delivering volumes into EGTS (teal line), SGG (purple line), and Equitrans (brown line).

Figure 1 | Antero FT and likely East Side Express route

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Accounting for rising in-basin demand and exports to Mexico, filling that capacity would require 18 Bcfd of dry gas production growth, more than the ~17 Bcfd Appalachia managed in its fastest five-year stretch, from 2011-16. Every gas E&P fears what Permian gas growth could mean for Henry Hub prices. But a record pace of Permian gas production growth would require operators to drill more gas-weighted targets, which Permian E&Ps demurred on this earnings season.

Rather than an expectation that Permian gas production will match the pace of post-FID pipeline buildout, I read this project’s FID as revealing skepticism about Desert Southwest’s effective capacity and its ownership structure as suggesting a change in how Permian E&Ps view the risk-reward of gas takeaway commitments.

Who are the likely shippers?

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Over the first half of this year, the company ran more rigs and as many frac crews as any other operator in the play. With seasonal spreads again as wide as last year’s, Apex’s growth is likely to surge again in early winter.

How did Apex’s production grow last winter?

After the acquisition, Apex immediately ramped up drilling activity, from two rigs in winter 2024-25 to seven rigs by June 2025. The company ran just one frac crew in summer 2025, building DUCs and keeping production flat at ~600 MMcfd. But by December, Apex’s Haynesville volumes surged to ~1.4 Bcfd, deploying several tactics simultaneously to boost production alongside rising seasonal prices.

Figure 1 | Apex production and upstream activity

Deferred TILs and excess DUCs

Although market lore holds that Apex accumulated a large backlog of excess DUCs and deferred TILs, in fact deferred TILs and excess DUCs explain less than half — ~300 MMcfd — of the company’s late-2025 production surge.

Of the 13 pads Apex turned in line between September 2025 and February 2026, only five had completed wells sitting idle for more than 21 days after the last well was completed (purple boxes in Figure 2). These TIL delays were generally modest: less than two months for all but one. And only one of these pads (yellow shading) also saw an abnormally long gap between the rig’s departure and the crew’s arrival.

Figure 2 | Apex spuds, completions, and TILs by pad

Aggressive chokes

An equally large driver was Apex’s aggressive choking of wells that came online in 2H25. Across multiple vintages, those wells’ production peaked in December. Expand’s wells, by contrast, peaked in their second month online.

Figure 3 | Apex and Expand type curves1 by vintage

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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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