Who ends up with Coterra's Marcellus asset?
This comes down to more than just rock quality
Kimmeridge has now said out loud what the market has expected since the Cabot–Cimarex1 deal was announced: the Delaware and Marcellus assets don’t belong together. The company’s Delaware production will keep growing, whether as part of a slimmed-down Coterra or folded into a larger Permian portfolio. The more interesting question is the northeast Pennsylvania position — because in a constrained, mature basin, the value drivers are different and depend on midstream alignment as much as remaining inventory.
Which is why the buyer universe gets very small, very quickly.
A small universe of potential buyers
Northeast Pennsylvania operators in general — not just Cabot/Coterra — have limited remaining Tier 1 inventory2 and some of the most challenging marketing conditions in North America. The northeast Pennsylvania micro-basin constrains at times, and it sits inside a broader Northeast bottleneck, both of which typically worsen when Henry Hub prices rise.
These challenges are so severe and so well-known that they likely preclude out-of-basin buyers of the Cabot asset, specifically, but also of any other major assets in the basin.3 All of the other recent, major deals in the area — Chief’s sale to Chesapeake, Alta’s exit to EQT, Southwestern’s merger with Chesapeake — have been to other Marcellus players. And for the Cabot asset, the most natural Appalachian acquirers are those same two companies: EQT and Expand. Antero, Range, and NFG/Seneca are plausible options, but these companies are significantly smaller. Also, the former two have historically favored organic growth over acquisitions, while NFG’s utility investors4 may be reticent to buy such a large E&P.
The under-the-radar importance of wellhead gathering
But I don’t see EQT as a serious contender here. Since Toby Rice assumed control, EQT’s sizable upstream acquisitions — Olympus, Tug Hill, and Alta — included gathering assets. EQT’s Equitrans acquisition — and everything it has said since — make clear that controlling wellhead gathering is now a strategic priority for the company.
Antero, CNX, and Seneca all have their volumes gathered by related5 midstream entities. As do Appalachian privates like HG and Snyder Brothers, and IOCs like Repsol.
In today’s era of capital discipline, it is most efficient for E&Ps — not just those in Appalachia — to own their wellhead gathering. Unlike transmission, where gas volumes can and do flow in different directions depending on market conditions, wellhead gathering is, functionally, part of the upstream asset.
The midstream operator bears the upfront capex of building out a system of trunklines that’s only economic if the E&P continues to produce in that area for a long time. That typically means the midstream company insists on increasing rates over the life of the contract and/or minimum volume commitments. But the E&P bears the commodity price risk, and those rising rates and MVCs often incentivize suboptimal capital allocation during downward price cycles.
And the conditions in constrained Appalachia support E&P-gathering integration even more so:
Transmission constraints mean that production is not growing much, whereas in a play like the Haynesville, the gathering capex requirement could be less tenable for E&Ps
E&Ps bear not just significant commodity price level exposure but also major basis risk
In an environment of limited inventory, like in northeast Pennsylvania, midstream operators are highly exposed to potential volume declines
All roads lead to Oklahoma
So the corollary to its being efficient for E&Ps to do their own wellhead gathering in this era of capital discipline is that it may also be most efficient for midstream operators to own the upstream assets where they have significant pipe in the ground and therefore capital at risk. Put differently: E&Ps are exposed to declining inventory, but their midstream counterparties are more exposed — in this case, Williams, which I think is the most logical buyer of Coterra’s Marcellus position.
Yes, Williams has recently (again) been an upstream seller, with a $1.5 billion sale of its Haynesville joint-venture asset6 to JERA announced last month. But it’s consistent for a midstream operator to want to exit a capital-intensive, growing E&P while still being interested in owning a more mature and capital-efficient upstream position — especially where it already has such a strategic interest.
Williams doesn’t break out volumes within its Northeast G&P segment, but I estimate the company gathers 2.5-3.0 Bcfd on the Susquehanna Supply Hub.7 Overall, Williams’s Northeast G&P business gathered about 10.8 Bcfd and generated $500 million of EBITDA in 3Q25.
Beyond this gathering exposure, Transco could also be affected if Coterra’s production were to decline. The 350 BBtu/d of capacity Coterra holds to the Dominion Cove Point interconnect at Pleasant Valley isn’t at risk, given that northeast Pennsylvania is likely to remain the cheapest source of feedgas for Cove Point offtakers.
But Coterra also holds 750 BBtu/d of capacity to River Road, where the new Central Penn Line portion of Transco interconnects with the legacy mainline. Two-thirds expires in 2033 and one-third in 2036. All of this capacity8 is vulnerable to not being renewed if production declines, given that it terminates in a market that is upstream of typical Transco constraint points.
Sure, Williams could offer to negotiate its contracts with a potential upstream buyer — most likely Expand — to ensure this asset is competitive in the acquiring company’s portfolio, and that production doesn’t decline. But in a constrained basin, such alignment is genuinely difficult, for both the E&P and the midstream operator. For Williams, as with EQT, I expect vertical integration to deliver the best risk-adjusted returns.9
Call it a reminder that in Appalachia, the midstream always has its say, too.
Fun fact that I recently relearned while reading a research note that screened the deal as one of the best of the last 10 years: it was technically structured as an acquisition of Cimarex by Cabot.
But nonetheless, plenty of inventory to make the assets worth considerably more than their PDP value
Especially given how the Cimarex foray went
Seneca is the E&P division of National Fuel Gas, which unlike any other Appalachian E&P, also owns a gas utility. The company recently announced the purchase of another gas utility.
The exact financial structure varies, but in all three cases, these three midstream entities overwhelmingly serve the related E&P
Williams got this asset in the Chesapeake bankruptcy settlement, which should also tell you something about midstream exposure to E&Ps
The vast majority (maybe even all) of Coterra’s northeast Pennsylvania production is gathered onto this system. In the third quarter, Coterra reported net northeast Pennsylvania production of 2.1 Bcfd, and royalty rates are typically 20-25%.
500 from the same Atlantic Sunrise project as the tranche to Cove Point and 250 from the 2021 Leidy South project
The true galaxy-brain synthesis is for Williams to roll up Expand, but that’s another post for another day