The latest emerging play is one that’s been tried before, the liquids-heavy portion of the Utica. In this insight, we’ll dig into this asset using the AFE Leaks Well Cost Database and highlight early trends in this development.
Asset Position
EOG wasn’t the first to develop in the liquids window.
- PDC Energy (2013‑14).
- Focused area: Guernsey Co., Ohio (condensate/oil window).
- Results: High costs, EURs that trailed early type‑curve expectations, poor takeaway in the region impacting differentials, and an oil-price crash.
- Decision: The mid‑2014 price collapse pushed full‑cycle economics below competing projects in the DJ Basin, so PDC redirected capital and ultimately divested the acreage in 2018. (The buyer was not disclosed at the time; the assets now sit with Infinity Natural Resources.)
- Peer activity (pre‑2017).
- Chesapeake, Antero and Ascent also developed in the area, but owned a much broader acreage footprint. Each ultimately concentrated spend in the gassier core, where lower well costs, better takeaway options and stronger single‑stream gas margins delivered superior returns relative to the liquids window.
What changed the equation? Like the Haynesville, improved efficiency in drilling and the ability to drill longer laterals meant that this part of the play was ripe for a redevelopment phase. Additionally, takeaway capacity expanded markedly, improving pricing. And finally, we’re running out of inventory in most known plays, so operators are poking around for anything that may have been given up on a bit too early in the learning curve of shale.
If you know me, I’ve harped about this for years. Because of the SEC 5-year rule, operators have had a defined mechanism for adding reserves each year without actually exploring. Eventually, that illusion runs dry and you have to either acquire or explore to truly grow your reserve base, and much of the scarcity premium trade we’ve seen over the last few years is a reflection of this.
Enter EOG, known for preferring organic inventory build over acquisitions (outside of Yates). As of the Q1 2025 quarterly earnings announcement they are now sitting at ~460k net acres, for a prior-disclosed entry price somewhere in the $0.5 bn range. Previous operators of EOG wells include Chesapeake, Anadarko/OXY, and Chevron, so it’s fair to say they have block-and-tackled their way into this position.
Acreage is estimated using the company provided shapefiles, which are a bit aggressive compared to actual net acreage, and intersecting with PLSS shapefiles available via the Ohio DNR. We typically use an intersection threshold of somewhere around 30-40%, and then adjust visually. Net acreage is then calculated by adjusting gross acreage to reported nets (in this scenario, prior disclosures of the North/South allowed somewhat better estimates). So, for the rest of this report, acreage calculations largely use this methodology and may differ from actual owned acreage.
EOG breaks the position down into four phase windows (Black Oil, Volatile Oil, Wet Gas, Dry Gas), which is a bit less than the 7+ other operators have used to better delineate yields, but for the sake of profiling we’ll keep with their definition.
~80% of estimated acreage is in the Oil window
Bulk of acreage needs delineation
The bulk of the acreage is not delineated, though on a percentage basis, the Black Oil wedge is the least developed. Historical well performance in that zone has been consistently poor—primarily due to limited solution gas drive, which hampers flow to surface. Given those results, it’s unlikely that this area will attract much capital in the near term.
Midstream Buildout
A big part of why the oil window didn’t get much love historically came down to two things: prices were bad, and the differentials were worse. While the front-end strip has improved (well, had improved before the tariff tantrum), the real shift has been on the infrastructure side. Both gas and liquids takeaway have improved meaningfully since 2015 — enough that the netbacks today look very different from when PDC and others first gave it a go.
Gas: Getting Out of the Basin
Back in 2015–2016, a handful of smaller expansions helped chip away at the constraints:
TETCO’s OPEN project added ~550 MMcf/d to the Midwest
Columbia’s East Side expansion helped move another ~310 MMcf/d into the Mid-Atlantic
Projects like Broad Run Flexibility and Leidy South quietly opened more flow to the Gulf
But the big change came in 2017–2018, when REX Zone 3 flipped direction (moving up to 2.6 Bcf/d westward) and Rover came online, eventually adding 3.25 Bcf/d to the Midwest and Dawn. That’s when basis differentials — the infamous Dominion South and TETCO M2 blowouts — really started to tighten.
Most recently, in 2024, the long-delayed Mountain Valley Pipeline (MVP) finally got built. That opened another major release valve to the Southeast. Collectively, it means that Utica gas now has a lot more ways out, and basis blowouts have been replaced with something approaching normalcy.
Liquids: From Local Discounts to Export Pricing
The condensate and NGL story has quietly improved just as much — maybe more.
The Mariner East 2/2X system brought C3+ barrels all the way to Marcus Hook by 2020–2021, letting Appalachian operators tap into international pricing
Shell’s Monaca plant finally started pulling real volumes of ethane (~100 Mb/d), which had mostly been rejected prior to 2022
Several splitters and rail terminals went in to move stabilized condensate to the Gulf Coast (or refine it in-basin), reducing the local discount drag
Global LPG demand has also lifted propane/butane netbacks, especially post-2020
Back in 2014–2016, Appalachian propane was lucky to fetch $10/bbl, and condensate regularly traded $10–20 below WTI. Ethane was nearly worthless unless forced into the pipe.
By 2023–2025, propane was clearing at $25–35/bbl, condensate was approaching parity with the Gulf, and ethane was being sold, not rejected. The NGL uplift that EOG, Encino, and others are chasing is real — and it’s structurally supported by export capacity, local demand, and better infrastructure.
Activity/Well Design
Overall well activity has been declining with an un-supportive gas price environment, though EOG has trended higher.
EOG Spud 16 wells in 2023 and 25 in 2024, as they continue to delineate the position.
Average lateral lengths in the play have continued trending higher, though the last few years has seen a slight leveling off. It appears we are nearing the technical limits of development.
EOG has been developing at a higher average proppant loading than peers in the play.
Casing design for EOG is consistent on a county basis. For Carroll/Harrison they usually run a 20” conductor to 150 ft, 13-3/8” Surface to ~1100, 9-5/8” Intermediate to ~1600 (not sure what they’re covering in that 500 ft), and then 6” production casing down to TD. For Noble, they have been running the Intermediate section down to ~7000 ft.
How does productivity change with lateral length increases in the Utica?
We can investigate this at a high-level by setting a few conditions.
- Compare performance of 3-mile laterals to offsets
- Wells with first production between 2018-2022
- Offsets to target well must be within 3 miles of location
- Bin each comparison scenario by lateral length range (ie 1, 1.5, 2, 2.5 mile offsets)
Based on high level analysis, reduction in performance by going from a 1 mile to a 3 mile location is ~20% on a per-ft basis, while the reduction from 2-miles to 3 is ~7%. That performance continues to trend similarly as laterals move even higher (ie 3.5 milers underperform 3 milers).
Most of the wells that went into the analysis are in the Dry Gas window. In other plays, the reduction in performance for more oil-weighted assets can be more severe, so there is some risk that performance will be impacted more negatively in the condensate/oil windows here.
While the reduction in performance is noticeable, this is usually offset by capex spend. In scenarios that we have evaluated in the past, even if 2-mile performance on an individual well F&D basis is better, reduced environmental impact and potential to share facilities can sometimes call for the 3-mile units, especially in large, concentrated positions.
Cost Benchmarking
EOG reported $/ft costs of somewhere in the mid 600’s in the quarterly preso, which aligns well with AFE cost estimates. In general, 3-mile laterals have been in the $11 mn range and 4-milers around $13 mn.
Q4 2024 AFE’s are right in-line with EOG’s reported Q1 2025 actuals.
The best comparison of 3-4 mile capex savings expectations are probably looking at Q1 and Q2 2024, where cost-per-ft expectations dropped ~6% while lateral length increased from 15,600 to 19,600. Given the productivity decrease mapped out earlier of 4%, this may be an indication that those wells can make more sense economically, though this assumes no execution risk for even longer laterals.
Productivity
There are two ways to look at this. First, more broadly, the cost disclosures in Ohio include a company-provided estimate of EUR, so we will take a look at how well performance looks versus predicted for wells brought online with at least 12 months of production.
All generally underperform their disclosures to the state, but at the very least EOG is closer than the others.
Full disclosure, EOG only has 4 wells in this dataset as the majority have been producing less than a year. Similarly Antero and Infinity are only sitting with 5, while the remainder have many more wells, but is telling that the default is to over-estimate productivity.
Now, we will dig a bit deeper into actual productivity for the three main areas that EOG has developed on the acreage.
Based on the productivity map, we would expect the southern wells to perform worse, followed by the north, and then the strongest performance to come from the central portion of the asset.
As we see from the map, cumulative production (adjusted to 16,000 ft lateral lengths) shows a wide disparity between the areas. The south has been poor, while the Xavier lease in the Central part of the asset has been quite strong.
Initial results do align with the productivity map with poor performance down in the south, while I’d presume the Northern acreage looks somewhat disappointing also. We are early into results, so we’ll need to keep an eye on various developments to see how it progresses. It is a large position with plenty of areas that need to be delineated.
PSA: Despite how strong of an operator EOG is, they do have a reputation for opening chokes much more aggressively than others, so don’t put much stock in IP disclosures. When they drilled there one and only Louisiana Austin Chalk horizontal, the huge reported IP spurred a rush to lease the play and subsequently destroyed a ton of others’ capital.
For this section, I will leave you with the EUR productivity map with the acreage position overlain.
Conclusion
The opportunity EOG sees here is clear: a massive, under-developed position in a liquids window that got overlooked the first time around. They’re betting that longer laterals, tighter execution, and improved midstream can unlock something PDC, Chesapeake, and others couldn’t.
And to their credit, they’re doing it in typical EOG fashion — organically built, blocky acreage and a willingness to scale fast if the results hold.
But the rocks don’t lie. A lot of this acreage is still untested, and early returns are mixed at best — especially in the Black Oil window. Productivity degrades as laterals stretch, and while the cost-per-foot improves, there’s always risk in pushing technical limits, especially in high-pressure shale.
Still, the game has changed since the 2014 vintage. Liquids are clearing at international pricing. Gas isn’t trapped in-basin anymore. And with most of the core U.S. plays inventory-constrained, even a Tier 2 rock can start to look investable again — if you can drill it right.
If EOG can prove out the middle part of this position, this could be a real asset. But it’s still early days, and this isn’t the Delaware — it’s the Utica, and the bar for calling something “core” should stay high.
