Background
The Cherokee interval in Northwest Oklahoma has long been known to operators but historically underdeveloped. A combination of stronger pricing, higher drilling efficiency, and inventory exhaustion elsewhere has reignited interest in the Western Anadarko Basin (WAB). This report explores recent activity, well design trends, productivity, and half-cycle economics — with a focus on Ellis, Roger Mills, and Lipscomb counties.
Most active in the play are Mewbourne, Crawley and Sandridge after its’ purchase of Upland in Q3 2024 for $144 million.
This analysis will examine this development in more detail, particularly by looking at well economics using our Well-level AFE Costs and existing public data.
AFE Leaks focuses on providing detailed AFE/actual development costs across the Lower 48, with capex data across 92,000+ wells.
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Asset Position
Though the play does apparently extend down into Dewey, the bulk of the development is in Ellis and Roger Mills of Oklahoma and Lipscomb in Texas and that’s where the focus of this insight will be (largely the circle in the Sandridge announcement). The defined core of the play remains limited, with roughly 300,000 net acres located within 1-mile of existing horizontals. Producers boasting positions here are Mewbourne, Maverick (via Unbridled), Sandridge (via Upland), and Crawley, with some wells drilled by others. Given the limited number of operated wells despite a large footprint, Maverick appears to be participating as a non-operated partner in most activity.
Mewbourne has been the most active operator in the play by far
Activity/Well Design
Activity ramped hard in 2023/2024, and it will likely continue at least through Q1, though recent declines in WTI may push rig counts lower in the second half. Standard well is a 2-miler, with proppant loads moving up from ~1500 lb/ft in 2021 to ~2400-2700 since 2023.
| Surface |
~700 ft |
13.375 in 54.5# J-55 |
| Intermediate 1 |
~2,000 ft |
9.625 in 36# J-55 |
| Intermediate 2 |
10,000 ft |
7 inch 26# P-110 |
| Production Liner |
9,500 ft-TD |
4.5 13.5# P-110 |
| Tubing |
~10,000 ft |
2.375 in |
Casing design is generally consistent across operators.
Pricing
Oil
API gravity is somewhere in the 45-50 range for most of these wells.
As compared to the Permian, which receives very close to WTI, these lighter crudes can expect a 3-5$/bbl discount.
Gas
From the wells with available cost data, shrinks are in the 72-78% range, with NGL Yields at ~100 bbl/mmcf.
NGL Prices dropped hard from over 40% of WTI in late 2023 to ~30% in late 2024, resulting in the compression of realized pricing vs Henry Hub. For the trailing 12 months with full data, NGL Prices averaged 37.5% of WTI and Gas Prices were 97% of Henry Hub, while the last quarter of data was 31% and 81% respectively.
Cost Benchmarking
Since late 2023, costs have largely settled at the $10.5 Million range, with pre-production casing costs (DHC) between 4.1-4.2 Million. With steel prices starting to increase with tariffs, we would expect upward inflation on these costs in 2025.
On the capex side, AFE Leaks has AFE-level Drilling and Dry-Hole Costs across 81 wells with existing API’s. More exist, but we generally wait until a well has been identified via public data before moving it to the database.
The Upland AFE’s (now Sandridge) were well above the depth vs cost trend when looking at 2-milers.
Productivity
Productivity looks to be increasing dramatically as we head south. The real question will be how far this play can be extended to the east towards Dewey.
Crawley wells are well above play average
Mewbourne’s acreage covers the bulk of the play, with exposure to the more productive areas.
Sandridge’s northern wells were poor, though they do have some exposure to the more productive parts of the play. If they can extend the play to the south and east, then their acreage is well-primed to take advantage.
Not a large position, but Crawley’s wells have been strong.
Economics
Water data is a little scarce. On the Texas side, for newer wells, there has only really been once test cycle (the W-2), so still waiting for annual test data to come in. Oklahoma reports initial tests, but it is generally less than 5 days after flowback so it is probably still producing back slickwater. The furthest out tests are around a 3 WOR, while the latest test on the Texas side is about a month after initial production, and WOR is at 1.65. For the purpose of our model, that is where we will settle, but some room for error.
Table: Assumptions Used in WAB Economic Model. These inputs represent half-cycle assumptions unless otherwise noted. Sensitivity to NGL pricing and WOR is high, given the gas-rich nature of the system.
| NRI |
% |
75 |
| WTI |
$/bbl |
60 |
| Henry Hub |
$/mcf |
3.7 |
| Fixed Monthly Opex |
$ |
10,000 |
| Variable Expense Oil |
$/bbl |
0.5 |
| Variable Expense Gas |
$/mcf |
0.1 |
| Variable Expense Water |
$/bbl |
1 |
| Oil Differential |
$/bbl |
-3 |
| Gas Differential |
% HH |
81 |
| NGL Price |
% WTI |
31 |
| Gas Marketing |
$/produced mcf |
-1.4 |
| Drill Capex |
$000s |
4,500 |
| Complete Capex |
$000s |
5,500 |
| Facilities Capex |
$000s |
500 |
| Tax |
% revenue |
2% (36 months)/7% after |
| GOR |
mcf/bbl |
9.2 |
| NGL Yield |
bbl/mm |
100 |
| Shrink |
% |
72 |
| Water-Oil-Ratio |
bbl/bbl |
1.65 |
Obviously these assumptions can change, but for the sake of modelling we have to choose something. Given the companies are private or do not separate the regions in their financials (Sandridge), it is difficult to get actuals, though I doubt it’s too far off from here.
At $60/3.7 WTI/HH, the median well generates a sub-10% return. Using 12-month BOE/ft as a proxy for IRR and at current cost and pricing assumptions, wells delivering >17.5 BOE/ft are likely to exceed a 20% IRR threshold. In a $90 WTI environment, a 12-month BOE/ft value of 13 equates to roughly 20% IRR.
Conclusion
The Western Anadarko Basin (WAB) Cherokee play remains early in its development cycle. While results vary, there is a defined corridor of strong productivity where returns are decent. However, given the small acreage footprint, this is not yet a “buy everything” play until operators are able to test the limits of the play to the east. If proppant loading and well placement continue to improve and oil prices remain constructive, it has the potential to grow into a meaningful Tier 3 area with selective Tier 2 pockets, but economics still fall well behind core Permian.
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