The Bighorn Basin sits between the Bighorn Mountains and the Absaroka Range in northwest Wyoming, extending north into south-central Montana. Its oil is trapped in large surface-mapped anticlines — Oregon Basin, Elk Basin, Garland, Grass Creek, Hamilton Dome — that were among the earliest structures drilled in the Rockies. Several were discovered before 1920 and have been under waterflood or pressure maintenance for more than half a century. The basin's defining characteristic for a mineral owner is longevity: production per well is modest, but the injection-supported decline is unusually flat, and these fields have paid royalties across generations. We buy mineral rights, royalty interests, NPRI, and ORRI throughout the Bighorn Basin.
Approximate location of the Bighorn Basin shown in tan
Basin-level activity chart not yet available for the Bighorn Basin. For current activity, see our rig count dashboard and the state production pages linked above.
The Bighorn Basin is an asymmetric Laramide structural basin, deepest along its western margin and rimmed by steeply folded strata. The principal reservoirs are Paleozoic: the Pennsylvanian Tensleep Sandstone and the Permian Phosphoria Formation carry most of the production, with the Mississippian Madison Limestone productive on several structures and the Cretaceous Frontier and Muddy sandstones contributing at shallower depths. The traps are large, simple, four-way anticlinal closures, which is why they were found early — many were identified from surface geology before the seismic era. Reservoir quality in the Tensleep is good enough that waterflooding has been effective for decades.
The basin's operator base is concentrated among companies that specialize in mature waterfloods rather than new drilling. Merit Energy has been associated with Oregon Basin and Hamilton Dome, and a mix of smaller independents holds the remaining structures. Because the economics here depend on injection management and workover discipline rather than on drilling inventory, operator quality has an outsized effect on how long a field keeps producing and what a royalty interest is worth.
Bighorn Basin mineral values are driven by the stability of injection-supported production rather than by drilling upside. A tract inside an active unit with a well-run flood can generate steady income for a very long time, and that durability is the asset. Key factors are whether the tract is inside a participating unit, the unit's tract participation factor, current injection and production rates, and the operator's commitment to the flood. Undeveloped acreage carries less weight here than in a shale basin, because new drilling is limited. Heavy or sour crude in parts of the basin can also widen the differential to benchmark pricing.
Most of the large Bighorn fields are unitized, meaning the separate tracts over a reservoir are operated as one property so a waterflood can be run across the whole structure. Your royalty is then paid on a share of total unit production based on your tract participation factor, rather than on wells physically located on your land. This is why you can receive checks without a well on your acreage, and why the participation factor is one of the first numbers we ask for when valuing a Bighorn interest.
Longer than most people expect. Several Bighorn structures have been on injection since the 1950s and 1960s and still produce. A mature waterflood declines slowly and predictably as long as the operator keeps injecting and maintaining wells, which is a different risk profile from a shale well that loses most of its rate in the first two years. The main risks are operator neglect, a sustained low price environment that makes injection uneconomic, and eventual mechanical limits on old wellbores.
Frequently, yes. Parts of the basin produce heavier or more sour crude than the light sweet barrels that set benchmark prices, and Rocky Mountain production sits far from Gulf Coast refining, so transport costs are deducted as well. The result is a differential to WTI that shows up directly on your check stub as a lower realized price. It is a normal feature of the basin rather than a sign that something is wrong, and we account for it explicitly when we underwrite an offer.