Market Data
WTI and Henry Hub are the two benchmark prices most US mineral owners encounter, but the price your royalty check is settled at almost never equals either one. WTI is a Cushing, Oklahoma delivery price for a specific crude grade; the crude actually produced from your minerals trades at a differential to WTI based on basin, gravity, sulfur content, and pipeline connectivity. Permian crude has historically traded at a premium to WTI when Cushing is oversupplied and a discount when Midland egress is constrained. Bakken crude carries its own differential driven by rail economics. Eagle Ford condensate trades on a different basis again.
Henry Hub is even more divergent from the price actual gas producers receive. Appalachian and Permian gas frequently sells at a discount to Henry Hub because pipeline capacity doesn't match production; Haynesville and Eagle Ford gas tend to track Henry Hub more closely thanks to better LNG and export pipeline access. The spread between Henry Hub and your actual realized price is one of the most consistently under-appreciated drivers of royalty income.
For mineral owners deciding whether to sell or hold, the useful question isn't “where will WTI go” — it's where the spread between WTI and your specific basin's realized price will go. Many of the largest royalty surprises (positive and negative) we've seen in our held portfolio have come from midstream changes — a new pipeline opening, a takeaway constraint lifting — rather than from headline commodity-price moves.
The world oil supply and demand chart above shows annual balances back to 1980. The most reliable pattern in 40+ years of data is that tight balances (supply just barely keeping up with demand, or trailing it for stretches) precede multi-quarter strength in WTI, while loose balances precede stretches of weakness. The lag between balance and price is usually two to six months for crude — long enough that mineral owners watching only the spot price are typically reacting to old information.
For natural gas, the global market still translates loosely to domestic Henry Hub prices because most US gas is still consumed domestically. That's changing as LNG export capacity continues to grow — each new export terminal coming online pulls Henry Hub toward global TTF-equivalent pricing — but the relationship is far from one-to-one. Gas mineral owners benefit asymmetrically from this shift: rising global gas demand lifts Henry Hub, but additional pipeline capacity to export terminals also widens or narrows your basin's discount to Henry Hub depending on which basin you're in.
For mineral owners considering a sale, the price chart is background. The variable that moves an offer most is whether the underlying tract is currently producing and what its decline curve looks like. Pointer's underwriting starts with the tract, not the headline price — though both feed in. If you'd like to see what your specific tract looks like against current price assumptions, send us the basics and we'll come back with a number within 48 hours.
WTI is a Cushing, OK delivery price for a specific crude grade. Your operator typically sells your basin's crude at a differential to WTI — usually a discount, since most basins are inland and the price has to absorb transport to market. The differential is reported on most check stubs as the “price” line; subtract it from prevailing WTI to verify.
Indirectly. Your operator sells gas at the basin's local index price (Waha for the Permian, Dominion South for Appalachia, Houston Ship Channel for Eagle Ford, etc.). Local indexes correlate with Henry Hub but can diverge significantly when pipeline egress is constrained. The check stub typically shows the index used.
Direct buyers like Pointer typically apply forward-strip pricing for the first 18–24 months and a long-term price thereafter (often the back-end of the strip or a consensus deck). Offer ranges respond more to the long-term assumption than to the spot price, since the bulk of any producing tract's value sits in years 3–15 of the decline curve.
There's no universal answer — it depends on your tract, your basin, current operator activity, and your personal liquidity needs. We don't pressure sellers to decide. The most reliable signal we've seen across our held portfolio: tracts with recent permits or active drilling within two miles tend to see the strongest offers, regardless of where headline WTI is.