Why Oil Prices Are Rising in 2026 — and Your Royalties

Where prices actually sit right now

As of early June 2026, WTI is trading around $95.64 and Brent around $96.65 (June 2-3 settlements). That sounds high until you remember where we just came from: Brent averaged roughly $117 in April and spiked to about $138 on April 7. We are down roughly 30% from the $138 April peak, not at it. So the headline depends entirely on your reference point — versus a $70 February it feels like a windfall, versus an April $138 it feels like a retreat.

The number that matters for planning is not today's tick but the forward curve. The EIA's May Short-Term Energy Outlook pegged Brent around $106 for May and June, then has it easing to roughly $89 in the fourth quarter of 2026 and around $79 in 2027 as Middle East supply is expected to recover. Goldman's Q4 2026 view sits near $90 Brent / $83 WTI, with risks called explicitly two-sided. Translation: the smart money expects today's elevated price to fade, but nobody is confident about the path.

If you only take one thing from this section: 2026 is not a 'high price' year so much as a high-volatility year. WTI has been quoted with a plausible June range from the low $70s to the mid $100s. That spread — not the midpoint — is the real story for anyone weighing a lease or a sale.

Driver one: Iran and the Strait of Hormuz

The dominant driver this year is geopolitical, not geological. Following coordinated U.S. and Israeli strikes on Iran on February 28, 2026, Iran's Revolutionary Guard declared the Strait of Hormuz closed to Western-allied shipping. Tanker traffic collapsed almost overnight — on March 7 a single commercial vessel transited a strait that normally sees around 100 ships a day. Crude that moved through Hormuz fell nearly 30% year over year in the first quarter, to about 14.6 million barrels per day.

Why does one waterway move the whole market? Roughly 20 million barrels per day — about a quarter of all seaborne oil trade — passes through Hormuz, and the alternatives are thin. The combined capacity of the pipelines that bypass the strait is only about 9 million barrels per day. You cannot reroute 20 million barrels through a 9-million-barrel back door. That math is exactly why Brent jumped from $71 on February 27 to $104 by March 9 and on to nearer $120 by late March.

The risk premium has since deflated. A U.S.-brokered ceasefire was announced in early April, and the two sides are reported to have 'mostly agreed' on a 60-day memorandum to extend it — though as of this writing it still needs final sign-off, and there have been fresh flare-ups, including reported strikes around Qeshm Island. That on-again, off-again pattern is precisely what keeps a premium in the price without committing to a direction. Markets are paying for insurance against a re-closure of Hormuz, not pricing a confirmed shortage.

Driver two: OPEC+ is still sitting on the supply

Behind the headlines, OPEC+ remains the largest single hand on the wheel. The group is holding roughly 3.24 million barrels per day of effective cuts off the market — on the order of about 3% of global demand. That is the cushion that, in a calmer year, would cap prices. It also means the cartel has the physical barrels to soften a Hormuz shock if and when members choose to release them.

In March 2026, eight OPEC+ members agreed to resume unwinding the 1.65 million barrels per day of voluntary cuts first announced back in April 2023, starting with a modest 206,000 barrel-per-day step. Critically, they framed the unwind as 'flexible and conditional on market conditions' — meaning it can be paused, accelerated, or reversed. So the supply that could eventually pressure prices lower is real, but its timing is a policy decision made meeting by meeting, not a fixed schedule you can plan a deal around.

For a mineral owner, the practical read is this: the floor under prices is partly a choice. As long as OPEC+ keeps barrels in reserve and the Middle East stays unsettled, the downside is cushioned. The day they decide to open the taps into a calmer market is the day the EIA's $89-and-falling path starts to look right.

Driver three: U.S. shale is responding slowly, on purpose

The classic textbook says high prices summon U.S. shale, shale floods the market, and prices fall. In 2026 that reflex is muted. The Permian still leads the country with about 241 rigs, but the broad signal from public operators has been capital discipline — many planned flat 2026 capex even as prices ran. The U.S. rig count has stayed in the low-to-mid 500s nationally. Wall Street rewards free cash flow and dividends now, not production-at-any-cost growth.

There are exceptions worth naming. Diamondback Energy said it would immediately boost output in response to the rally. ConocoPhillips raised 2026 capex guidance and plans to add a rig in the Delaware sub-basin in the second half. Continental reversed a planned 20% capex cut. Citi has projected public shale could add around 20 rigs and over 100,000 barrels per day of incremental output by 2027 if prices hold — with private operators likely moving faster than the publics.

The takeaway for minerals: do not expect a fast domestic supply wave to crash prices the way it might have a decade ago. New-well breakevens run roughly $62-$70 per barrel (Dallas Fed Q1 2026; the Permian sits around $67), though operating breakevens on existing wells are lower — closer to $40 — so margins above breakeven are historically wide right now, yet operators are choosing measured adds over a sprint. That restraint is part of why elevated prices have held longer than the supply-and-demand fundamentals alone would suggest.

So what does this mean for your royalty check?

Royalties are the most direct line from the oil price to your bank account. Your check is, roughly, production volume times the realized price times your decimal interest, less any deductions your lease allows. When WTI runs from $70 to $95, a producing royalty on a flowing well sees a real, immediate bump — with the usual one-to-two-month lag between the wellhead and the operator's revenue distribution. If you noticed fatter checks in April and May, that April price spike is why.

But realized price is not the screen price. Basis differentials, gathering and transport deductions, and the gas-versus-oil mix on a given well all sit between the Brent headline and your decimal. A volatile year like 2026 also means your checks will be lumpier month to month — that is the price of a market trading on ceasefire headlines rather than steady fundamentals. Don't annualize a single hot month.

Decline curves don't care about geopolitics. A well that is three years into its life is going to keep declining regardless of what Hormuz does. High prices slow the felt impact of decline; they don't reverse it. If most of your value sits in older producing wells, a price spike is a chance to capture cash flow, not a sign your asset base just got structurally more valuable.

Bonuses, drilling activity, and the buy/sell decision

On the leasing side, bonus and rate offers move with sentiment and local rig activity more than with the daily price tape. Texas lease bonuses have generally run from a few hundred dollars to a couple thousand per acre, with competitive plays pushing higher; royalty rates sit in the 12.5%-25% band, and the best Permian acreage commands a 25% rate. A sustained-price view plus nearby permitting and DUC activity is what pulls an operator to the table — which is exactly why watching new TRRC permits around your tract tells you more about your next offer than the CNBC ticker does.

For valuation, remember that buyers underwrite minerals on a forward strip, not on the spot peak. Producing Permian mineral interests have been changing hands in the $10,000-$30,000+ per net mineral acre range, with active-rig proximity driving the top of that band. A buyer in June 2026 is discounting the EIA's own glide path toward $89 and then $79 — so an offer that looks 'low' against today's $95 may be perfectly rational against a $79 strip two years out. Knowing the strip the buyer is using is half the negotiation.

The buy/sell call comes down to what you own and why. If you hold non-producing or speculative acreage and a price-driven offer arrives during a geopolitically inflated tape, that premium is a gift you may not see again once Hormuz normalizes — selling into strength is defensible. If you hold strong producing acreage you want to keep, the same volatility argues for patience and for capturing the cash flow. Either way, the discipline is the same: model your position on the forward curve and your actual decline, not on a headline, and make sure your owner records, lease terms, and offer history are organized enough to negotiate from facts.

That last point is where most independents lose money — not on the macro call, but on walking into a negotiation without their own numbers in front of them. Knowing every tract you own, every offer you've already fielded, and exactly where each deal stands turns a reactive 'is this a good price?' into a grounded counter. A system of record like Scout exists for precisely that: one record per owner, your offers and documents in one deal file, so when a price-driven offer lands you're answering from your data instead of guessing.