Stop Waiting for Normal: Fuel Market Decisions in the New Equilibrium 

When clients ask us about the Iran war, the question that comes up most often is some version of when, and how, things get back to normal. Our view today is that a return to pre-war conditions is not the right framing for what comes next. The crude market will normalize faster than products, the product market will lag for months, and a risk premium may be baked into the forward price curve for the foreseeable future. The useful question for the next 30 to 90 days is not when prices come down but what shape the new equilibrium takes, and which client decisions get reshaped along with it. 

Stillwater first weighed in on the Iran war’s fuel market implications in a March article by Stillwater’s President, Megan Boutwell, which argued that the simple oil-shock framing missed the real dynamics, and that jet fuel, liquefied natural gas (LNG), and the West Coast were the actual pressure points. The piece closed with five items we said we would be watching: the Ras Laffan timeline and its aviation implications, West Coast supply routes, Low Carbon Fuel Standard (LCFS) credit markets and biomass-based diesel (BBD) dynamics, the Northern Hemisphere LNG injection season, and Trans Mountain Expansion (TMX) flows. A team of Stillwater senior subject matter experts recently gathered to work through where each of those threads stands today as well as new issues. What follows is a look behind the curtain at that conversation – the data points we are tracking, the analytical questions we are wrestling with, and what the picture means for the decisions clients are weighing right now. 

Jet fuel and aviation: from pressure point to defining story

https://www.hydrocarbonprocessing.com/news/2026/03/shell-says-pearl-gtl-facilitys-train-two-in-qatar-requires-around-a-year-for-full-repair/The aviation consequences anticipated in March are now visible in the data, and the picture is more asymmetric between Europe and the U.S. than the trade press has generally characterized. The shortfall reflects the broader loss of Middle East and Asian supply into the global jet pool rather than damage at any single facility – Shell’s Pearl Gas-to-Liquids (GTL) facility at Ras Laffan, where Train 2 will require roughly a year to repair, is one component of that impairment and a useful reminder that a Strait reopening will not restore pre-war kerosene flows on day one. 

The European jet outlook is quite challenged. Goldman Sachs research projects European commercial jet inventories will fall below the International Energy Agency’s (IEA) 23-day storage threshold sometime in June, with the United Kingdom most at risk of rationing. Italy began issuing fuel uplift advisories at several airports in early April 2026. 

The U.S. story is more stable. California refiners increased jet fuel output from roughly 285,000 barrels per day in March to more than 300,000 barrels per day in April, while cutting California Air Resources Board (CARB) gasoline production by 32,000 barrels per day to chase the widening jet crack spread. California jet inventories nevertheless fell to 2.6 million barrels in April, the lowest level since November 2023, as refiners worked to offset the loss of imported Asian cargoes.  

Another supply-side lever stabilizing California’s fuel supply is Jones Act waivers, which temporarily allow foreign-flagged tankers to ship Gulf Coast jet fuel (and gasoline) cargoes to West Coast ports. These routes are normally closed to non-U.S.-built, -flagged, and -crewed vessels. With Asian refineries short crude and product, these waivers have allowed Gulf Coast refiners to take advantage of arbitrage to the West Coast that’s normally closed. We note that waivers do not change the underlying inventory math, but they do widen the availability of barrels to supply the shorts; we cover the scenario implications in our client work, discussed further below. 

Unusual product market conditions for refiners and traders

Cracks on the West Coast have reflected the unusual market conditions worldwide. The gasoline crack has held above $40/bbl, while the jet and diesel cracks have averaged $65 and $57, respectively. In our assessment, gasoline and jet should stabilize to an import basis from the Gulf Coast while diesel will price at an export basis to the Asia-Pacific market. These unusual pricing and trade flow conditions create unusual incentives for West Coast refiners and suppliers. 

For West Coast clients, the implication cuts two ways. Refiners pushing yield toward jet is a partial buffer against an outright physical shortage. The same shift decreases gasoline barrels at the margin (functionally, cutpoint changes plus hydrocracking instead of catalytic cracking). In addition, sky-high diesel prices in the Asian market further create incentives for distillate production over gasoline with a highly unusual, profitable diesel outlet. These market forces are part of why California gasoline prices have remained elevated even as some import flows have resumed. Whether the marginal jet and gasoline molecules come from a U.S. refinery running flat-out for the crack spread margin, a Gulf Coast vessel under a Jones Act waiver, or from a constrained Asian cargo has direct implications for hedging windows over the next 30 to 90 days. 

West Coast crude supply: cargoes, slate, and the limits of TMX

Most coverage of the West Coast picture has focused on lost cargoes of refined product from India and South Korea. The more useful question for refiners is whether the remaining plants can technically run the crude slate they can actually source. Roughly 8 percent of U.S. crude imports in 2025 came from the Middle East Gulf, with the West Coast (PADD 5) absorbing 47 percent of that volume. With Persian Gulf crude supply materially reduced, those barrels need to be replaced. 

The constraint is concentrated. Chevron’s Richmond Refinery is the West Coast refinery most dependent on Middle East crude due to lube plant compatibility constraints, with Marathon Carson and Chevron El Segundo running smaller volumes for chain optimization. Richmond’s ability to substitute is structurally tougher because Latin American and Canadian crudes are too aromatic for lubes manufacturing. West African grades are a partial substitute; Guyanese crude is another candidate, though run economics depend on cost and yields relative to sourcing constrained Middle East barrels through Yanbu.  

The pre-war baseline against which any substitution is measured was itself sub-optimal – sanctions on Iranian, Venezuelan, and Russian barrels, drilling constraints in the San Joaquin Valley, and the shutdown of the Outer Continental Shelf (OCS) Platforms in Santa Barbara distorted the West Coast slate for years before the current conflict. The delta between a normal slate and a feasible one under current sourcing constraints, and what that delta means for finished product yields and cracks, dictates how refineries and traders should analyze crude slates and product arbitrage between the West Coast and other markets.  

Trans Mountain Expansion is a relevant data point here, but not a swing supplier, nor a one-for-one barrel substitution for Middle East crudes. Trans Mountain’s full-year 2025 results showed total system throughput averaging 761,000 barrels per day on 890,000 barrels per day of nameplate capacity, for an annual utilization rate of 86 percent. Fourth-quarter utilization reached 91 percent, with record throughput of 807,000 barrels per day, including 203,000 barrels per day to Washington State via the Puget Sound Pipeline. Light crude movements to Washington State have held steady near 200,000 to 250,000 barrels per day with limited variability. For waterborne scheduling purposes, utilization in the high 80s is near capacity. Optimization projects could eventually add up to 300,000 barrels per day, but those are 2027-and-beyond solutions. For clients modeling West Coast supply for the next 90 days, TMX is a stable contributor – not a marginal source of additional barrels. 

LCFS and biomass-based diesel: the March thesis holds, with new cross-currents

The Environmental Protection Agency (EPA) finalized its Renewable Fuel Standard (RFS) Set 2 rule on March 27, 2026 (published in the Federal Register April 1), with an effective date of June 15. The final rule established record-high Renewable Volume Obligations (RVOs), including BBD volumes of 9.07 billion Renewable Identification Number (RIN) gallons for 2026 – nearly 70 percent above the 2025 applicable volume. The mechanics matter more than the headline volumes: if gasoline demand falls faster than diesel under sustained high pump prices, the ethanol pool that absorbs the conventional (D6) obligation shrinks, leaving a shortfall that has to be filled with D4 BBD RINs, putting upward pressure on BBD prices. 

Stillwater’s published LCFS credit pricing tracker shows 2025 year-to-date credit prices averaging $57 per metric ton (MT). Separately, Portland’s renewable fuel program has raised its carbon intensity (CI) ceiling for BBD – partly in response to high Oregon credit prices and concern that Portland is a harder market to attract low-CI BBD volumes to when overall demand is suppressed.  

LNG injection season: the winter setup is the next pressure point

QatarEnergy estimated that broader damage to Ras Laffan – including LNG Trains 4 and 6, roughly 17 percent of Qatar’s LNG export capacity – would take three to five years to repair, prompting force majeure declarations on long-term contracts. Our March piece flagged the Northern Hemisphere LNG injection season as the item most likely to determine whether the current disruption becomes a multi-winter problem. Two months in, the answer is that it is too soon to know definitively, but the early storage data is not encouraging. European Union (EU) gas storage stood at 28.48 percent of capacity on March 21, 2026, compared to 33.80 percent at the same point in 2025 and 59.26 percent in 2024. With Ras Laffan force majeure in effect and Qatari LNG removed from the global pool for an extended period, Asian buyers are competing more aggressively for non-Qatari cargoes – pulling supply away from European storage rebuilds during the window when those rebuilds need to happen. 

The risk on the U.S. side sits in the Northeast. Even a normal winter (not a particularly cold one) would draw storage below where current refill trajectories can replace it. Taiwan has signaled that it will prioritize semiconductor manufacturing power load (potentially at the expense of residential utility supply), which is a useful indicator of how Asian demand will be triaged if the supply picture does not loosen by autumn. This is the watchlist item most worth tracking through the summer; we expect to update on it in subsequent pieces as the storage and contracting picture clarifies. 

The path back to normal … and why it doesn’t actually come back

Valero, on its first-quarter 2026 earnings call, framed the recovery dynamic as roughly three days to rebuild light product stocks for every day the Strait has been closed. The closure has run roughly 90 days as of this writing, implying something like nine months of recovery time from the moment the Strait reopens. The longer the closure persists, the more conservative that ratio becomes. Baker Hughes assumes the Strait may not fully reopen until the second half of 2026; a Dallas Fed Energy Survey published in late April found that nearly 80 percent of oil and gas executives surveyed do not expect the Strait to reopen until August or later. Rapidan Energy Group has framed the scenarios more sharply: its base case assumes a July reopening with average oil demand reduction of 2.6 million barrels per day and Brent peaking near $130 per barrel over the summer, while a disruption running through August would deepen the third-quarter supply deficit to roughly 6 million barrels per day (just as inventories approach operationally challenging levels) and could force enough demand erosion to produce an annual contraction in global oil consumption in 2026. 

Mechanical realities feed the lag. Crude oil and natural gas fields cannot simply be turned back on. Tankers are displaced globally and need to reposition, both of which will take time. Inventories drawn down to near-record lows must be rebuilt before consumer-facing prices normalize. Rapidan’s analysis points the same direction: even with an early-August restart, crude inventories continue declining into September while Arab Gulf production gradually rebounds and shipments work their way to destinations – an independent read on the lag Valero’s three-to-one ratio describes. Mandatory inventory levels in several countries will require restoration that, even at maximum production, could take in excess of two years. 

The harder point is that the eventual equilibrium is not the pre-war equilibrium. The forward price curve will not return to its pre-war shape. The crude market has now embedded a war-risk premium on top of whatever risk premium pre-existed, and the level of backwardation traders will accept has moved structurally higher. As of May 19, 2026, the 30-year U.S. Treasury yield touched 5.19 percent, its highest level since July 2007, partly attributed to the inflationary effect of sustained high fuel prices passing through the supply chain. A sustained risk premium can also push marginal supply projects across the line economically – additional Canadian pipeline capacity to tidewater, accelerated Argentinian fracking, even more drilling in the Permian Basin, and supply chain diversification away from Gulf bunkering – that would not have been justified under pre-war assumptions. The same logic runs on the demand side: consumers historically dependent on Hormuz-routed barrels are unlikely to accept a return to that dependence on the old terms and will pay up for diversified sourcing rather than be repeatedly held hostage. These adaptations are themselves costly, which is part of why the new equilibrium settles at a higher level rather than reverting. We have not seen the full response yet, but we are watching for it. 

The macro frame for that pass-through is consequential: several leading forecasters now expect a rare annual contraction in global oil consumption in 2026. The pass-through to consumers and corporate margins is already visible in retail data. On its fiscal Q1 2027 earnings call on May 21, Walmart disclosed that the average fill-up at its U.S. fuel stations fell below 10 gallons for the first time since 2022 – the prior occurrence coinciding with the post-Ukraine-invasion price spike – which CFO John David Rainey characterized as an indication of stress among lower-income consumers. The bifurcation in the retail channel is sharp: Walmart reported Sam’s Club fuel volumes up 12 percent in May while OPIS data show average U.S. same-store gallons down 6.8 percent year over year, with Sam’s and Walmart pricing 24 and 18 cents per gallon below local markets, respectively. The same shock is hitting Walmart’s own P&L from the other direction – higher fuel costs in distribution and fulfillment eroded operating profit by roughly 250 basis points in the quarter. For our purposes, the Walmart data are a useful real-time read on two things the forward curve cannot show directly: that demand destruction is reaching the pump in measurable ways, and that fuel-price pass-through is now showing up in non-energy corporate margins. Both reinforce the view that the new equilibrium is structurally higher, not transitory. 

What this means for the decisions clients are weighing right now

Terminal and infrastructure investment. West Coast terminal owners are being asked to commit capital in a supply environment that looks meaningfully different than it did at the start of 2026. Stillwater’s proprietary USWC Supply and Demand Balance Outlook directly informs that answer. 

Refinery-side analytics under a constrained slate. The technical-capability-versus-availability question is a refinery-by-refinery linear programming question. Stillwater has the tools and the experience to work out the delta between a normal West Coast slate and a feasible one, and what that delta does to finished product yields. 

Price modeling for fuel consumers and obligated parties. Stillwater’s West Coast product price model is purpose-built for the question many clients are facing: what will jet, gasoline, and diesel prices be on the West Coast under different marginal-supply scenarios, including Asia-Pacific imports and Jones Act waiver scenarios for Gulf Coast cargoes?  

In closing, it is worthwhile to reflect on the oil crises of the 1970s as we consider the current environment. When the U.S. embargo ended, the world did not return to “normal”; instead, prices settled at structurally higher levels as OPEC flexed its pricing power. The policy response reshaped the energy landscape for decades – the goal of U.S. energy independence, the creation of the Strategic Petroleum Reserve, federal fuel economy standards, and substitution efforts such as the Synthetic Fuels Corporation. That is the more useful frame for the question clients keep asking. “Normal” after this conflict will not be the pre-war equilibrium any more than the post-1973 equilibrium was the pre-1973 one. New policy initiatives in the U.S. and beyond are almost certain to follow, and the cost structures and risk premiums embedded in fuel markets are likely to reset along with them. Stillwater will continue to follow the repercussions of the war and share insights and analysis with our clients as that picture clarifies. 

If you are weighing a decision that turns on any of these dynamics, reach out now to discuss. Better to have the conversation today than deal with the implications in a board meeting six months from now.