Energy & Climate Desk

Barrel Report Conrad Stahl

The Strait of Hormuz is not a policy abstraction — it is the physical chokepoint through which roughly 20 percent of global oil and 25 percent of global LNG transits every single day. A closure, even a partial or contested one, does not show up first in the futures curve. It shows up in VLCC spot rates, in loading delays at Ras Tanura, in the spread between Brent dated and the front month. Watch the physical. Trump's threat to bomb Iran if the strait is not reopened is, from a commodity standpoint, a double-edged pressure: it may accelerate Iranian compliance, but it also prices in an elevated probability of kinetic escalation that no amount of SPR release can paper over.

Taiwan's CPC forecasting stable supply is notable, but read it carefully. State oil companies do not forecast instability — that is a political and market-confidence function, not an operational assessment. What matters is what CPC is actually doing: how much spot cargo is on the water, what their term contract coverage looks like, whether they are quietly bidding up Atlantic Basin crude to substitute for Persian Gulf barrels. The forecast is narrative. The tanker bookings are the truth.

The EU Commission speech on LNG and shipping at Columbia is the tell. Brussels does not convene roundtables about open straits. That event signals that European energy security officials are actively war-gaming rerouting through the Cape of Good Hope — adding 10 to 14 days of transit time per cargo — and the downstream effect on regasification terminal queues in Rotterdam, Wilhelmshaven, and Eemshaven. U.S. LNG exporters, particularly Sabine Pass, Corpus Christi, and the newer Plaquemines terminal, are sitting on a price spike that has not yet fully materialized in Henry Hub because the market is discounting rapid resolution. That discount is the trade.

Rubio's framing of a stable strait as in both U.S. and Chinese interests is the most geopolitically significant data point in the corpus. China takes roughly 40 percent of Persian Gulf crude exports. If Beijing is being privately signaled that Washington will act militarily, Beijing has a structural incentive to quietly pressure Tehran. That back-channel dynamic — not the military threat itself — is what could move physical barrels back through the strait fastest. But it will not show up in public statements. Watch tanker AIS data for resumption of loaded departures from Kharg Island.

Key point: The Hormuz closure is already repricing physical LNG and crude globally; the Rubio-China back-channel dynamic, not Trump's public ultimatum, is the fastest path to barrel flow resumption.

Grid Watch Lena Hargrove & Sam Okafor

From a grid operations standpoint, the Hormuz closure lands on U.S. power systems in two distinct pathways, and they operate on different timescales. The first is the fuel-cost channel: roughly 3 percent of U.S. utility-scale generation still runs on petroleum liquids and distillates, concentrated in New England (where oil-fired capacity remains a winter reliability backstop) and island systems like Hawaii and Puerto Rico. A sustained crude price spike translates directly into dispatch cost increases for those units, compressing reserve margins in markets where those generators sit at the top of the merit order. NERC's latest seasonal reliability assessment already flagged the Northeast as tight heading into summer peak. Add a fuel cost shock and you are stress-testing a system that does not have a lot of slack.

The second pathway is the LNG-to-power channel, and this is where the numbers get serious. Natural gas generates approximately 43 percent of U.S. electricity. Domestic gas supply is not directly disrupted by Hormuz — the U.S. is a net LNG exporter, not importer — but the global LNG price spike will pull U.S. export volumes toward higher-priced European and Asian markets, tightening domestic gas supply at the margin and bidding up Henry Hub. PJM, ERCOT, and MISO all watch Henry Hub closely. A sustained $2/MMBtu increase in gas prices translates to roughly $20-25/MWh increase in marginal generation cost across gas-fired capacity — that is not a rounding error on peak summer load days.

The hurricane season opener on May 15 for the Eastern North Pacific, and June 1 for the Atlantic, is the compounding risk. Gulf of Mexico gas production — still roughly 2 percent of total U.S. supply but disproportionately important for Gulf Coast grid balancing — is the first thing to go offline when a named storm enters the Gulf. A simultaneous Hormuz disruption and active hurricane season is not a tail scenario. It is a scenario that grid operators in MISO-South and SPP need to be running tabletops on right now.

Key point: The Hormuz crisis hits U.S. grids through the LNG-to-gas-to-power price chain and through direct fuel cost exposure in New England and island systems — and a concurrent active hurricane season makes the compound risk non-trivial.

Carbon Desk Henrik Lindqvist

A Hormuz closure is, on its face, a bearish signal for European carbon markets and a structurally ambiguous one for the U.S. voluntary carbon market. Here is why: if LNG rerouting via the Cape of Good Hope drives European utilities back toward coal dispatch to manage gas supply uncertainty, you get a near-term carbon intensity increase in European power generation. That increases EUA demand, which supports the EU carbon price — currently trading in the mid-60s EUR/tonne after recovering from the February lows. But if the disruption persists and triggers recession-risk pricing across commodity markets, industrial output falls, and EUA demand drops with it. The carbon price is thus caught between a fuel-switching uplift and a demand-destruction headwind. Historically, in 2022, the Russian gas shock produced both simultaneously — the EUA price spiked to €95 before collapsing as industrial output fell.

For U.S. carbon markets, the signal is more subtle but worth tracking. RGGI allowance prices have been under pressure from low natural gas prices suppressing coal dispatch and thus keeping carbon intensity low. A gas price spike from the LNG-pull effect reverses that dynamic — higher gas prices narrow the coal-to-gas switching spread, potentially increasing coal burn in RGGI states and lifting allowance demand. Watch the RGGI clearing price at the next quarterly auction. More significantly, any escalation that keeps oil elevated is a structural accelerant for clean energy investment under the surviving IRA provisions — stranded-asset risk for long-dated fossil fuel infrastructure increases materially when geopolitical disruption reprices the cost of supply security.

Snap's guidance citing 'Middle East geopolitical situation' as an advertising demand uncertainty is the sleeper item here. When digital advertising spend contracts — historically the first discretionary budget cut in uncertainty — ESG-linked corporate communications spending contracts with it. That compresses the voluntary carbon market's demand side, which has been propped up partly by corporate sustainability marketing budgets. Price the difference between commitment and verified reduction: it just got wider.

Key point: The Hormuz disruption simultaneously supports EUA prices via coal-switching and threatens them via demand destruction — the EU carbon market is pricing both signals and the spread will tell you which one the market believes.

Weather Risk Dr. Maya Castillo

The NHC's seasonal reminders — Eastern North Pacific opens May 15, Atlantic opens June 1 — drop into a corpus dominated by a Hormuz closure. The juxtaposition is not coincidental from a risk-portfolio standpoint. The 2025 Atlantic hurricane season produced above-normal activity, and early-season ENSO conditions for 2026 are tracking toward neutral-to-weak La Niña, which historically correlates with elevated Atlantic basin activity. NOAA's preliminary 2026 outlook, expected in late May, will be the first formal quantification of that risk.

The compound scenario that grid and energy market operators must price is this: a Hormuz disruption is already straining LNG supply chains and bidding up gas prices globally. A Category 3 or above storm making landfall on the Gulf Coast between July and September would simultaneously disrupt offshore gas production, onshore refinery operations, and — critically — the Sabine Pass and Corpus Christi LNG export terminals that are currently pricing a global supply premium. The insured loss from a major Gulf Coast hurricane in a tight-energy-market year is meaningfully higher than in a slack year, because business interruption losses compound against elevated replacement energy costs. The uninsured loss — to the 40 percent of Gulf Coast energy workers without adequate income-interruption coverage, to municipalities whose emergency reserves are already stressed — is the story no one is pricing.

The adaptation gap in U.S. coastal energy infrastructure remains wide. Post-Harvey hardening investments at major Texas refineries improved flood resilience, but LNG export terminal siting on the Gulf Coast reflects pre-2020 storm-intensity assumptions. A slow-moving, high-rainfall event of the type that has become more frequent under observed warming trends is not what the terminal protective berms were engineered for. That is not a 2050 risk. That is a this-season risk.

Key point: The convergence of a Hormuz supply shock, elevated hurricane-season risk, and under-hardened Gulf Coast LNG export infrastructure creates a compound energy-market vulnerability that no single risk model is currently capturing in full.