Energy market analysis June 18, 2026

Why the Hormuz premium keeps deflating and why that is fragile

Three months into the most severe oil-supply disruption in modern history, the price action has confounded the physical arithmetic. Reduced traffic through the Strait of Hormuz has cut Middle Eastern crude output by more than 11 million barrels a day against pre-conflict levels, yet WTI has been trading just below $90, far short of the $150 many analysts expected. The EIA’s latest Short-Term Energy Outlook expects global inventories to fall by an average of 6.3 million b/d in the second quarter and 7.6 million in the third. The market, in other words, is being supplied out of storage rather than out of the Gulf.

Three offsets explain the calm. First, barrels are quietly getting out: a growing number of Gulf tankers are switching off their transponders and transferring cargoes ship-to-ship beyond the strait, a pattern first flagged when Gulf states began planning bypass routes. Vessel trackers identified clusters of such transfers off Oman, prompting one monitoring service to call it the reason oil is not already at $200. Second, the United States is exporting at record rates and has drawn heavily on its Strategic Petroleum Reserve. Third, and most striking, China is simply buying less.

Chinese crude imports fell in May to roughly 7.8 million barrels a day, an eight-year low, down about 30% on last year’s pace. Two forces are squeezing imports from the refining side: price ceilings imposed by Beijing have hit independent refiners’ margins, and run rates have plunged as a result, alongside a broader run of weak economic data that has revived hard-landing concerns. Some of that is a weakening economy, but part looks structural: China appears able to function on less fuel than assumed, with electric-vehicle charging volumes up by around two-thirds year on year and rail and metro use climbing. The country has leaned on a stockpile estimated at over a billion barrels to absorb the shock, but as analysts have noted, that cushion is not infinite, and imports will need to recover at some point even if the structural demand shift proves durable.

That is precisely why the present equilibrium is unstable. As Goldman Sachs trader Rich Privorotsky observed, the fact that so much has been thrown at the market without lifting prices suggests “Iran’s leverage over global energy markets may be far lower” than many assumed. But inventories are a wasting asset: US commercial crude has drawn for seven consecutive weeks, Cushing is approaching tank-bottoms, and the SPR has shed about 16% of its pre-war volume. ING analysts warn the buffer shrinks daily, with summer demand still ahead. When restocking eventually collides with an unresolved blockade, the repricing could be abrupt.

The import-dependent economies show what that would cost, and India is the clearest case study. As the world’s third-largest crude importer, buying more than 85% of the oil it consumes, India turned heavily to discounted Russian barrels after 2022 and has continued doing so even as Washington’s stance has shifted back and forth. Foreign minister S Jaishankar pushed back on accusations that India is too willing to buy Russian oil, noting that Washington itself encouraged the purchases in 2022 to stabilise the market. “Circumstances pushed us in a certain direction,” he said, a reminder that the politics of energy security are rarely as principled as they sound.

On the ground, Indian refiners have moved quickly to diversify. They have secured crude supply through August by lifting purchases from the UAE, and are buying growing volumes from Nigeria, Angola, Brazil and Venezuela to offset lost Middle Eastern supply. Diversification of this kind is the practical playbook for any economy facing a chokepoint disruption, but it does not come free: switching suppliers under time pressure typically means paying up for cargoes, freight and insurance, and the bill shows up in the macro numbers.

India, which buys more than 85% of its oil abroad, is intervening to defend the rupee, which fell to record lows as the energy import bill climbed. Investment banks, brokerages and rating agencies are lowering India’s growth forecasts as the government works to stem the resulting bleed in its balance of payments. The Reserve Bank of India has warned that the oil shock poses downside risks to growth and upside risks to inflation, and analysts at 360 ONE Capital have gone further, estimating that oil averaging $90 a barrel could push inflation toward 4.8% in the coming fiscal year while shaving GDP growth, widening the current-account deficit and lifting the fiscal deficit. The mechanism is simple and universal: a dollar-denominated import bill rising faster than export earnings drains foreign-exchange reserves, weakens the currency, and passes straight through to domestic prices. For import-dependent businesses and strategic planners, the read-across is about risk shape rather than today’s screen price. Current levels reflect borrowed time, not a solved problem, and the distribution is asymmetric: limited downside while the cushions last, sharp upside if they run dry before the strait reopens. For anyone on variable or index-linked fuel and power contracts, that argues for treating present prices as a planning floor and revisiting hedge cover now, well before the inventory story turns.

How the May supply loss has been absorbed — re-routing, inventory release and demand destruction. Source: J.P. Morgan Commodities Research, Rystad, S&P Global Energy, EIA

The ceasefire deal and the deflating risk premium

On 14–15 June, the United States and Iran announced a memorandum of understanding — to be formally signed in Switzerland on 19 June — that extends the ceasefire for 60 days and commits both sides to lifting their duelling blockades of the Strait of Hormuz. Trump declared the deal complete on Sunday night, stating that “oil will flow” once the agreement is signed, and immediately announced the lifting of the US naval blockade of ships docked at Iranian ports. Iran’s Deputy Foreign Minister confirmed the signing ceremony.

Markets reacted immediately. Brent crude fell 3.95% to $83.88 per barrel and WTI dropped 4.62% to $80.96 in early Asian trading on Monday — a move that came on top of a roughly 30% decline from April’s peak that had already been building on ceasefire optimism through May and early June. In total, the market has unwound a substantial portion of the geopolitical risk premium that accumulated when Hormuz was effectively closed.

The deflation of that premium makes sense: the risk premium existed to compensate for the probability of prolonged supply disruption; a signed deal reduces that probability. But full normalisation will take longer than the price move suggests. Shipping operators warn it will take weeks, not days, to return tanker traffic to pre-war levels once the strait is cleared of mines and security is confirmed. Iran’s nuclear programme remains unresolved and will be subject to a further round of negotiations. And the structural damage done to Gulf infrastructure — pipelines, terminals, refineries — is not repaired by a ceasefire alone.

For procurement and risk planning, the directional read is clear: the supply-disruption premium will continue to compress as the deal holds. Iran is permitted to resume crude exports during the 60-day period, which adds supply to a market that has been drawing down inventories for months. The caveat is that inventories remain deeply depleted — the US alone has drawn its Strategic Petroleum Reserve by roughly 16% since the conflict began — meaning the restock phase will absorb a significant portion of returning supply before prices find a new equilibrium. A deal that holds points to a gradual return toward pre-war price levels; a deal that fractures on nuclear terms could reverse the move sharply.

Crude Oil Price Brent Aug 2026 ($/vat) – dag cloud candle, log scale

The grid’s problem is no longer just supply — it is the loads themselves

A May report from the Texas grid operator ERCOT gave the market a concrete reason to stop assuming the system can absorb unlimited hyperscale demand. In voltage ride-through testing, several clusters of proposed data-centre and crypto sites simply disconnected when subjected to routine disturbances, with each group capable of dropping more than 5,000 MW at once — ERCOT likened a single event to losing the entire consumption of a city the size of Boston. An instantaneous loss of demand on that scale pushes frequency up sharply and can cascade into a system-wide stress event.

Europeans have already seen the supply-side version of the same physics. The Iberian blackout of April 2025 was not a straightforward case of excess solar; ENTSO-E’s analysis identified shortcomings in how the system managed voltage and reactive power, with generators held in fixed power-factor settings that offered no dynamic support, after which a rapid voltage rise tripped large amounts of generation. Gas units ultimately stabilised the recovery, a detail that complicated the initial “net-zero failure” framing of the event once the full picture emerged. ERCOT’s tests are the demand-side mirror image: inverter-based generation and concentrated, sensitive electronic load each respond to disturbances quite unlike the spinning synchronous plant the network was originally built around.

Regulators are paying attention on both sides of the Atlantic. The US Interior Secretary has already warned of Spain-style blackout risk on the US grid, and the scale of the load growth behind that warning is striking: Texas electricity demand could more than quadruple under data-centre and crypto growth scenarios, while PJM is targeting 15 GW of new supply just to keep pace with its own data-centre corridor. The common factor across these grids is ageing infrastructure with little spare capacity meeting load growth that was not part of the original planning assumptions, on either side of the Atlantic.

The response is taking two complementary forms. On firm capacity, the Western nuclear pipeline is filling with proposals — a US microreactor reached criticality, Constellation cleared a path to restart Three Mile Island, Cameco’s Westinghouse unit sees as many as 20 new large reactors in the pipeline, and NANO Nuclear has signed with Supermicro to target AI data-centre power directly — though the only operational scoreboard still favours China, which is building dozens of grid-scale reactors. Behind this pipeline sits a tightening fuel market: term uranium (U3O8) pricing is holding firm above $90 per pound, supported by fundamentals that point to 2026 primary production falling short of base demand. Fuel costs are a small share of nuclear’s overall economics, which are dominated by capital and financing, but the firming term price is a useful signal that the fuel-cycle supply chain is tightening alongside the reactor pipeline itself.

On flexibility, Google signed a three-year “Bring Your Own Capacity” agreement with Voltus for up to 100 MW of aggregated distributed resources in the PJM market — batteries, thermostats and EVs orchestrated as a virtual power plant. The Brattle Group estimates better use of existing infrastructure could save US consumers over $100 billion this decade.

The Voltus deal is just one front in a much broader procurement push. On the firm, always-on side, Google has struck a deal with NextEra to restart the Duane Arnold nuclear plant in Iowa and is looking to offtake power from Kairos’ molten-salt small modular reactors in Tennessee. On next-generation geothermal, Google’s long-running partnership with Fervo Energy has expanded under a Clean Transition Tariff structure with NV Energy, alongside PPAs with Ormat under the same framework. On renewables and storage, Alphabet has closed its $4.75 billion acquisition of Intersect Power, a developer of co-located data-centre and energy infrastructure, and has separately backed Form Energy’s iron-air long-duration battery technology. Taken together, this is a hyperscaler methodically assembling exposure to nearly every generation and flexibility technology in play, restarting nuclear, advancing geothermal, buying developers outright and now directly funding distributed capacity, because grids are not adding transmission and firm generation fast enough to match announced data-centre builds. For the standard European industrial buyer, the practical consequence is that corporate Power Purchase Agreements for green baseload are becoming scarcer and more expensive: any business seeking such a PPA is now bidding directly against the likes of Alphabet and Microsoft for the same underlying projects.

Across both the European and American examples, the binding constraint is engineering rather than any single fuel’s politics: keeping a grid stable through a period of rapid load growth requires firm, fast-starting capacity and demand-side flexibility in roughly equal measure. The implications travel well beyond the American data points. Global load growth is lifting power demand and tightening grid congestion everywhere, which means forward baseload prices and — increasingly — the availability of grid connection capacity are becoming strategic questions rather than routine line items. Energy-intensive and reliability-critical operations such as healthcare and industrial sites should treat connection timelines, on-site flexibility and back-up firmness as part of the procurement conversation, not an afterthought.

Peak summer effective capacity set against demand growth: the reliability margin is narrowing as load scales. Source: Goldman Sachs Global Investment Research.

Price Baseload Electricity delivery year 2027 (eur/MWh) – week cloud candle, log scale

Germany’s big Canadian LNG deal, and why the molecules may never arrive

The Iran war has made liquefied natural gas the most strategically contested commodity since Russia’s 2022 invasion of Ukraine, and Germany has responded by reaching across the Atlantic. Ottawa brokered an agreement under which the German utility SEFE will buy one million tonnes a year of LNG from the planned Ksi Lisims project on the British Columbia coast for up to two decades — the first long-term supply deal between a Canadian project and a European buyer. Days later, Uniper signed a letter of intent for a possible further two million tonnes a year.

The complication, as OilPrice.com sets out, is geography. Ksi Lisims sits on Canada’s Pacific coast, there are no operational large-scale export terminals on the Atlantic side, and the project still faces a Final Investment Decision plus legal challenges over its pipeline. Shipping West Coast gas to Germany via the Panama Canal is awkward enough that Germany may, in practice, never physically receive a single Canadian cargo.

Instead the buyers are expected to use cargo swaps, a mechanism now routine among portfolio players: redirect the Canadian volumes to buyers in Japan, South Korea or Taiwan, and take equivalent molecules from suppliers closer to Europe such as the US, Qatar, Algeria or Norway. The result, as analysis via the Financial Post frames it, is lower shipping costs and greater flexibility while the overall supply balance is unchanged. The contract, not the cargo, is the asset: a Canadian position offers diversification and supply from a stable democracy even if the gas itself is burned on the other side of the world.

The benchmark that matters here is Dutch TTF, on which the region’s gas and much of its power cost depends, and it is exposed less to where any individual molecule originates than to the depth and flexibility of the contractual web around it. The lesson for procurement is that security increasingly comes from optionality — diversified, swappable positions — rather than from a single physical source. Businesses on fixed-price gas contracts have effectively pre-purchased that certainty; those on variable or spot exposure carry the flexibility risk themselves, which is worth weighing deliberately while the market is calm rather than in the depths of a winter scramble.

Price TTF gas delivery year 2027 (eur/MWh) – day cloud candle, log scale

Washington props up coal as Europe retires it, watch the export channel

The divergence between US and European coal policy widened sharply this month. The US Department of Energy announced up to $850 million to modernise existing plants and build new capacity, drawing on Defense Production Act authorities. Around $425 million is directed at a dozen coal-fleet projects, with a further $350 million to recommission and modernise roughly 3.6 GW of capacity. Two of the proposed plants, in Alaska and West Virginia, would be the first new US coal units since 2013.

The administration frames this as reliability and affordability — preventing the early retirement of dispatchable plants it argues are cheap and secure. Critics see the opposite: the Sierra Club calculated that emergency orders keeping ageing fossil plants online have already cost ratepayers more than $230 million, calling it a subsidy for an uncompetitive fuel. Both readings can be true at once: coal can be dearer to run than the alternatives and still valued for the firmness it provides during system stress — the same attribute that mattered in Spain.

The most relevant detail is easy to miss in the domestic argument: $75 million of the package supports a rail-served marine export terminal aimed at the Indo-Pacific. More US thermal coal reaching seaborne markets loosens global supply and feeds into the API2 benchmark that sets European coal economics. That in turn shapes the coal-to-gas switching calculus and, by extension, the value of EU emission allowances, since cheaper coal raises the carbon price needed to keep gas competitive in the merit order. The causal chain runs from a US subsidy decision through seaborne coal pricing to the carbon spread that European power and industrial buyers ultimately pay — a reminder that policy made in Washington can land on a Dutch or German invoice.

Price ICE Coal delivery year 2027 (usd/t) – week cloud candle, log scale

Nuclear-powered shipping hubs and the slow tightening of maritime carbon costs

China’s Jiangnan Shipyard has proposed a large offshore platform that would combine cargo transfer, power generation and ship refuelling in a single floating facility, according to the South China Morning Post. The concept centres on a molten-salt reactor, supplemented by solar and wind, producing hydrogen, synthetic green fuels and ammonia to power terminal operations and electric support vessels. The designers argue molten-salt technology is inherently safer because the coolant solidifies if released, and that the modular hub could be replicated at other strategic ports.

Treat the engineering claims as aspirational rather than settled — this is a design unveiled at a trade exhibition, not a sanctioned build. The reason it belongs in a carbon discussion is what it signals about where compliance pressure is heading.

The EU has extended its Emissions Trading System to cover maritime transport since January 2024, and the complementary FuelEU Maritime regulation took effect in 2025, setting a tightening cap on the greenhouse-gas intensity of fuels used by ships calling at European ports and explicitly incentivising renewable fuels of non-biological origin, including e-ammonia.

That regulatory architecture is the real story for European participants. Shipping now carries a carbon cost into the same allowance market that industry and power already operate in, and the structural direction of the ETS is a shrinking supply of allowances against a steadily broadening scope. Whether or not floating reactors ever reach commercial service, the technologies being prototyped — ammonia, green hydrogen, onshore power — are precisely those the European framework is designed to reward. For any business with cargo-exposed supply chains, the practical implication is that freight is becoming a carbon-priced input, and the cost of moving goods through carbon-regulated zones will tend to rise.

Price Emission Allowances – Dec-26 contract EEX (eur/t) – week cloud candle, log scale

Europe bets on North African sun while solar quietly overtakes coal elsewhere

Starved of cheap energy since the start of the Ukraine war and now rattled by the Iran conflict, the European Commission has pledged €5 billion towards renewable projects in North Africa and the Middle East under an initiative known as T-MED. The vision is expansive: solar in the Sahara and wind along the Mediterranean’s southern shore, exported north through subsea high-voltage links, with the EU money intended to mobilise up to €25 billion of investment and 15 GW of new capacity by 2035. Energy chief Dan Jørgensen tied it directly to the crisis, noting the bloc’s fossil-fuel import bill has climbed steeply for no additional supply.

The ambition deserves a sober reading. Subsea interconnection across the Mediterranean at this scale is technically demanding, politically complex and slow, and the headline figures sit well below the true cost of building generation, grids and transmission together. The probability that meaningful North African electricity is flowing into Europe within the decade is low, and the bill for getting there would be considerable for a Union that is, if anything, more cash-strapped than energy-strapped. The initiative is best read as a long-horizon supply-security signal rather than a near-term price influence.

The more immediate evidence sits in the generation mix. In the United States, solar overtook coal for a full month for the first time on record in May, reaching a 12.8% share against coal’s 12.2%, on data from the think-tank Ember. As Ember’s Nicolas Fulghum put it, solar has moved “from a niche contributor to the third-largest and fastest-growing source” of US power. Notably, this is happening despite federal support for coal, with solar and storage making up the bulk of new capacity additions — a reminder that economics, not just policy, drives the build-out. As one analysis put it, solar is booming even under an administration openly hostile to it, which is itself the clearest evidence that the cost curve, not the political weather, is now the deciding factor.

The binding constraint on this transition is increasingly storage and grid stability rather than panels themselves, which loops back to the electricity-market story above. Advances in cheaper, safer chemistries — from grid-scale prismatic cells now being piloted at US national labs to solid-state batteries — matter because they determine how much intermittent capacity a grid can actually use. The scale of China’s EV supply chain is the main reason these chemistries are getting cheaper so quickly: the bulk of near-term cost reduction in sodium-ion, LFP and iron-air technology is being driven by automotive-scale manufacturing, not by niche applications. A separate strand of development, solid-state cells engineered for extreme-temperature operation, is being pursued for demanding niches such as eVTOL aircraft, where customers can absorb higher costs; that work may eventually feed back into grid-storage chemistries, but on a much longer timeline than the automotive-driven cost curve that matters for near-term deployment.

The overarching takeaway is that renewables will keep scaling on cost, but the value increasingly lies in firmness and flexibility: dispatchable supply, storage and demand response. Businesses weighing on-site solar or storage should size the decision around resilience and self-consumption, not headline generation figures alone.

US monthly generation shares: solar edges past coal for the first time, May 2026. Source: Ember.

Additional charts

A few supporting visuals from this fortnight’s sources, with attribution.

Chinese crude imports fell to an eight-year low in May. Source: Chinese customs data via Bloomberg

Chinese crude imports fell to an eight-year low in May. Source: Chinese customs data via Bloomberg

New reactor construction starts in May added China and South Korea to the global under-construction tally, where China continues to dominate. Source: World Nuclear Association / PRIS, compiled by Goldman Sachs Global Investment Research.

Solar and storage made up 91% of new US generating capacity in Q1 2026, with states won by the current administration accounting for 74% of installations. . Source: SEIA / Wood Mackenzie.

This analysis contains COMCAM’s own commentary, which is COMCAM’s copyright and may not be reproduced without permission. Factual data and any third-party quotations remain the property of their original sources, which are linked throughout. This material is general market commentary and not investment, legal or tax advice.