The energy market in the summer of 2026 is not experiencing a price spike. It is experiencing a structural reorientation. The framework that kept global commodity markets stable for the better part of four decades — a US-enforced maritime order, dollar-denominated trade, and cheap capital flowing toward technology — is fracturing along its seams.
Writing via InternationalMan.com, contrarian analyst Chris MacIntosh argues that the rotation from technology to energy has already begun, and that this cycle is structurally larger than those of the past two decades. The key mechanism is geopolitical: the United States and China have divided the material world between them. China dominates critical minerals, rare earths and the supply chains that feed the energy transition; the US controls hydrocarbons, food and the financial infrastructure of global trade. When China restricted exports of rare earth elements and magnets in April 2025, the fragility of Western manufacturing was immediately exposed. The parallel with oil is exact: decades of efficiency gains have stripped out discretionary consumption, leaving only essential uses. You cannot substitute away from what remains.
The postwar security order — whereby the US Navy protected global shipping in exchange for dollar primacy — is unwinding, not because any administration chose to end it, but because the fiscal arithmetic of maintaining it has broken down. Defence now ranks fourth in the US federal budget, behind Medicare and Social Security and rising interest costs. The Hormuz crisis of 2026 is the most visible consequence: a chokepoint disruption that the US no longer has an unconditional incentive to absorb on behalf of its trading partners. For any business planning energy procurement over a multi-year horizon, the relevant question is not whether prices will normalise — they will — but what the next baseline looks like when the old security architecture no longer operates as it once did.
Crude oil
The reopening turns contested, but the structural damage runs deeper
After nearly four months of disruption, the Strait of Hormuz began to reopen in mid-June. At the recovery’s high-water mark, US Energy Secretary Chris Wright confirmed at the Reuters Global Energy Forum that roughly 72 ships carrying approximately 20 million barrels of crude had transited the chokepoint in a single 24-hour period — approaching pre-war daily flows. Brent fell below $72 per barrel and WTI settled around $69, approaching levels last seen before the conflict erupted in late February. Tanker rates for the Saudi Arabia-to-China route, which had surged to $470,000 per day at the peak, fell 39% in a week to around $287,000 as vessel availability normalised.
That snapshot marked a peak rather than a settled new normal. In the final week of June the 60-day truce was tested by a renewed exchange of fire around the strait. The sequence began on Thursday 25 June, when Iran struck a vessel transiting the waterway — an act President Trump called a “foolish violation” of the agreement. US Central Command conducted retaliatory strikes on the Friday and Saturday after further attacks on commercial tankers, including the Panamanian-flagged Kiku carrying more than two million barrels of crude, hitting some ten Iranian military targets in and around the strait. Iran’s Revolutionary Guard Corps answered with missiles and drones against US facilities in Bahrain and Kuwait; a Qatari national was killed by shrapnel and a residential building in Bahrain was damaged. US forces struck mine-laying boats and missile sites in southern Iran on Monday 29 June. Both sides agreed to halt strikes on the Sunday evening, and negotiators were reported to be meeting in Doha on 30 June — though Tehran’s foreign minister warned that outside interference in its handling of the strait would only delay the reopening.
The market’s response was the more telling signal. Live military exchanges between the US and Iran — the precise scenario that drove Brent above $120 earlier in the year — barely moved prices: Brent rose roughly 1% to around $73 and WTI to about $70, both still below where they traded before the war began in late February. The cushion, not the ceasefire, was doing the work. Analysts at ING characterised the market’s composure as complacent, warning that a slow supply recovery or fresh escalation leaves meaningful upside risk unpriced. For a procurement desk, the read is not that geopolitical risk has passed, but that the buffer absorbing it is finite — and, as the inventory data below show, drawing down.
The ceasefire memorandum of understanding signed on 14–15 June gives both sides a 60-day window to lift their duelling blockades, with a formal signing ceremony in Switzerland on 19 June. But the physical reopening is proceeding more slowly than financial markets have priced. Mine-clearance is expected to take several weeks. Gulf exports are running at roughly 75% of pre-war levels, not 100%, and some insurers remain cautious. The futures market has largely moved on; the physical shipping market clearly has not.
The inventory picture is the reason complacency is premature. US commercial crude has drawn for seven consecutive weeks, and stocks at Cushing — the WTI delivery hub — have hit their lowest level since 2014, testing what traders describe as “tank bottoms.” The Strategic Petroleum Reserve has drawn steadily alongside commercial stocks since the conflict began. HSBC analyst Kim Fustier described the reopening as having created a “near-term supply overhang,” but noted — in a late-June assessment — that the next inflection point arrives when the vessel backlog clears and SPR releases end in July, at which point Brent could, on that timeline, retest $80.
Two structural developments sit beneath the price action. First, China’s post-war reconstruction strategy: Beijing’s Foreign Minister Wang Yi signalled during talks in New Delhi that China will support Iran’s reconstruction and peacebuilding. Reconstruction contracts are Beijing’s established mechanism for converting political capital into long-term energy access, and Tehran has made clear it views China as a strategic anchor. For European buyers, Chinese re-engagement with Iranian supply will, over time, replenish Chinese inventories and reduce Beijing’s need to buy from alternative suppliers — moderating competition for non-Middle Eastern barrels on a multi-quarter horizon.
That moderation in Chinese demand partly explains why oil did not spike to the $150 many predicted despite an 11 million barrel-per-day supply disruption. Chinese independent refinery operating rates fell to 50.5% in the week to 21 June — the weakest since 2017 according to consultant JLC — squeezed by high feedstock costs, weak domestic demand and export curbs. China’s broader structural shift toward electrification has also reduced marginal oil intensity. The country absorbed the supply shock partly through its own inventory, estimated above one billion barrels, rather than through spot buying. It is also why June’s renewed strikes barely registered in the price: the marginal Chinese buyer that would normally bid crude higher in a supply scare is, for now, largely absent from the spot market.
Second, OPEC’s internal cohesion is deteriorating. The UAE formally exited the cartel in April. Iraq briefly threatened to follow, with its Oil Ministry warning Baghdad would reconsider membership if quotas were not raised to reflect its actual production capacity, before walking the statement back. A cartel that has lost the UAE and faces credible exit pressure from Iraq is a structurally weaker price floor mechanism than the one that existed a year ago. That weakness is compounded on the supply side: with Saudi Arabia loading again at Ras Tanura and the UAE, Kuwait and Qatar all pushing volumes back to market — and Iraq now pressing openly for a higher quota to recoup wartime sales — the near-term supply impulse points firmly downward, which is part of why the renewed strikes failed to sustain a bid under crude.
India offers the clearest illustration of what sustained disruption costs an import-dependent economy. Indian refiners set a record 2.6 million barrels per day of Russian crude imports in June, with Russian supply accounting for 53.5% of all Indian oil purchases according to Kpler data. At the height of the supply shock, the rupee fell to record lows under pressure from the surging import bill, forcing the Reserve Bank of India to intervene. The RBI warned that the oil shock — should prices remain elevated — poses downside risks to growth and upside risks to inflation. Analysts at 360 ONE Capital modelled that oil sustained at $90 a barrel would push Indian inflation toward 4.8% while widening the current-account deficit. The mechanism is universal: a dollar-denominated import bill rising faster than export revenues drains reserves, weakens the currency, and passes through to domestic prices.
TotalEnergies CEO Patrick Pouyanné called it an “absolute priority” to invest in pipelines bypassing Hormuz, noting that Iraq-to-Mediterranean routes built by predecessors a century ago could be replicated today. Saudi Arabia’s East-West pipeline ramped to full capacity of 7 million barrels per day in the conflict’s first month. Expanding that alternative export infrastructure will, over a 3–5 year horizon, structurally reduce Iran’s ability to use Hormuz as leverage — which is precisely why Tehran is unlikely to agree to permanent bypass development as part of any nuclear settlement.
The distribution of oil-price outcomes remains asymmetric, but the asymmetry has sharpened. The downside holds only while inventory cushions do; the upside is no longer a remote tail contingent on the ceasefire breaking, because the ceasefire was broken and patched back together inside its first fortnight. June’s flare-up demonstrated both things at once — that the truce is fragile, and that ample stocks can, for now, absorb a live shock. But those stocks are drawing down, and the next disruption will meet a thinner buffer and a market that has already priced in the best case. Businesses on variable or index-linked fuel and power contracts should treat current prices as a planning floor rather than a forecast, and review hedge coverage now rather than in the depths of an autumn re-pricing.
Two distinct pressures arrived on European electricity markets simultaneously in late June: a short-duration weather event and a structural capacity challenge with no quick resolution.
The immediate trigger was a heat dome that settled across Western Europe, pushing French average daily temperatures to 29.8°C on 24 June according to Météo-France, with the southwest briefly hitting 44.3°C. French evening power surged to its highest level since the 2022 energy crisis; German day-ahead prices hit two-year highs; and Belgian peak-hour delivery on EPEX Spot reached €933 per MWh for Wednesday evening. The stress arose from a familiar combination: air conditioning demand spiking precisely when wind output was low and French nuclear output was constrained by heat-related river-temperature limits. Red heat warnings ran simultaneously across Germany, Luxembourg, Switzerland and the UK.
The heat event will pass. The structural challenge will not. The Tennessee Valley Authority released its preliminary 2026 integrated resource plan estimating an incremental capacity need of between 7 and 26 gigawatts of natural gas generation through 2040, driven primarily by data centre growth that is already outpacing the utility’s high-growth scenario. TVA also flagged a new winter peak record of 35,319 MW set in January 2025. The US numbers are not directly transferable to European grids, but the underlying dynamic is the same on both sides of the Atlantic: AI-driven load growth is arriving faster than the planning cycles embedded in network investment can accommodate.
Writing in UtilityDive, Amanda Simonian of TerraFlow Energy frames the diagnostic precisely: the energy sector is treating “what is fundamentally an infrastructure performance challenge as though it were only a generation problem.” More supply matters, but supply alone does not resolve congestion at constrained network nodes, instability from volatile load behaviour, or local system stress when large loads concentrate faster than the grid can adapt. The Iberian blackout of April 2025 — which ENTSO-E’s final report, published in March 2026, attributed to a multi-factor failure of voltage control and reactive-power management rather than to any deficit of renewable capacity — was the European demonstration of exactly this dynamic. ENTSO-E’s chair was explicit that the problem lay in voltage control “regardless of the type of generation”. Restoration, in turn, leaned on dispatchable resources: hydro black-start units such as Aldeadávila and the French and Moroccan interconnectors did the heavy lifting, with gas turbines brought back as the grid was rebuilt — a reminder that the scarce commodity in a stressed system is firmness, not raw capacity.
For energy-intensive and reliability-critical operations — industrial processors, healthcare facilities, cold chain logistics, hospitality groups running large HVAC loads — the practical implication is that forward baseload availability and grid connection timelines are becoming strategic questions. The Belgian €933/MWh print is an extreme tail event, but the directional pressure on peak-hour pricing in congested markets is upward as firm dispatchable capacity retires faster than it is replaced. On-site generation or storage, sized for resilience rather than cost savings alone, increasingly merits a place in procurement planning.
Qatar’s blast and Brussels’ methane rules: two separate threats to winter security
Europe’s gas market entered summer with a fragile storage trajectory, and two developments in late June have made the path to a well-filled October meaningfully more complicated.
The more immediate risk is physical. An explosion at Qatar’s Barzan gas processing complex in Ras Laffan on Sunday 21 June killed at least 13 people and injured 66. Goldman Sachs energy analyst Samantha Dart, cited in market coverage of the explosion, assessed in the days immediately following the blast that it did not appear to have directly impaired LNG export capacity, but raised the prospect of QatarEnergy slowing the restart of its export trains as a precautionary measure. Dart’s base case at that point assumed Qatari exports ramping to 83% of capacity by end-July; a one-month delay would reduce northwest Europe’s end-October storage to around 70%, four percentage points below the 74% base case — increasing winter scarcity risk under a colder-than-average scenario. Subsequent reporting through late June suggests the ramp is proceeding faster than this initial assessment indicated, which reduces the lower-storage tail risk. Under a two-month delay scenario, Goldman estimated fourth-quarter TTF would be supported closer to €50/MWh than to their €40 base forecast.
“Goldman Sachs scenario (22 June): a one-month Qatari ramp delay would lower NW Europe end-October storage fill by 4pp to 70%”
The timing is particularly unwelcome: the Ras Laffan accident came just days after the Hormuz reopening, precisely when the market had been counting on Qatari volumes as a significant contributor to Europe’s storage recovery.
The second risk is regulatory and, in part, self-inflicted. US Energy Secretary Chris Wright and Qatar’s Energy Minister Saad al-Kaabi wrote jointly to EU member states ahead of the June energy ministers’ meeting, co-signed by Algeria and Nigeria, warning that compliance with the EU’s methane regulation is technically infeasible for complex multi-operator supply chains. “There is no viable path to compliance with the regulation,” the letter stated, adding that “significant supply and price impacts are a certainty.” The methane regulation, extended to all foreign suppliers from 2025, requires tracking greenhouse gas intensity from wellhead to LNG carrier and levies financial penalties for non-compliance. According to reporting in the Financial Times, the US alone accounts for roughly 59% of EU LNG imports — rising to 64% in April — making the threat of reduced supplier willingness a material supply risk rather than a diplomatic posture.
Brussels partially deferred penalties until 2030 last year, but exporters are pressing for effective cancellation. A regulation that makes new long-term LNG supply agreements harder to structure introduces a structural source of supply uncertainty into exactly the contracting environment European buyers need to build resilient portfolios.
The causal chain for procurement planning runs directly. A delayed Qatar ramp tightens autumn storage. A methane regulation standoff constrains new contract formation and limits diversification options. Both effects land on Dutch TTF — the benchmark for most European gas and power pricing — and from there onto the variable component of any supply contract. Businesses on fixed-price arrangements have effectively pre-purchased protection from this tail risk. Those on variable or indexed tariffs carry it directly, and the current window of relative calm is the time to revisit that exposure.
Price TTF gas supply year 2027 (eur/MWh) – day cloud candle, log scale
Coal
China’s coal guarantee and India’s import pivot: what the latest demand data means for API2
European benchmark API2 Rotterdam peaked around $150 per ton in mid-June — the highest level since September 2023 — as the Hormuz disruption squeezed LNG availability and European utilities competed for the same seaborne cargoes as Asian buyers. Since the ceasefire, API2 has retreated to around $128 per tonne — roughly 15% above its pre-conflict level of circa $110, but well below the June peak. The demand architecture that shapes seaborne coal pricing is being reinforced, not dismantled. The two largest coal consumers in the world both published significant signals in the final week of June.
China’s new five-year energy plan, published on 25 June, designates coal a formal “bottom-line guarantee” of the power system even as it targets wind and solar energy rising from 22% to 30% of electricity supply by 2030. The plan does not cap coal capacity additions: China accounted for 78% of all new coal power capacity commissioned globally in 2025 and holds 86% of the total construction pipeline this year according to Global Energy Monitor. Wind and solar will become the stated “mainstay” of the grid, but coal is set to grow alongside them in absolute terms as a flexible backstop — the mechanism for covering demand whenever renewables or hydro fall short.
“China’s newly released five-year plan for the energy sector has very little to get excited about — Lauri Myllyvirta, CREA”
India’s direction is different but equally consequential for seaborne pricing. Thermal coal imports fell to a four-year low between January and May, down 12% year-on-year, as rising domestic output from Coal India allowed authorities to raise the share of locally mined coal to 50% — and in some cases 70% — at the 18.7 GW of capacity originally built to run on imported fuel. This reduces India’s seaborne offtake and offers some buffer to API2. But the underlying consumption is unchanged: coal represents roughly 70% of national electricity output and total coal-fired generation continues to grow with demand. India is rerouting supply chains, not stepping back from coal.
For energy buyers, the practical read is that API2 Rotterdam is a direct or indirect input into electricity and gas contract pricing across northwest Europe — its movements pass through into forward baseload and peak curves within days. With China formalising coal as a permanent grid backstop and India maintaining consumption while only substituting the source, APAC structural demand will keep a floor under seaborne prices well beyond the Hormuz recovery. Businesses on variable or indexed contracts carry this exposure live; those approaching renewal should treat the current API2 level as the relevant reference point rather than reverting to pre-crisis assumptions.
Storage breaks records while the ETS expands its perimeter
The United States added 3.3 GW and 8.4 GWh of energy storage in the first quarter of 2026, records for a seasonally slow quarter according to Wood Mackenzie and the American Clean Power Association. The organisations forecast cumulative US installed capacity reaching 200 GW / 655 GWh by 2031 — a four-fold increase from today. Two factors are driving deployment: colocation demand from data centres, and the preservation of the investment tax credit for storage systems under recent US tax legislation, which maintained the storage ITC even as it accelerated the wind-down of equivalent credits for wind and solar.
The European relevance of US storage deployment data is indirect but real. The battery chemistries being scaled in American utility projects — lithium iron phosphate, sodium-ion, and emerging iron-air formats — are the same technologies European grid operators need to firm up intermittent renewable output. As costs fall, the economics of pairing renewable generation with storage improve, raising the share of the merit order that can be displaced by zero-marginal-cost capacity — which in turn affects the carbon price signal needed to shift the remaining fossil generation.
The structural direction of the EU Emissions Trading System is a tightening supply of allowances against a steadily broadening scope. Maritime transport entered the system in January 2024, and the complementary FuelEU Maritime regulation took effect in 2025, setting a cap on the greenhouse gas intensity of fuels used by vessels calling at European ports. Each sectoral extension adds compliance demand to the same pool of allowances. For industrial buyers, MKB operators, and agricultural businesses carrying ETS exposure — directly or embedded in electricity and gas costs — the medium-term trajectory of allowance prices remains upward in the base case, with short-term volatility driven principally by coal-to-gas switching economics and weather-driven demand.
Price Emission Rights – Dec-26 contract EEX (eur/t) – day cloud candle, log scale
Renewable
Renewables scale on cost — but firmness is the scarce commodity
China’s ambition to power its AI data centres primarily with renewable electricity is running into a practical objection from the grid operators who would have to deliver it. Pei Shanpeng of State Power Investment Corporation told a Beijing industry conference that data centres “cannot really adjust power consumption load much” — GPU-intensive workloads run at near-full utilisation continuously because the hardware cost cannot be justified any other way. The result is a load profile that intermittent renewables are poorly suited to serve without substantial firming capacity. IEA data show that Chinese data centre electricity consumption was roughly 70% coal-powered as of 2025, with renewables at under 20%, despite China’s enormous solar and wind build-out.
China has nonetheless pressed ahead with a striking proof of concept. The world’s first offshore wind-powered undersea data centre — a 24 MW demonstration facility developed by HiCloud Technology at Shanghai Lingang, using seawater cooling and renewable electricity — illustrates the direction of ambition even if it is far from commercial scale.
In India, the near-term answer is nuclear. Gautam Adani announced at his group’s annual meeting that Adani Atomic Energy is targeting 10 GW of nuclear capacity by 2035, with land already identified, as India opens its civil nuclear sector to private investment for the first time. India’s government has set a 100 GW nuclear target by 2047 against a current installed base of 8.8 GW, implying an investment requirement estimated by a government panel at around $204 billion. Reliance Industries is also exploring the sector. Both announcements reflect the same structural calculation: round-the-clock clean power for a rapidly industrialising, reliability-critical economy cannot be built on solar and wind alone.
The overarching signal is that renewable deployment will continue to accelerate on cost economics, irrespective of the political weather. The Belgian €933/MWh power price spike and China’s data centre grid problem both point in the same direction: the binding constraint is increasingly firmness and dispatchability — the ability to deliver power when it is needed, not only when the sun shines or the wind blows. For businesses weighing on-site solar or storage investment — whether in agriculture, hospitality, healthcare, MKB or industrial settings — the relevant question is not headline generation capacity but self-consumption ratio and resilience value: how much peak-hour and peak-price exposure can be managed on site, and how does that compare against the contract alternative over a multi-year planning horizon.
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 does not constitute investment, legal or tax advice.
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