The 2026 Middle East war transmitted into electricity systems through oil and gas prices, not through a single global power price. When Dated Brent reached 144 United States dollars per barrel in early April, and when LNG supplies from Qatar and the United Arab Emirates fell by over 300 million cubic metres per day from 1 March, the cost of fuels that set or influence power prices rose sharply. This article explains the mechanisms that link those verified oil and gas shocks to electricity costs. Regional power price figures are cited only where the IEA or Euronews publish them.
The starting point is the fuel shock itself. The International Energy Agency records that the war began on 28 February and that flows through the Strait of Hormuz fell from around 20 million barrels per day prior to the conflict to an average of 2.7 million barrels per day in March, April and May. Cumulative Middle East oil supply losses exceeded 1.3 billion barrels. As the crisis intensified in early April, North Sea Dated crude reached an all time high of 144 dollars per barrel, more than double pre war levels, with even steeper gains for jet fuel and diesel. On the gas side, the IEA states that Hormuz transit disruption cut LNG supplies from Qatar and the UAE by over 300 million cubic metres per day since 1 March, a loss of over 2 billion cubic metres every week. About 20 per cent of world LNG had moved through the Strait in 2025. Spot gas prices in Asia and Europe reached their highest monthly averages since January 2023 in March 2026. In the second quarter, Europe’s TTF averaged near 16 dollars per million British thermal units, up 32 per cent year on year, and Asia’s Platts JKM averaged 17.5 dollars, up 45 per cent. Those are the fuel price anchors for any serious discussion of power cost pressure.
Electricity markets feel oil and gas shocks through several channels. The first is the gas bid stack in liberalised power markets. Where gas fired plants set the marginal price for many hours, a rise in wholesale gas costs lifts the offers those plants submit into the day ahead and balancing markets. Even buyers who never purchase LNG directly pay more when the marginal unit is gas fired and gas has become scarce. The IEA notes that higher LNG prices spurred gas to coal switching in the Asian power sector and that in Europe a combination of strong renewable output and higher natural gas prices was expected to reduce gas demand by more than 2 per cent in 2026. Fuel switching is itself evidence that power systems were adjusting to gas cost and availability, not that power became cheap.
The second channel is oil linked gas contracts. A substantial share of long term LNG and pipeline gas pricing remains indexed, in whole or in part, to oil benchmarks such as Dated Brent or related crude baskets. When Dated Brent doubled to 144 dollars per barrel, formula linked gas prices reset higher at the next indexation window even if spot LNG was already tight. Buyers on oil linked terms therefore imported the crude spike into their fuel bills, and generators holding such contracts faced higher variable costs. The IEA does not publish a single universal power tariff for this episode. The directional effect is clear from the fuel side alone: oil linked gas became more expensive when Dated Brent peaked.
The third channel is diesel and oil fired peaking. In systems that still use diesel or fuel oil for peaking, backup or islands of the grid, middle distillate spikes feed directly into generation cost. The IEA commentary emphasises that diesel and jet fuel saw even steeper gains than crude as Middle East product exports collapsed with Hormuz transit. Refining adjustments in the United States, Europe and West Africa eased some jet fuel strain, but middle distillates remained a tight leg of the barrel. For power planners, that matters wherever diesel gensets cover peak demand, support industrial parks, or back up renewable heavy grids during evening ramps. Again, the mechanism can be described without asserting an unsourced retail electricity price.
A fourth channel is forced demand destruction and administrative curtailment. The IEA Hormuz factsheet notes that natural gas dominates the power sectors of Bangladesh and Pakistan, with gas fired generation accounting for 50 per cent and 25 per cent of their electricity supply mixes respectively in 2024. Bangladesh, India and Pakistan imported almost two thirds of their total LNG supplies via the Strait of Hormuz in 2025. Inadequate LNG supplies, the factsheet states, would cause a deterioration of electricity supply security in those price sensitive markets and could lead to production curtailments in gas intensive industries including fertilisers. Euronews reports that some customers in Pakistan and Bangladesh were told Qatari delivery suspensions would continue through November, and that Edison in Italy faced 35 missed cargoes since April under extended force majeure. When contracted LNG fails to arrive, power systems either burn more expensive alternatives, switch to coal where possible, or cut load. Those are electricity security outcomes driven by gas logistics, even when no headline power price is quoted.
The fifth channel is cross commodity competition. When Asian spot LNG commanded a premium averaging 2.1 dollars per million British thermal units over TTF from March to June, flexible cargoes diverted from Europe to Asia. European power systems then competed harder for the remaining Atlantic Basin gas, while Asian power and industry buyers paid the premium required to win cargoes. The IEA records that non Gulf LNG production grew by almost 18 per cent, or around 27 billion cubic metres, between March and June, offsetting around three quarters of the Qatar and UAE decline. Global LNG production still fell by 4 per cent over that period. Partial offset limited the worst outcomes; it did not restore pre war fuel cost conditions for generators.
How large was the oil side buffer that indirectly protected some power systems? Global oil inventories drew at 3.8 million barrels per day on average from the start of the conflict. The IEA released 400 million barrels of emergency stocks, reaching 2.5 million barrels per day of additional supply in May. United States crude and product exports rose to a record 13.1 million barrels per day in May. Saudi exports via Yanbu rose from 2 million barrels per day before the war to more than 5 million in early June. Those oil system responses mattered for electricity wherever oil products feed peaking plants or wherever oil linked gas contracts reference crude. They also mattered for diesel logistics that keep grid maintenance fleets and backup generators running. Emergency oil stocks are not emergency electrons, but they damp the fuel complex that power markets draw upon.
Power impacts can be analysed in four steps. Step one is to lock the fuel facts to primary pages: Dated Brent at 144 dollars, Hormuz oil flows at 2.7 million barrels per day on average in March to May, LNG losses above 300 million cubic metres per day from Qatar and the UAE since 1 March, TTF near 16 dollars and JKM at 17.5 dollars on second quarter averages. Step two is to map each national power market’s exposure by fuel share, contract indexation and peaking technology, using official generation mix data such as the IEA’s 2024 figures for Bangladesh and Pakistan gas fired shares. Step three is to discuss cost pressure and security of supply qualitatively or with sourced figures only. Step four is to cite retail or wholesale electricity prices only where official sources publish them.
Policy implications follow from these mechanisms. Governments that still rely on oil linked LNG for a large share of power fuel should accelerate reviews of indexation and of storage. Systems with high gas fired shares and heavy dependence on Hormuz routed LNG, such as those flagged for Bangladesh and Pakistan in the IEA factsheet, need contingency fuel switching plans that are rehearsed before the next transit shock. Markets with deep gas on gas competition should expect bid stacks to rise when TTF and JKM spike, and should not assume that renewable growth alone cancels fuel price pass through in residual thermal hours. Diesel dependent peaking fleets should treat middle distillate spikes as a power reliability issue, not only a transport fuel issue.
The mid June interim agreement between the United States and Iran, which aimed to reopen Hormuz, eased some price pressure. The IEA notes that TTF month ahead and Platts JKM declined by 6 per cent and 12 per cent respectively between 15 and 26 June after the announcement. Easing is not normalisation. Euronews later reported that QatarEnergy continued force majeure extensions into late 2026 for some European and Asian customers, and that Ras Laffan repairs for damaged units would take about three years even though 12 undamaged units could resume once shipping was safe. Power markets will therefore live with elevated gas risk well after oil tanker counts improve.
In plain terms, the 2026 oil and gas shock raised the cost of the fuels that many power systems burn at the margin, tightened LNG availability for gas dependent grids, and stressed diesel supply for peaking and backup. Dated Brent at 144 dollars and LNG losses above 300 million cubic metres per day are sufficient to explain why electricity costs and security came under pressure. Adding unsourced power price claims would weaken, not strengthen, the analysis. Transition economics worthy of the name keeps the causal chain intact and the arithmetic honest.