핵심요약

• 세계 LNG의 20%와 해상 유전의 25%가 호르무즈 해협을 통과합니다.
• 카타르는 세계 LNG의 20%를 공급하며, 2026년 3월 이란의 공격으로 17%의 LNG 수출 용량이 영향을 받았습니다.
• 브렌트유 가격은 분쟁 전 대비 40-50% 상승했습니다.
• 분쟁으로 인해 LNG 공급 안정성과 가격 간 균형 재검토가 이루어지고 있습니다.

도입

중동 분쟁이 아시아 태평양 지역의 전력 시장에 미치는 영향은 투자자에게 중요한 정보를 제공합니다. 특히 LNG와 유전의 공급 안정성과 가격 변동성이 전력 생산 비용에 직접적인 영향을 미치기 때문입니다. 이 분석을 통해 투자자는 분쟁이 장기적인 에너지 시장 구조에 어떤 변화를 가져올지 예측할 수 있습니다.

본문 1: LNG 공급 안정성 재검토

카타르의 LNG 수출 용량 17%가 영향을 받은 것은 전력 생산에 의존하는 국가들에게 큰 영향을 미칩니다. 이란의 공격으로 인해 호르무즈 해협의 안전성이 위협받자, LNG 수입국들은 공급 안정성을 더 중요하게 고려하게 되었습니다. 이는 장기적으로 LNG 수출국과 수입국 간의 계약 조건에 변화를 가져올 가능성이 있습니다. 특히, 기존의 단기 거래 중심의 시장 구조에서 장기 계약으로의 전환이 가속화될 수 있습니다.

본문 2: 유가 가격 변동성과 시장 반응

브렌트유 가격이 분쟁 전 대비 40-50% 상승한 것은 유가 시장의 변동성을 보여줍니다. 유가는 유동성이 높아 공급 다각화가 상대적으로 용이하지만, LNG는 그 특성상 공급 다각화가 어렵습니다. 이는 LNG 수입국들이 더 많은 비용을 지출하게 만듭니다. 또한, 유가 상승은 전력 생산 비용 증가로 이어질 수 있어, 에너지 기업들의 수익성에 영향을 미칠 것입니다.

본문 3: 장기적 전망과 리스크

분쟁의 장기적 영향은 LNG 시장 구조의 변화를 초래할 것입니다. 공급 안정성을 확보하기 위해 LNG 수입국들은 다양한 수출국과의 계약 체결을 확대할 가능성이 있습니다. 또한, 새로운 LNG 생산 시설의 건설이 가속화될 수 있으며, 이는 새로운 투자 기회를 창출할 것입니다. 그러나, 이러한 변화는 동시에 새로운 리스크를 동반할 수 있습니다. 예를 들어, 새로운 생산 시설의 건설 비용과 시간, 정치적 안정성 등이 고려되어야 합니다.

결론

중동 분쟁은 아시아 태평양 지역의 전력 시장에 중요한 영향을 미치고 있습니다. 특히, LNG 공급 안정성과 유가 가격 변동성은 전력 생산 비용과 에너지 기업들의 수익성에 직접적인 영향을 미칩니다. 향후, 투자자는 분쟁의 장기적 영향을 고려하여 전략을 수립해야 합니다. 또한, 새로운 LNG 생산 시설의 건설과 공급 다각화에 대한 주목이 높아질 전망입니다.

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원문 링크: https://news.google.com/rss/articles/CBMi1AFBVV95cUxOZGpRZHY5Slg3NU95TzN4Y2JNYzJtQzAwTGh0bGpSaHp1QkpyMmdPUEYtYW0yYWZOVmZVWWsyZDhUdTlvSzNuYUZfQnFSYW1VQzhBVS1EU2tIX25NQkRjdmVsS1hDa2padlVlaUd4VlN0Vk9Bb3dBYkhlNW1Tc0hWbHpVWDM5c21zVkZ3RnFxWmhjZ3lSMG90ZTRyMHAxRmxHemtPNXhHX1pFMkhDdl9KaUxBQ001cFp2cTNCOGJlZlp4SFlmWEdETVRJU2lfanBmT1htMA?oc=5

Impact of the Middle East conflict on Asia-Pacific power markets | Japan | Global law firm - Norton Rose Fulbright

This briefing considers some of the impacts of the current Middle East conflict on energy markets across the Asia-Pacific region.

Around 20% of global LNG and 25% of seaborne oil transits the Strait of Hormuz. Qatar supplies roughly 20% of global LNG, meaning any disruption to its production facilities will significantly affect countries that are reliant on imported LNG for domestic power consumption and translate directly into higher power generation costs.

The Iranian strikes on Ras Laffan in March 2026 are reported to have affected approximately 17% of Qatar’s LNG export capacity. As of mid-May 2026, gas production from the North Field continues and Qatar’s overland pipeline to the UAE and Oman remains operational. The first LNG cargo has transited the Strait following the ceasefire, although recovery is expected to take several months for undamaged facilities and considerably longer for those that sustained significant damage. Overland capacity is unlikely to materially offset Qatar’s seaborne LNG volumes.

While the conflict impacts both oil and LNG, oil importers can diversify supplies more easily than LNG importers due to oil’s liquidity and short-term trading. Despite its diversity of supply, the macro impact of the closure of the Strait of Hormuz on global oil supply has short-term, and potentially medium-term, global price implications, with Brent crude oil prices (for front-month forward delivery) already 40-50% above pre-conflict levels. LNG is less fungible because differences in calorific value can impact terminal compatibility. Due to this key characteristic, despite growth in spot trading, LNG supply remains largely dependent on long-term offtake contracts.

The conflict has refocused attention on the production and supply of LNG as having significant geopolitical and energy security implications.

Critically, in the medium to long term, the conflict may cause buyers to reassess the balance between price and the security of LNG supply. For example, Australian LNG, despite its higher cost base, has the advantage of a shorter and more predictable shipping route to South and South-East Asia (although it is also important to note that most production from existing projects is already contracted).

It is anticipated that coal will be critical for short-term energy security. Over the longer term, renewables, storage, and demand response will become increasingly important hedges against energy market disruptions.

Australia: Australia occupies a unique dual position in the current conflict: as one of the world’s largest LNG exporters, it is a critical supply diversification option for Asian buyers, yet it is simultaneously exposed to global refined fuel disruptions given its geographic isolation and limited domestic refining capacity. Since March 2026, demand for Australian LNG spot cargoes has surged, particularly from South Korea and Japan, but Australia’s existing facilities are already operating at near-full capacity, leaving limited room to materially increase exports in the short term. Australia has moved rapidly to strengthen bilateral energy security arrangements, issuing joint statements with the Republic of Korea (30 April 2026), signing energy resource security agreements with Japan (3 May 2026), and pursuing fuel/LNG swap arrangements with Malaysia, Brunei, and Singapore. On 7 May 2026, the Australian Government also announced a Domestic Gas Reservation Mechanism, requiring east coast LNG exporters to reserve 20 per cent of export volumes for the domestic market from 1 July 2027. Bangladesh: Bangladesh is highly dependent on LNG for power generation but has few long-term supply contracts. This exposure to LNG price volatility and shipping uncertainty is likely to sharply increase power generation costs, raising subsidy requirements and increasing the risk of load-shedding and reduced industrial supply. Bangladesh’s limited ability to absorb spot market volatility is also likely to constrain dispatch of gas-fired generation, increasing reliance on oil-based fuels such as diesel and heavy fuel oil which are nevertheless also subject to price increases. To address this, the Bangladesh government has shifted to direct procurement of oil and LNG cargoes, including emergency purchases from non-traditional suppliers (e.g. Kazakhstan, Singapore), besides exploring additional sourcing from Africa and other regions to mitigate supply disruptions. It has also significantly expanded long-term LNG procurement, signing multiple 10–15-year SPAs with Middle East and US-based suppliers. While the shift toward long-term LNG contracts and supply diversification should improve medium-term supply security and price visibility, near-term risks of elevated generation costs, fiscal pressure, and intermittent load-shedding remain significant. India: Natural gas only accounts for around 5-6% of India’s primary energy mix. While LNG is not used for baseload power generation, it plays an important role in urban transport through compressed natural gas and in households through piped gas for cooking and water heating. LNG also provides critical feedstock for fertilisers, refineries, and petrochemical industries, where domestic gas reserves are insufficient. On 9 March 2026, India’s Ministry of Petroleum and Natural Gas issued a Natural Gas (Supply Regulation) Order, 2026. The Order establishes an allocation framework to ensure continuity of natural gas supply to essential sectors – principally fertilisers and city gas distribution – and is directed at strengthening food security and urban energy access. Policymakers can be expected to further expand strategic reserves, diversify crude oil supplies, and improve refinery flexibility, in addition to accelerating the development of additional renewables, storage, and demand response, in order to reduce exposure to imported fuels. Indonesia: Indonesia’s power generation is dominated by coal, which provides a measure of domestic energy security amid global supply disruptions. The country is also a net LNG exporter, and domestic power generation has limited reliance on LNG imports, as gas is primarily allocated to industrial use and export commitments. Since the escalation of the Middle East conflict and disruption to shipping through the Strait of Hormuz, the Indonesian government has positioned coal as a short-term energy security backstop, raising production quotas and prioritising coal availability for the power sector – to insulate domestic generation from oil and gas price volatility. As a major coal exporter, Indonesia may also benefit from rising international demand for thermal coal as gas-importing countries increase their reliance on coal-fired generation. While Indonesia faces wider macroeconomic exposure to higher energy prices, its power sector is expected to remain largely insulated from the conflict, given the dominance of coal and limited LNG import dependence, which together provide greater resilience than regional peers enjoy. Indonesia is simultaneously accelerating its transition to renewable energy while seeking to attract investment in upstream oil and gas, critical minerals and rare earth mining. Japan: Japan relies heavily on gas-fired power generation, with LNG accounting for roughly 30-40% of its electricity mix. It is one of the world’s biggest LNG importers with supplies sourced from a diversified portfolio including Australia, Qatar, the United States and South-East Asia. Price volatility therefore feeds directly into generation costs and electricity tariffs. Japan has sought to mitigate supply risk through contractual diversification, trading flexibility, and strategic LNG buffer stocks. In March 2026, the Ministry of Economy, Trade and Industry suspended the 50% utilisation cap on inefficient coal plants for one year to conserve LNG. More broadly, Japan is accelerating the restart of nuclear capacity, expanding renewables, and developing ammonia and hydrogen co-firing to diversify its power mix. Malaysia : Around 28% of Malaysia’s power generation is fuelled by natural gas, most of which is domestically sourced. Malaysia is a major natural gas producer and a top-five global LNG exporter, with LNG imports used only to backfill declining output from mature gas fields. As a result, LNG imports are not a dominant feature of the power system. Malaysia is expected to suffer limited physical supply disruption, although it may be subjected to inflationary pressure from oil markets. The conflict may also redirect global LNG demand toward Malaysian supply, bolstering export revenues – as with Indonesia – but sharpening the tension between export optimisation and domestic energy security. Pakistan: Pakistan is exceptionally vulnerable to Middle East LNG disruptions because of extreme supplier concentration and low system flexibility. Qatar and UAE together supply roughly 99% of Pakistan’s LNG imports, which are mostly for power generation, fertiliser production and industrial use. LNG accounts for about 30% of Pakistan’s total gas supply. The disruption in supply has prompted the Pakistan government to curtail gas supplies and increase dispatch from coal, hydropower and nuclear generation plants. The government has also adopted a strategy comprising load-shedding, demand-side conservation measures, tariff adjustments, and the maximisation of output from non-gas generation sources. Philippines: Natural gas constitutes around 14-21% of the Philippines’ power generation mix, with coal remaining dominant. As domestic gas reserves decline, the country is increasingly reliant on LNG to backfill supply and preserve its gas-fired generation fleet. The current conflict has exposed the Philippines’ structural vulnerability to global energy shocks, driven by its heavy reliance on imported oil, coal and LNG, and has triggered an unusually interventionist policy response in the power sector. In March 2026, the government declared a national energy emergency and temporarily suspended trading on the Wholesale Electricity Spot Market (WESM) after electricity prices spiked in response to higher fuel costs, replacing market-based pricing with an administered regime intended to stabilise consumer bills and preserve fuel inventories. While these interventions are designed to cushion consumers from short-term price volatility, they underscore the Philippine power market’s sensitivity to geopolitical disruption and reinforce the strategic case for accelerating domestic renewable generation and transmission infrastructure. In particular, the crisis has sharpened the policy focus on grid resilience and fuel diversification, strengthening the long-term investment case for renewables and enabling transmission projects, even as near-term price controls and regulatory intervention may complicate the assessment of merchant risk and market-based revenue exposure. Singapore: Singapore relies heavily on gas-based power, which accounts for close to 95% of generation, and is largely dependent on imported LNG. Around 57% of gas imports are LNG, with the balance supplied by piped natural gas from Malaysia and Indonesia. To manage supply risk and diversify imports, Singapore commissioned an LNG terminal in 2013 and is developing a second terminal to expand regasification capacity later this decade. LNG is sourced from Australia, Qatar, the United States and Equatorial Guinea, with Singapore deliberately maintaining diverse sources to avoid over-exposure to any single region. While this mitigates single-source supply risk, Singapore remains exposed to global LNG and oil prices, strengthening the case for greater diversification of the power generation mix. The government’s current plans to issue licences to the private sector for 4-6GW of low-carbon, non-intermittent power imports, and to increase the share of green molecules in generation, reflect this direction. South Korea: Much like Japan, South Korea relies heavily on gas-fired power generation, with LNG from a diversified portfolio (Qatar, Australia, and the United States, among others) accounting for a substantial share of its electricity mix alongside coal and nuclear. To manage supply issues arising from the Middle East conflict, South Korea has adopted a range of measures, including maintaining diversified long-term contracts, pursuing spot market flexibility, and leveraging its nuclear fleet to provide baseload stability. In March 2026, the South Korean government issued a “resource security crisis alert” contemplating the release of LNG from stockpiles, the securing of alternate cargoes, and stricter supervision of fuel markets. Sri Lanka: Following the 2022-23 economic crisis, Sri Lanka’s power sector is recovering with IMF support but has not yet achieved full resilience. Electricity generation remains heavily reliant on diesel and heavy fuel oil, with hydropower providing important but seasonally constrained supply and coal serving as baseload generation. While Sri Lanka had been pursuing the development of LNG importation infrastructure, and LNG to power plants, prior to the 2022-23 economic crisis, LNG is not yet critical to the energy mix. However, higher global oil prices will directly raise generation costs and tariffs, and place renewed pressure on foreign exchange reserves as they are being rebuilt. Thailand: Gas-based power is central to Thailand’s generation mix (around two-thirds of generation), with a growing reliance on imported LNG supplied through a highly centralised LNG-to-power model. Imported LNG accounts for around a quarter of Thailand’s gas demand, sourced predominantly from Qatar and Australia, with additional volumes from Malaysia, the United States and Oman. This diversification of supply sources provides a degree of insulation against single-country disruption. LNG import, regasification, and transmission are managed at the system level, meaning procurement is not decentralised and individual generators do not compete for supply. As a result, any LNG shortage must be absorbed by the power utility (i.e., the Electricity Generating Authority of Thailand) and the government through fuel substitution, demand prioritisation, price pass-through and policy intervention. LNG price volatility creates fiscal strain, whether through higher power tariffs passed on to consumers or increased subsidy costs borne by government. In the context of the current conflict, this reinforces the case both for diversifying LNG supply sources and for accelerating the integration of renewable generation, energy storage and demand-response mechanisms into Thailand’s power mix. Vietnam: LNG-based power supply represents only around 2% of installed generation capacity, with most gas-fired generation supplied by domestic natural gas, and coal and hydropower dominating the mix. While higher coal prices and shipping costs could have an indirect impact, the power system is largely insulated from an LNG shock. The current conflict strengthens Vietnam’s case for domestic renewables and a cautious LNG-to-power rollout.

We expect that the following priorities will feature in discussions among policymakers and market participants in South Asia, South-East Asia and Australia, as they look to address the impact resulting from the current conflict and also future proof their domestic power and energy systems: Accelerating renewables: Reducing marginal dependence on imported fuels by accelerating renewables and storage deployment to displace marginal gas generation (in addition to meeting demand growth) and prioritising renewables that can be built in 12–36 months (e.g. utility-scale solar, wind farms and commercial & industrial rooftop solar). This priority is also evident in the Australian Government’s announcement that it would expand its Capacity Investment Scheme (a Commonwealth underwriting mechanism designed to incentivise investment in new renewable generation and storage capacity) from 32GW to 40GW and commit AUD 179.9 million to accelerate environmental approvals for energy projects. Rebalancing the generation mix: Redesigning dispatch rules so that gas plants run for balancing and peaks (not constant baseload) and are compensated for availability and flexibility (not energy volume). Expanding operating reserves: Increasing spinning and non spinning reserve requirements to ensure the grid can instantaneously or quickly respond to unexpected supply shocks. Rethinking fuel stockpiles: Expanding strategic fuel stocks for power generation, not just transport fuels. Power plants require specific fuels, and reserves maintained for transport may not necessarily be compatible with power generating assets. As well, these stockpiles may not necessarily be physically located at or near power plants. Strategic planning is required to ring-fence supplies for power generation. LNG-exporting in South-East Asia may require policies to ensure that domestic gas needs continue to be met, even where supply shortages and higher global prices might otherwise incentivise increased exports. Australia – which, despite being an LNG exporter, holds only 20-32 days of refined fuel reserves owing to limited domestic refining capacity – has responded with a substantial fiscal intervention. In its Federal Budget for 2026-27, the Australian Government announced a AUD 14.8 billion “Strengthening Australia’s Fuel Resilience” package, which includes a AUD 3.2 billion government-controlled Fuel Security Reserve (holding approximately 1 billion litres of diesel and jet fuel), an expansion of the Minimum Stockholding Obligation to 50 days of supply, and a AUD 7.5 billion Fuel and Fertiliser Security Facility providing loans, guarantees and price support to expand domestic fuel storage capacity. Cross-border power export/import: There must be greater emphasis on improving regional power transfers and internal transmission so that shortages are shared, not localised. South Asia and South East Asia can share shortages if they build selective, strategic interconnections that allow markets and system operators to move power during periods of stress.

As mentioned above, LNG markets are less fungible than oil. Declaring diversification goals does not mean that alternatives exist in reality over the short term. A case in point is China, which has limited its Middle East oil exposure at around 50% but is reliant on Qatar for up to one-third of its LNG imports. China is therefore exposed to export hub concentration and transit risk through the Strait of Hormuz. Accordingly, in a supply crisis, new LNG suppliers may not be the first recourse. It is more likely that countries will look to mitigate risk by drawing on LNG stockpiles, limiting industrial use, and increasing reliance on coal in the case of power generation. Alternatives for South Asian and South-East Asian LNG buyers exist: US LNG has a large and expanding supply base and can offer flexible contracts at competitive pricing, which are destination free and enable resale, although long shipping distances and exposure to export restrictions and trade policy would need to be considered. US LNG cargoes to Asia would need to transit through the Panama Canal, which carries its own congestion risk. Australian LNG has geographic proximity to Asia. Australia is an established, reliable supplier of LNG with a long operational track record. On the other hand, South Asian and South-East Asian buyers would need to find capacity that remains uncontracted, and the cost base for Australian LNG may be higher than US LNG. South-East Asia has Papua New Guinea, Indonesia, Malaysia, and Brunei as LNG exporters which offer regional proximity, existing LNG infrastructure and trading history, as well as familiarity with South Asian and South-East Asian buyers. On the other hand, new buyers would need to confront limited spare capacity, declining production in some legacy fields and competition with domestic demand. West Coast LNG in Canada is also emerging as an option, which would have direct access across the Pacific Ocean to Asia (no canal dependency), and would offer a stable political and regulatory environment. This option, however, is still ramping up and near-term volumes are limited. South Asian and South-East Asian buyers may therefore see Canada more as an option for future diversification rather than an immediate alternative to supply from the Middle East.

Accordingly, in a supply crisis, new LNG suppliers may not be the first recourse. It is more likely that countries will look to mitigate risk by drawing on LNG stockpiles, limiting industrial use, and increasing reliance on coal in the case of power generation.

Alternatives for South Asian and South-East Asian LNG buyers exist:

Force majeure declarations are cascading through LNG and oil supply chains. Market participants should urgently review contractual provisions, satisfy notice requirements, mitigate losses, and document disruptions contemporaneously. An invalid force majeure declaration may constitute a repudiatory breach, with potentially substantial damages exposure. Developments in the Middle East may increase the scope for commercial disputes for participants in the oil and LNG markets over coming months. Claims involving political force majeure are likely to be the most prominent, and are addressed in more detail below. More broadly, however, commercial parties should remain alert to the full range of contractual mechanisms that may be engaged by the current disruption, and to the importance of acting promptly to preserve their rights. The conflict also has wider implications for supply contracts. Over decades, the scale and reliability of Middle Eastern LNG producers have strengthened their bargaining position, securing long-term contracts with oil-linked pricing and strict destination restrictions. It remains uncertain whether such restrictions will be sustainable if the geopolitical risks associated with supply from those producers continue to intensify. In parallel, the sanctions framework that has reshaped energy markets since Russia’s invasion of Ukraine in 2022 is likely to undergo some recalibration. By way of example, the United States has announced a 30-day waiver of sanctions on Russian oil imports into India, characterising it as a one-off measure to ease supply pressures. At the same time, industry participants should anticipate continued and intensifying enforcement action against Iran’s “shadow fleet” of oil tankers and intermediaries, as well as against Asian refineries that have continued to purchase Iranian oil. The practical effect of these measures is, however, complicated by China’s May 2026 blocking order which prohibits entities within Chinese jurisdiction from complying with US sanctions on five refineries. As commercial disputes begin to emerge, market participants should take the following steps: Review relevant clauses: Revisit contractual provisions addressing force majeure, material adverse change, war risks, and destination restrictions, including any relevant carve-outs or qualifications. Confirm notification requirements: Review notice provisions to identify applicable deadlines and any prescribed form, to avoid claims being time-barred or deemed waived. Counterparties should be notified promptly once a basis for a claim is identified. Mitigate losses: Continue to perform contractual obligations where possible and take reasonable steps to mitigate loss or damage. Losses should be identified, estimated, and quantified as soon as practicable. Keep detailed records: Keep a comprehensive record of communications, key decisions, and losses incurred, to support any future claims or proceedings. Monitor sanctions landscape: Regularly update sanctions compliance processes, particularly those relating to Russia and Iran, to ensure continued compliance.

Developments in the Middle East may increase the scope for commercial disputes for participants in the oil and LNG markets over coming months.

Claims involving political force majeure are likely to be the most prominent, and are addressed in more detail below. More broadly, however, commercial parties should remain alert to the full range of contractual mechanisms that may be engaged by the current disruption, and to the importance of acting promptly to preserve their rights.

The conflict also has wider implications for supply contracts. Over decades, the scale and reliability of Middle Eastern LNG producers have strengthened their bargaining position, securing long-term contracts with oil-linked pricing and strict destination restrictions. It remains uncertain whether such restrictions will be sustainable if the geopolitical risks associated with supply from those producers continue to intensify.

In parallel, the sanctions framework that has reshaped energy markets since Russia’s invasion of Ukraine in 2022 is likely to undergo some recalibration. By way of example, the United States has announced a 30-day waiver of sanctions on Russian oil imports into India, characterising it as a one-off measure to ease supply pressures. At the same time, industry participants should anticipate continued and intensifying enforcement action against Iran’s “shadow fleet” of oil tankers and intermediaries, as well as against Asian refineries that have continued to purchase Iranian oil. The practical effect of these measures is, however, complicated by China’s May 2026 blocking order which prohibits entities within Chinese jurisdiction from complying with US sanctions on five refineries.

As commercial disputes begin to emerge, market participants should take the following steps:

Force majeure has moved to the centre of commercial activity as declarations cascade through supply chains. Because many clauses operate in tiers, declarations have been staggered – escalating as the disruption has affected more routes and persisted longer than initially anticipated. A major national LNG producer has confirmed that a significant proportion of its export capacity will be offline for three to five years, necessitating extended force majeure notices alongside short-term declarations. Downstream, a Gulf state refiner has declared force majeure on group operations following an attack on key refining infrastructure. International traders have followed suit, declaring force majeure to downstream customers on affected LNG cargoes. Market participants should, however, be cautious about relying on force majeure to excuse non-performance. Courts and arbitral tribunals tend to interpret force majeure clauses narrowly, following the precise wording to determine whether a specific event has genuinely prevented performance as defined by the contract. Post-pandemic case law confirms that courts rarely accept generalised disruption claims and will closely scrutinise direct causation and the adequacy of mitigation efforts. The dynamic nature of the Hormuz crisis compounds these difficulties. Where clauses require “reasonable” or “best” efforts to overcome the event, additional expense alone is unlikely to constitute prevention of performance, and force majeure is unlikely to apply if re-routing remains feasible. Parties also risk being overtaken by events: the geopolitical realities governing Strait access have shifted from initial closure of all traffic, to an Iranian-enforced toll regime, to a subsequent double blockade. As the threshold for impossibility moves with each development, courts and tribunals will assess the validity of force majeure declarations against the information available to the declaring party at the relevant time, the alternative performance options open to it, and its documentary record of mitigation steps. Interactions between force majeure clauses and local laws – particularly in Gulf states – can produce unpredictable outcomes that go beyond common law interpretations of force majeure. Saudi Arabia, for example, has a statutory regime that operates alongside contractual provisions, and Shariah law considerations may also arise in emergency situations. Parties should therefore identify the governing law of each affected contract at an early stage and determine whether local statutory force majeure or frustration regimes can override or supplement the contractual position. The consequences of an invalid force majeure declaration are significant. A party that invokes force majeure without a proper basis may be treated as having committed a repudiatory breach, entitling the counterparty to terminate and claim damages for the full value of lost performance. In long-term energy and construction contracts, this exposure can be substantial – which explains why force majeure has often been declared as a last resort rather than a pre-emptive attempt to discharge liabilities. Previous disruptions to transit routes in the Red Sea and Strait of Hormuz illustrate this pattern, with ship-owners relying on war‑risk and safe‑port clauses to limit exposure in the first instance. Alongside the general preparatory steps outlined above, market participants seeking to rely on or respond to force majeure clauses should take the following precautionary steps: Confirm clause wording: Review the scope and precise wording of force majeure clauses in each affected contract to confirm whether conflict, sanctions, or other war-related disruptions qualify as force majeure events, and whether notice requirements have been satisfied. Establish governing law: Identify the governing law of each affected contract and engage local counsel as needed. Consider broader contractual consequences: Assess whether force majeure declarations will trigger additional counterparty rights – such as termination, suspension of supply, or obligations to implement contingency measures – and whether the resulting liabilities outweigh the short-term benefits of relief. Document contemporaneously: Maintain real-time records of disruptions, mitigation steps, counterparty communications, and cost impacts. Ensure that the information available to decision-makers at each stage is captured and preserved. Engage early: Early engagement with counterparties to negotiate interim arrangements or waivers is usually preferable to formal proceedings. Given the evolving situation, commercial resolutions are typically more effective than litigation at containing legal and financial risk.

Market participants should, however, be cautious about relying on force majeure to excuse non-performance. Courts and arbitral tribunals tend to interpret force majeure clauses narrowly, following the precise wording to determine whether a specific event has genuinely prevented performance as defined by the contract. Post-pandemic case law confirms that courts rarely accept generalised disruption claims and will closely scrutinise direct causation and the adequacy of mitigation efforts.

The dynamic nature of the Hormuz crisis compounds these difficulties. Where clauses require “reasonable” or “best” efforts to overcome the event, additional expense alone is unlikely to constitute prevention of performance, and force majeure is unlikely to apply if re-routing remains feasible. Parties also risk being overtaken by events: the geopolitical realities governing Strait access have shifted from initial closure of all traffic, to an Iranian-enforced toll regime, to a subsequent double blockade. As the threshold for impossibility moves with each development, courts and tribunals will assess the validity of force majeure declarations against the information available to the declaring party at the relevant time, the alternative performance options open to it, and its documentary record of mitigation steps.

Interactions between force majeure clauses and local laws – particularly in Gulf states – can produce unpredictable outcomes that go beyond common law interpretations of force majeure. Saudi Arabia, for example, has a statutory regime that operates alongside contractual provisions, and Shariah law considerations may also arise in emergency situations. Parties should therefore identify the governing law of each affected contract at an early stage and determine whether local statutory force majeure or frustration regimes can override or supplement the contractual position.

The consequences of an invalid force majeure declaration are significant. A party that invokes force majeure without a proper basis may be treated as having committed a repudiatory breach, entitling the counterparty to terminate and claim damages for the full value of lost performance. In long-term energy and construction contracts, this exposure can be substantial – which explains why force majeure has often been declared as a last resort rather than a pre-emptive attempt to discharge liabilities. Previous disruptions to transit routes in the Red Sea and Strait of Hormuz illustrate this pattern, with ship-owners relying on war‑risk and safe‑port clauses to limit exposure in the first instance.

Alongside the general preparatory steps outlined above, market participants seeking to rely on or respond to force majeure clauses should take the following precautionary steps:

The Middle East conflict has exposed deep structural vulnerabilities in Asia-Pacific power markets. The Iranian strikes on Ras Laffan and ongoing disruption to Strait of Hormuz transit have delivered an acute supply shock to LNG-dependent economies across South and South-East Asia in particular, driving up power generation costs, straining public finances, and prompting emergency policy interventions from Bangladesh to the Philippines. For LNG exporters such as Australia, Malaysia, and Indonesia, the crisis has simultaneously created export opportunities and sharpened the tension between domestic energy security and international supply commitments. The conflict has also reinforced several longer-term structural trends. Across the region, policymakers are accelerating renewables and storage deployment, expanding strategic fuel stockpiles, and redesigning generation dispatch to reduce marginal dependence on imported gas. Force majeure declarations are cascading through LNG and oil supply chains, and the legal and commercial frameworks governing long-term supply contracts – including oil-linked pricing and destination restrictions – are coming under sustained pressure. Geopolitical risk has re-emerged as a central variable in energy investment and procurement decisions. * With thanks to Andrew Digges, Ben Carrozzi, Wira Saputra, James Nicholls, and Suwen Fang for their assistance in preparing this article.

Source: https://news.google.com/rss/articles/CBMi1AFBVV95cUxOZGpRZHY5Slg3NU95TzN4Y2JNYzJtQzAwTGh0bGpSaHp1QkpyMmdPUEYtYW0yYWZOVmZVWWsyZDhUdTlvSzNuYUZfQnFSYW1VQzhBVS1EU2tIX25NQkRjdmVsS1hDa2padlVlaUd4VlN0Vk9Bb3dBYkhlNW1Tc0hWbHpVWDM5c21zVkZ3RnFxWmhjZ3lSMG90ZTRyMHAxRmxHemtPNXhHX1pFMkhDdl9KaUxBQ001cFp2cTNCOGJlZlp4SFlmWEdETVRJU2lfanBmT1htMA?oc=5